Questar Q1 2007 Earnings Call Transcript

Apr.26.07 | About: Questar Corporation (STR)
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Questar Corporation (NYSE:STR)

Q1 2007 Earnings Call

April 26, 2007 9:30 am ET

Executives

Steve Parks - VP and CFO

Keith Rattie - Chairman and CEO

Chuck Stanley - CEO of Questar Market Resources

Analysts

Shneur Gershuni - UBS

Carl Kirst - Credit Suisse

Sam Brothwell - Wachovia

Carol Coale - FMH Capital

Mike Heim - A. G. Edwards

Carl Brown - Cramer Rosenthal

John Mansfield - SAC Capital

Presentation

Operator

Good morning. My name is Elizabeth, and I will be your conference operator today. At this time, I would like to welcome everyone to the Questar First Quarter 2007 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). Thank you.

I would now like to turn the conference call over to Mr. Steve Parks, Senior Vice President and Chief Financial Officer. Please go ahead sir.

Steve Parks

Thanks Elizabeth. Good morning and welcome to Questar's first quarter 2007 conference call. I will briefly summarize our first quarter results and then turn the microphone over to Keith Rattie, our Chairman and CEO. Keith will comment on our revised guidance for 2007 and give you an update on our key projects. After Keith, we will take your questions.

Others members of Questar's management team are here to answer your questions, including Chuck Stanley, President and CEO of Questar Market Resources; Allan Bradley, President and CEO of Questar Pipeline; and Alan Allred, President and CEO of Questar Gas.

I must remind you that our remarks this morning will contain forward-looking statements about the future operations and expectations of Questar. 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 may vary significantly from our current expectations and projections due to a variety of factors that are described in our 10-K filings with the Securities and Exchange Commission.

Now, here is the summary of our first quarter results. Questar net income grew 10% in the first quarter to $151.1 million or $1.72 per diluted share, compared to $137.2 million or $1.57 per share a year ago.

Our Market Resources subsidiary grew net income 16% to $109.5 million in the first quarter 2007. Our four Market Resources segments, Questar E&P, Wexpro, Gas Management, and Energy Trading, delivered double-digit net income growth in the first quarter.

Questar E&P grew net income $6.7 million or 10% including a $7.4 million of net mark-to-market gains on NYMEX/Rockies natural gas basis swaps.

Questar E&P grew production 8% to 34.9 Bcfe, the average costs structure increased 15%. And realized prices for natural gas, crude oil and NGL were essentially flat.

Wexpro grew net income 16% driven by a 23% increase in investment base over the past 12 months.

Gas Management grew net-income 28% driven by higher third-party gathering volume.

Energy Trading more than doubled net income, driven by higher storage trading margins. Questar Pipeline, our interstate pipeline in storage business earned $11.2 million in the first quarter 2007 down 7% from 2006.

Operating, depreciation and interest expenses all increased once we completed construction and put the Overthrust pipeline expansion and service at the end of the last year. Questar pipeline began collecting revenues from this project, a year earlier. And we began service at an interim delivery point.

Questar Gas, our retail gas distribution utility, reported first quarter 2007 net income of $29.1 million down 1% from a year ago due to a June 2006 rate reduction.

Questar Gas now serves about 861,000 homes and businesses up 3.2% from a year ago.

For More details on the first quarter, you can get a copy of our earnings release plus the latest version of our Investor Relations presentation on our website at questar.com.

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

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Keith Rattie

Well, good morning everyone. We are off to a pretty good start in 2007. As Steve noted, all four segments in our Market Resources Group posted double-digit net income growth for the first quarter and that offset lower earnings from our regulated businesses.

As we talk about all the time, we focus on returns, market resources, continues to earn solid returns on capital, posting 21.6% ROA for the trailing 12 month period.

Questar E&P grew production 8% to 34.9 billion cubic feet equivalent for the quarter and that was driven by Pinedale. And our Elm Grove tight-gas play in Northwest Louisiana.

Note also that the commodity price and Rockies basis hedges we've put in place over the last few years boosted pre-tax income by $42.9 million that offset a 21% decline in the average sales price of natural gas and oil equivalent production compared to a year ago.

Note also the table at the end of our release; we've added hedges in '08, '09 and 2010 as we've explained in the past. We used fixed-price swaps to hedge equity production, a process is analogous to dollar cost averaging, when prices are at or above levels we consider attractive. We hedged to lock in returns and to protect against the down turning commodity prices a widening of basis or both.

When we hedge, we try to be agnostic about the direction of the market. We try to keep our focus on returns.

Note that Questar E&Ps cost structures, speaking of returns, was up 15% in the first quarter, driven by a 32% jump in our DD&A rate from a year ago.

DD&A expense is of course volume-weighted, and more of our production today is coming from recently drilled wells while volumes from older lower cost fields comprise an ever shrinking share of the total. Let me assure you that we are focused on this, as we've said in the past, one of our challenges and our intent is to manage the trade-off between growth and cost to ensure that our cost remain among the lowest in the industry.

We hope you noticed that our mid-continent team grew production 9% in the first quarter of '07 compared to a year ago, that comes on the hills of a 21% growth in 2006.

The primary story here is our ongoing two rig development program at Elm Grove, but we are also getting good results from our Granite Wash play in the Texas Panhandle.

Wexpro's investment base grew 23% from a year ago. In our IR presentation, we highlight Wexpro's $1.1 billion inventory of identified risk growth potential on the Rockies properties that are covered by the 1981 Wexpro agreement. As you know, Wexpro earns a 19% to 20% after-tax unlevered return on that investment base.

Wexpro produced 10.6 billion cubic feet equivalent of cost-of-service gas in this quarter for our utility, Questar Gas.

Now, with the Gas Management, our Rockies gas gathering and processing business grew net income 28% in the quarter, and that was driven by a 43% jump in third-party gathering volumes.

The bottom line here is that Gas Management is executing the hub strategy, which we've talked about in the past. Under that strategy, we dedicate production volumes from our E&P businesses which helps underwrite the initial investment in gathering and processing facilities, in our core Rockies producing area. Once we get critical mass, we reach out and capture third-party business.

With the first quarter in the books, we now have better visibility in rest of this year. And therefore, we've raised our production guidance and raised the bottom end of the range on our EPS estimates for the year. We now expect natural gas and oil equivalent production to range from 135 to 138 billion cubic feet equivalent, that's up 2 Bcfe from prior guidance of 133 to 135.

I note that we now expect '07 net income to range from $5.20 to $5.35 per diluted share. That compares to previous guidance of $5.15 to $5.35, and we put a table in our earnings release to reconcile these estimates.

Please note, our revised earnings guidance, assumes a much wider Rockies base, than has been assumed in the guidance we gave in February. We now assume that the Rockies to NYMEX basis differential will average $3.25 per MMBtu for the remainder of this year. That compares to the $2 per MMBtu assumption we used in our earlier guidance.

Also note that we now expect to complete 48 to 52 wells of Pinedale this year compared to our previous estimate of 45 to 48. Our Pinedale team, and when I say Pinedale team. We are also talking about our contractors, continues their relentless drive for improvement.

We are going to come out of the winter drilling season with 34 wells drilled and cased ready to complete. That's one more than a year ago even though we had one less rig operating this winter.

Our team is really executing well. We averaged 35 days from spud to TD on wells drilled this winter. That's down from an average of 42 days last year. In fact, we've now consistently broken the 30 day barrier. We drilled five of those 34 wells in less than 30 days and keep in mind, that we are drilling directional wells with major depths of nearly 14,300 feet. That's about 1,000 feet deeper than wells being drilled by other operators in this play.

If we stay on this track, our average cost to drill complete and connect to Pinedale well this year should be lower than the 5.8 million per well which we averaged last year.

I would like to stress that while driving down cost. Our Pinedale team has also kept a keen focus on safety. This is not coincidental. Efficiency and safety go hand-in-hand. You can't have one without the other.

More good news from Pinedale; we should get an earlier start with our summer drilling program this year. Once we move the drilling rigs, we will start completing these winter wells that should get Pinedale production turned up in the second quarter, a bit earlier than years past. We are currently planning an eight rig program at Pinedale this summer.

Just a quick update on the Pinedale SEIS, the BLM public-comment period ended on April 6. We expect the Record of Decision, the ROD, sometime in the third quarter.

We are optimistic. We think that Questar and the other Pinedale operators have made the case. The concentrated development is far superior to the status quo with concentrated development; we will leave more acreage open for wildlife. We’ll start reclaiming disturbed areas, several years sooner than we would have under the status quo.

By 2010, with year round drilling and completions, we should be drilling over a 100 wells per year on our operated acreage. Of course, that's important because we have over 700 wells yet to drill on 10 acre density. And potentially, up to 13,000 total locations to drill on a mix of 5 and 10 acre density.

Let me turn now to our emerging shale gas play in the Vermillion Basin in which the usual caveat is one well does not a play make.

The Trail 13C, the 16th new well we’ve drilled on our 146,000 net acres in this play may have changed the paradigm and moved just closer to cracking the code. Trail 13C, you recall is on the flank of the trail structure on the Northern part of our Vermillion Basin acreage. It has now produced about 530 million cubic feet of gas in the first 70 days on production, that's roughly five times the average from the previous wells over a comparable period. And Trail 13C today is making about 7.7 million cubic feet per day with a flowing casing pressure of around 1200 pounds.

Now, obviously this rate will continue to decline, but folks this is a strong well. So the key question is Why so much better? And can we repeat these results? Well, we think we've drilled into a natural fracture network with a Trail 13C, we now have to figure out how to identify map and then target natural fractures, and target them most likely with horizontal well. Speaking of horizontal wells last week, we completed our first horizontal well, the Canyon Creek 79H, it's located on the flank of the Canyon Creek structure.

Our technical team predicted that this well would intersect our natural fracture network and it appears they were right. We encountered several fracture swarms with strong gas shows while drilling the horizontal leg in the middle of the Baxter.

In fact, the last fracture set kicked us so hard that we decided not to press our luck. We stopped drilling and cased the well with just a 1000-foot horizontal leg, that’s shorter than the 3000 feet we planned. But we think it's adequate for an initial test to see if horizontal drilling leads to better well performance.

We've completed the well, we pumped only four frac stages in the horizontal legs and drilled out the frac plugs and started flowing the sales about five days ago.

The Canyon Creek 79H averaged 5 million cubic feet per day in its first five days online, that's about twice the average initial rate we've gotten from the Baxter section, the Baxter shale and vertical wells we've drilled in the past excluding that Trial 13C well.

Now, let me stress a few important points. Most important is that we are still on the front-end of a very steep learning curve with our Vermillion Basin play. 79H has been on production only five days, its still way too early to draw conclusions about horizontal wells and horizontal drilling in the Baxter shale.

The initial results are encouraging, but we are going to have to drill more wells to validate our belief that we can increase rate recovery and returns with horizontal drilling. Our well costs are still too high. We still have a lot to learn about how to drill and complete horizontal wells. But, we are a lot further up the learning curve today than we were just a few months ago. We now know that the Baxter shale is productive across most of our Vermillion acreage. We now know that there are big targets in the Baxter that can produce at much higher rates than we've seen in the past. And we now know that we can drill and complete our horizontal well in the Baxter. We are going to apply what have we've learned with the Canyon Creek 79H on our second horizontal well. In fact, we are drilling that right now. It's the Trail 14D you are going to want to follow that.

Let me turn to our Uinta Basin deep play, where the latest results also have our technical team pretty excited. Recall that we operate a continuous block of about 120,000 net acres in the Uinta Basin, the deep target here of the Dakota, Mancos shale, Mancos B, Blackhawk, and Lower Mesa Verde formations across the growth section from about 9,000 feet to over 16,000 feet deep.

We now have six wells flowing to sales from zones below the Mancos B, plus nine older wells completed in the Mancos B and the Blackhawk. And one well is waiting on completion with three wells drilling ahead.

We've completed three new deep wells this year and they are all keepers. Note that our latest well, the Glen Bench 9027 today is making about 6.5 million cubic feet per day on just a 1264 choke with about 6000 pounds flowing casing pressure after nine days on production. What's intriguing about this well is we haven't fract it yet. It's producing naturally from just the Dakota formation. So, we still have up the whole targets to complete in the Mancos, the Mancos B, and the Blackhawk, Mesa Verde, and Wasatch formations.

We are also encouraged by some early results from our third and fourth well in the Flat Rock state section 36 in the southern part of the Uinta Basin. We have a 90% working interest in the third well, Flat Rock 3P, which has been online for 75 days and is currently making about 6.5 million cubic feet per day.

We have an 87% working interest in the fourth well, Flat Rock 11P, and that well is currently making about 2.5 million cubic feet per day after 30 days online.

We are drilling our fifth well in the state section today. The targets here are Jurassic and Cretaceous age reservoirs. Also, I should note that the gas from these wells flows into the new Uinta Basin field services line in which Gas Management is part owner and operator.

The location of these new wells are in more detailed shown on our updated Vermillion and Uinta Basin maps, which we've posted on our website at www.questar.com.

Let me turn to Gas Management. Our midstream company has a full played again this summer. We are going to expand our Uinta Basin hub. We are going to build a 150 million cubic foot per day gas processing plant, near Questar pipelines Fidlar Station compressor. We call this the Stagecoach plant. This $35 million project is underwritten by long-term volume dedications from third-party producers.

We will connect Stagecoach to our existing 180 million cubic foot a day Red Wash plant by an existing 16-mile pipeline. Both Stagecoach and Red Wash could be operating at full capacity by next summer. Gas Management is working with the Uinta Basin producers on still another expansion.

Our midstream company is also planning a new 300 million cubic foot per day gas processing plant at Kanda, that's near Rock Springs, Wyoming. It's the point where multiple pipelines come together to see the Rockies Express Pipeline. It's the likely location for processing for future volumes from the Vermillion Basin. We are going to start construction on this facility late this year.

Turning briefly to our Questar Pipeline, our FERC-regulated interstate pipeline business also has a full plate this summer. Rockies producers got some good news on April 19th when FERC approved the REX-West project. This project includes Questar pipeline subsidiary Overthrust Pipeline’s construction of the 78 mile 36-inch pipeline from Kanda to Wamsutter. This $200 million project is going to add about 625 million cubic feet a day to the Rockies Express Pipeline at Wamsutter and 125 million cubic feet per day to work at Kanda.

When we complete this project late this year Overthrust will be connecting Opal Supply, Urban Southwest Wyoming to Rex.

Our Overthrust expansion is underwritten by a 20 year capacity release with the Kinder Morgan led Rex Partners, who will build the 1.5 trillion cubic foot per day 750 mile pipeline from the Cheyenne Hub in the Eastern Rockies to the pipeline hub at Audrain, Missouri. This is a very important pipeline for Rockies producers.

Based on the current forward curve, the market is betting that Rex stays on track. Rockies basis shrinks from about $3.20 per MMBtu average for the remainder of this year to about a $1.50 per MMBtus next year, and then about $1 per MMBtus in 2009, once the final segment Rex East is completed from Missouri to Clarington, Ohio. If you own shares in Questar or any other Rockies producer you got to be routing for Rex.

On April 19, FERC-approved Questar pipeline southern system Phase II expansion this is a $105 million project, it will add about a 175 million cubic feet a day from the Uinta Basin West for delivery to Questar Gas and Kern River Pipeline.

We are going to break ground in May. This should be in service by December. Once again the investment is underwritten by long-term contracts with Uinta Basin producers.

So, let me summarize. Despite some challenges, as always Questar is off to a pretty good start in '07. We’ve raised production guidance for the year. We’ve raised the low end of our EPS guidance. We are optimistic that the BLM is going to issue a favorable ROD on our concentrated development proposal at Pinedale. And we are moving up the learning curve on our emerging frontier plays the Vermillion Deep and the Uinta Basin deep plays.

And with that we will now be glad to take your questions.

Question-and-Answer Session

Operator

(Operator Instructions). And your first audio question comes from the line of Shneur Gershuni with UBS.

Shneur Gershuni - UBS

Hi good morning guys.

Keith Rattie

Good morning Shneur.

Shneur Gershuni - UBS

How are you? Good quarter. I just wanted to ask a couple of quick questions here and so forth. I guess the first question is, in your guidance, you'd sort of mentioned in the 3rd of March you talked about a very wide Rocky basis differential. Are you erring on the side of conservatism or is it something that you are seeing in the strip right now with respect to trying to have some production up?

Keith Rattie

Thanks for the question, Shneur. We think our assumption is realistic. In fact yesterday based on the quotes that we received from the counter parties that we hedge with the Rockies basis for the remainder of the calendar year is widened to 320, which is about where our guidance is today. The mid-continent basis is a little less than the $1 assumption we’ve used in our guidance. But we could see some pressure on that. So, to answer your question, we think, we are just using the collective wisdom of the market which is about 325 for the rest of this year.

Shneur Gershuni - UBS

Given the very high level, would you be willing to sit there and say it's not worth hedging at this point right now and seeing what happens? Arguably this is a pretty high basis differential and could potentially come down a little bit?

Keith Rattie

Well, we're already pretty well hedged. We've got most of our proved-developed production in the coming months hedged. I should add that the forward curve is betting on new pipeline capacity. We see Rockies basis narrowing dramatically next year. Current quotes about $1.50, comes down to about $1 in '09 and then well below $1 in 2010, 2011.

But to get back to your question on hedging; Our focus now is on '08, '09 and we've started this you will see in our press release, adding a little bit of protection in the out years 2010. You may see us do a modest amount of hedging for the volumes the rest of this year, but most of our focus is going to be on '08.

Shneur Gershuni - UBS

Okay. Just two more quick questions; This is with respect to the Mancos play. I know it's still early on, but obviously the results look pretty promising at this point. Is it something that you're thinking that within the next six to nine months will move towards becoming a development play or move towards out of the experimentation role and more into a development role?

Keith Rattie

Let Chuck Stanley handle that one.

Chuck Stanley

We already have three rigs working in the area, drilling deep wells and another one capable of drilling this, working down the Flat Rock Area. So, I think you can say that we are moving forward with drilling up deep development wells on this place.

Shneur Gershuni - UBS

Okay, great. And just one final question, just with respect to the Vermillion Basin; Given the success that you've had in the 13C well 530 at this point after 70 days, but you've also had some success with the horizontal well, do you foresee sort of the combination of vertical wells and horizontal wells for the play going forward? Or are you leaning more towards horizontal versus vertical?

Chuck Stanley

Good question. I wish I knew the answer. Obviously, this first horizontal well was 79H well which was a mechanical success. I think if you recall in previous quarters when we talked about the 79H well. We told you that we weren't even sure we could drill a horizontal with over-pressured shales of this depth. We proved we could do it. We did have some problems drilling this well. But the biggest problem we had as Keith mentioned was gas.

We hit multiple natural fracture swarms. The last one kicked us really hard and by kick, I mean we were running at fairly high mud weights. And we got to the point where we were concerned about well control. We had closed to 3000 pounds of pressure at the surface with 17.5 pound mud at a depth of about 11,000 feet.

Now for those who are not drillers, that's a pretty tough situation. We were basically approaching the limits of the mechanical integrity of the rock. In other words, we weighted up any more with the drilled mud and think about just sort of to get a full picture here, the column of mud in the hole exerts pressure downward which basically keeps the gas in the rock and allows you to keep drilling.

We ran the risk if we ran into another fracture swarm of having a sudden loss of drilling mud in the hole that would run out into the fractures, at which point we would have a rapid entry of gas and potentially an uncontrollable well at that point. So, we made a decision after hitting that last fracture swarm about 1000 feet out to stop and set pipe. We demonstrated however that we were able to turn the corner, drill the well, lay in the casing cement; we got a good cement job. Isolate four stages and pumping in a horizontal well, initiate a fracture which frankly some of our technical folks were worried that because of the trajectory of the horizontal well, we might not be able to actually frac the shale but the fracs pumped textbook, in fact they went away very similar to vertical well. And we have a 1000 foot of horizontal section in the middle of the Baxter. And I point out, that that's about 2000 less than we had originally programmed.

What can we do differently with the next well? First of all, we really need a type of blowout preventer that has a mechanical rotating head that it will allow us to drill with a fairly substantial amount of pressure at the surface. The current blowout preventer that we are using, basically uses a big rubber doughnut around the drill pipe, which if you think about, it is not a very comfortable thing to have with 3000 pounds of gas pressure at the surface. These mechanical rotating heads that are steel are big pieces of equipment and we don't have a rig in our fleet working for us right now that will accommodate this additional piece of equipment, we need a taller rig.

We have a new rig, a purpose built rig being delivered this summer to work in this play that will accommodate this mechanical rotating head, that will give us the ability to drill, we think horizontally, take a substantial amount of pressure at the surface and get out further, that rig will be here sometime hopefully in June, July time period and we'll shake it down may be on one well before we drill a horizontal well with it.

The other challenge for us is we don’t know, we are really connected up completely with the cracks that we encountered when we drilled this horizontal well. We saw a lot of pressure and a lot of gas at the surface when we were drilling. Just the act of cementing and casing in the hole may have potentially plugged up some of those natural fractures. And we may not be seeing the full performance even though the 1000 foot laterals because of the way we cemented the casing.

We're discussing and debating internally whether it's even wise to cement casing in these holes or perhaps what we should do is just run an un-cemented pre-perforated liner and produce the well naturally. We are not even sure if fracture stimulation is not necessary because, given the liveliness of the well, while we are drilling it, we wonder if there maybe other ways to complete.

So, as Keith said, we are early in this program, but we are seeing a lot of encouragement just based on the fact that we are seeing natural fractures, we are able to drill these wells. And we think when we have the proper equipment in place we will be able to get out 3000 feet.

This well is making a little under 5 million a day this morning. That's from 1000 feet of Baxter, remember we normally have eight stages in the Baxter in a vertical well over 3000 feet of section. So, proportionately it’s doing quite well, because it's essentially producing from a single isolated interval in the middle of Baxter.

Shneur Gershuni - UBS

Okay. And just one last final question, I promise. With respect to the SEIS, could you potentially share with us some milestones, when certain comment periods as and when the reviews are expected to come back and so forth, sort of things that we can watch out for?

Chuck Stanley

Okay. Well, it's pretty simple from this point forward Shneur comment period ended a couple of weeks ago on the 6th, I believe. The process from this point forward is the BLM will finalize a draft, a final SCIS. And we don't know how long that will take. But given previous performance, several months and then issue a final record decision after that draft is finished and put in place.

That's why in Keith's remarks, we gave a range of dates, but it's going to be some time in the third quarter, late summer, or early fall, by the time that draft is finalized and the record decision is issued.

Shneur Gershuni - UBS

Great. Thank you very much guys.

Chuck Stanley

Thank you.

Operator

Your next question comes from the line of Carl Kirst of Credit Suisse.

Carl Kirst - Credit Suisse

Hi, good morning everybody.

Chuck Stanley

Hey, Carl.

Carl Kirst - Credit Suisse

Chuck to the kind of follow-up of Shneur's question to make sure I understand here. When you said you've only got a 1000 feet here of the Baxter in the 79H and then I guess turning to go 1000 feet into horizontal. Do we actually have left kind of height of permeability in the horizontal that we do actually in a vertical then considering a vertical is 3500 feet and it's just the natural fractures that are doing this, and so there may be further upsides by getting more than a 1000 feet down, am I understanding that correct?

Chuck Stanley

Great question, Carl. I would like to think so. As I said one well, with one data point it's hard to make generalizations, but you are absolutely correct we drilled about halfway through, so, about 1500 feet into the Baxter. By the time, we had turned the corner and we were essentially flat or in the middle of the zone that we were targeting, we were at a measured depth of about 11,000 feet and then we drilled about a 1000 feet horizontally and I think our total depth was little over 12,000 feet.

The four stages that we pumped were only in the horizontal section. And the fundamental questions that you are asking are good ones. How high are those fracs, the pump fracs of the artificial stimulation, and how much of they are actually contributing to the initial flow rate?

Obviously, fundamental principal of reservoir engineering is that the rate is directly proportional to the amount of permeability feet, or in other words the amount of rock that's exposed to the well bore. So, it's intuitively logical to assume that the longer the horizontal well, the higher the initial rate. If we got 5 million cubic feet a day out of a 1000 foot lateral would we get 15 million cubic feet a day out of a 3000 foot lateral. That's probably not good math.

It's probably not purely multiplicative, because there is friction and then, keep in mind we are tracking these wells as water laying in the horizontal well bore from the flow back of the frac fluids. But there should be proportionality; I don't know what the exact multiplier is between lateral length and initial rate. The only thing it keep caution then I will add it again just to make sure everybody's focus is on this.

Early time series production data. The real question here is obviously the initial rate and sustained deliverability help returns. We need to know whether we are tapping a larger reservoir and therefore increasing reserves as well, to really answer the other part of the equation here on economic viability of this well. But you are on the right track regarding your question.

Carl Kirst - Credit Suisse

Okay. That's very helpful. Just a couple of other questions on that, I guess the original budget was roughly $7.5 to $8 million range is that kind of where the well came in at, you mentioned some, obviously?

Chuck Stanley

We had some problems drilling the well even from the service because we started with a large diameter casing string than our normal vertical well in order to basically have the option of running casing through the build angle from vertical to horizontal. The costs are not all in on it, the completion cost since we just did it last week are still out there. But, my estimated cost is probably $9 million, $9.5 million but it costs more than budget.

Again, once we build confidence on casing design and overall well construction that costs will come down. We are seeing even in the Uinta Basin step changes in our ability to drill these wells as we focus our very talented team of drillers on well construction issues and design and then obviously the more wells we drill as we've demonstrated at Pinedale, the better we get out of it.

Carl Kirst - Credit Suisse

Great. And then last question, can you comment on what the total time was from spud to connection and if we should look for a same timeframe on the second Trail 14D.

Chuck Stanley

Carl, I don’t have that number in my head, I think this well took us about 70 days to drill, and case, and complete. Since we are not in the area with a concentration of equipment, frac equipment, et cetera, we have to kind of schedule these wells for completion and work around our other activities i.e. Pinedale. We want to use obviously the experience crews especially on these first horizontal wells and so we pick and choose when we complete them a little bit. We have another well standing, a vertical well on the north end of trail, that's been standing since before this horizontal well was completed and it's fundamentally just a matter of getting the right frac crew to pump the frac jobs.

So early days, I wouldn't use 70 days as a proxy and I know what you're trying to do, you’re trying to figure out when the next well will be down and we will have that news out and it really depends on whether or not wherever we get out further horizontally and what we learn in that well regarding drilling.

Carl Kirst - Credit Suisse

Okay, that's very helpful. I'll get back in the queue for my next question. Thanks guys.

Chuck Stanley

Thanks.

Operator

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

Sam Brothwell - Wachovia

Hi, good morning everybody.

Keith Rattie

Hi Sam.

Chuck Stanley

Hi Sam.

Sam Brothwell - Wachovia

As you guys, Chuck and Keith, you alluded to prior questions, Uinta and Vermillion moving more into the development stage. As you compare that with Pinedale, as my understanding you don't face the same kind of access restrictions there that you do at Pinedale. And secondly, can you talk a little bit about your rig and crew availability as you're going to kind of have three balls in the air here? Is that going to place some limitations on your development efforts?

Chuck Stanley

First of all, you're right the seasonal access restrictions that exist at Pinedale are not as significant in the Uinta Basin. There still are various wildlife stiffs that affect our ability to occupy certain locations at certain times of the year, raptors. That area is located in a Green River drainage area in Uinta Basin and near the river there are raptors and other critters that nest and during certain times of the year we are not enough to occupy locations. But we don't have the broad restriction on access, seasonal restriction on access that we have at Pinedale.

The other thing to keep in mind in Uinta Basin is that we have largely developed the existing leasehold of 40 acre density in the Wasatch, the shallower gas sands. So, we have established infrastructure roads and surface disturbances there, which mitigate some of the concerns over additional activity.

And to your second question Sam. Infrastructure are you drilling rigs and hydraulic stimulation services, that whole infrastructure is always a challenge, but we have worked with our drilling contractors and we have developed a fleet of rigs which we are pretty happy with their performance and we think we can continue to augment that fleet working with our contractors to grow with us, if you will, and it's not just the iron, it's the people as we continually emphasis that are critical to improve performance. The reason we get the results we get at places like Pinedale is because we have the same group of people, both our own employees, our consultants, and then the contractors have a stable workforce who is very talented, who is focused with us on efficiency and safety, and we need that same culture in all three areas and we will only grow as fast as we can grow that infrastructure and that culture along with us.

Sam Brothwell - Wachovia

Okay. Thanks and congratulations guys.

Chuck Stanley

Thanks.

Operator

Your next question comes from the line of Carol Coale with FMH Capital.

Carol Coale - FMH Capital

Hello, good morning everyone.

Chuck Stanley

Hi Carol.

Carol Coale - FMH Capital

It's Carol Coale from FMH Capital. Formerly at Sanders Morris Harris.

Chuck Stanley

(inaudible) that out.

Carol Coale - FMH Capital

I had a couple of questions on what you were doing in the Vermillion. And I just came from the IPAA Conference and listen to Kodiak, to their presentation. And it's my understanding that you all have just announced the one well in Vermillion, the Trail 13C. They seem to be under the impression that you had two more discoveries in the southern portion of the northern Trail area, actually went so far as to put it in their presentation and show it to the audience. Where you aware of that?

Chuck Stanley

Carol, this is Chuck. I haven't had a chance to look at any of our competitor's presentation. As you know, I was there, I saw you there actually right after our presentation, I was in one-on-one and then got back on a plane to get back here for the conference call.

Just to remind you, we talked about the 13C well which we press release back about 60 days ago. We have recently completed the 79H well, which we've been talking about the first horizontal well, and we have a third well that I mentioned the Trail 14 well, which is stand in cased, waiting on completion.

If you go out to our website, we recently posted just right as we started the call, a detailed map that shows the locations of each of those wells. It's actually a nice series of slides that starts out with sort of a broad locator map, and then it zooms down to zoom in area on the Canyon Creek area and on the Trail. It will show you not only those recent wells that I've just mentioned, but also the location of our new horizontal well, so you can see where they are relative to each other.

Carol Coale - FMH Capital

Okay. And secondly, I don't think this has been asked yet. There has been some talk in the past that you might consider separating your E&P operations from your Utility? I know it's not in your immediate plans at this point, I was wondering if you had any more thoughts there?

Keith Rattie

Carol, Keith Rattie. No plans to restructure the company at this point, something that we’re always looking at on a good mandate, as always reminds the GAAP and make sure that we are getting value for our shareholders. But we believe that there is some benefit to the current structure, there are certainly some compliments between these businesses. So, for the time being, we are going to focus on trying to capitalize on the growth opportunities we have in our unregulated businesses. It’s an ongoing conversation we have with our Board of Directors, but I would tell you that we have no plans to restructure at least not today.

Carol Coale - FMH Capital

All right, that’s all I have. Thank you very much.

Operator

And your next question comes from the line of Mike Heim with A. G. Edwards.

Mike Heim - A. G. Edwards

Thanks, I am still trying to understand the 13% jump in volumes at Pinedale this quarter, and quarter to that’s usually we see a decrease. I heard your comments about lowering the spud to TD number. I guess my question is that pretty much the full explanation? And two, as you talk about going from to eight rigs and more crews, how transferable do you think that is or is it a question of keeping good personnel over the winter that we should expect some decrease going into the summer?

Chuck Stanley

Mike this is Chuck. The comparable is quarter-over-quarter increase there. Are you looking at an 8% increase fourth quarter to first quarter?

Mike Heim - A. G. Edwards

I guess I’m looking at the jump for Pinedale from December of 10.7 to this quarter of 12.1.

Chuck Stanley

The key there is remember during the quarter, we have a lot of wells that are completed and turned to sales late in November or mid-November. So, you only get a partial quarter of production out of those wells. They come on at fairly high rates, they stay fairly high. So, what you see is a sustained production from those wells during the first quarter of '06.

Mike Heim - A. G. Edwards

Is more of that going on this year than in previous years?

Chuck Stanley

I don’t have it at my fingertips, the number of wells that we completed late in a year. But what we are seeing is well performance I think that is giving us more sustained deliverability for longer than higher rates than we have in the past. Perhaps, just based on where the wells are located. Some of the blank wells obviously decline a little faster than the wells on the crest.

Mike Heim - A. G. Edwards

Okay. And the second half of my question about just improved efficiency?

Chuck Stanley

Yes. We have relationships with contractors that have a very strong culture of performance themselves and we are relying on those contractors to field new rigs or refurbished rigs in each of these place, whether it would be Pinedale or the Vermillion or Uinta Basin. Only when they are comfortable that they can crew the rigs, I think, we saw that with the ramp-up in activity back in '03 and '04 that a lot of rigs were stood up and put into service but they were crewed by inexperienced people and as a result the productivity of those rigs was marginal at best.

And what we think are good drilling contractors who basically have said to us, look, we are not going to add to the fleet unless we are confident that we can give you the same kind of service that you use to get.

And what we've also found is that by using several key drilling contractors, they were able to bring new employees and train them with the season hands that have the experience and the culture that we like. And then, when they bring in a new drilling rig, they are able to take a subset of their existing personnel and move them onto that new rig. So, we are just not talking about the rigs. They get brand new people. And that's a huge step in the right directions as far as I am concerned.

Mike Heim - A. G. Edwards

Okay. And shifting subjects for one more question, I thought I saw a newspaper article once talking about the Governor expressing some surprise that the number of wells that could be drilled under the SCIS. Are you still comfortable, the Governor is backing the project?

Chuck Stanley

Mike, I can't speak for Governor Freudenthal, but he is firmly behind the proposal that the operators put forth with respect to the supplemental EIS. The pay for reproduction of all our various components in the draft SCIS I think was the subject of some of his concern. I think the Governor himself is known all along that the potential of Pinedale, which is now, as you know, the second largest gas field in US. And the possibility that the operators would be drilling wells on a combination of 10-acre and 5-acre density. The clarity of writing in the draft, at SCIS left a lot to be desired, especially the distinguishing between surface disturbance and subsurface density, because clearly all other proponents under the SCIS proposed to drill wells from pads directionally and there wasn't a real clear distinction in the draft with respect to the ultimate number of subsurface locations versus surface locations, because I think it created a lot of confusion for some folks.

Mike Heim - A. G. Edwards

Okay. All right, thank you.

Chuck Stanley

Thanks.

Operator

And your next question comes from the line of Carl Kirst with Credit Suisse.

Carl Kirst - Credit Suisse

Hi, good morning everybody. I just wanted to follow-up on few things. First of, can you talk from a budget standpoint of market resources incremental three to four Pinedale wells at 5 to 6 million above. Should we be looking at the budget going up a like amount or is there cost inflation just as we keep an eye on these things?

Chuck Stanley

Carl, we'll be updating our capital budget here, I am visiting with our Board at our quarterly meeting. Surprising to say, if we are drilling more wells, we are going to need more capital. But as Keith mentioned in his prepared remarks, with respect to Pinedale, we expect that our average well cost can go down a little bit.

Now, we are going to budget based on historical performance and obviously expect a reduction in cost based on the performance that we are seeing today. But an incremental, three or four wells there, we are going to drill more wells at Elm Grove.

Obviously, with the results in Vermillion, our view on how many wells we are going to drill there may change and obviously we are drilling horizontal wells versus vertical wells that could change as well. So, there is definitely going to be some increase in capital and market resources. The other components of our capital budget, I think our original proposal. It was approved by the Board. It was about $80 million of capital in Wexpro. We are hoping to spend little more than that this year.

Gas Management at the time we put together our 2007 budget had not firmed up the Stagecoach plant. So there is some additional capital required for construction of that plant in Uinta Basin and initiation of construction of the Kanda plant up in Wyoming. So, we'll see some change in capital budget through the year. We'll obviously update investors on that, as we visit our capital allocation and make changes.

Carl Kirst - Credit Suisse

Great, but it all seems to be coming from new activity, not necessarily cost inflation pressures?

Chuck Stanley

Yes, actually I think the cost from what we see, are flat to trending downward in our drilling activity. So, these new projects that obviously early in the year, we start our capital budgeting process in September and then visit with our Board and get approval in November. And by the time the first quarter is finished, we have a lot more visibility on how many wells we're going to drill and the various plays. Obviously, new projects or projects that we’re working on, finally reached the critical point where we allocate capital to them. We have contracts in place both in the case of our midstream business, with producers and we have a good, a high-quality cost estimate that we can go forward with allocating capital, after we're sure it meets our economic criteria.

Carl Kirst - Credit Suisse

Great. Just one follow-up on that and I may have missed this in the prepared comments, but the 300 million a day Kanda plant. Could you refresh my memory, what is the total cost of that in the in-service date?

Chuck Stanley

Go ahead. Keith wants to talk.

Keith Rattie

I'll let Chuck give you the capital number; we haven't put a number out there on that yet. Carl, in-service date would be 2008. We're trying to put together our strategies now that we'll integrate our development plan for the Vermillion Basin with our, what we hope will be an accelerated development at Pinedale. We also are looking at providing a processing service for pipeline affiliate and if you look at the way the plays are developing in our core Rockies producing areas, we think Kanda is a good place to build new processing infrastructure in our midstream business. So, that's what we are focused on right now. Chuck might have an updated capital number that I haven’t heard yet.

Chuck Stanley

I think it’s a little early to throw out a number yet, Carl. We are still working with vendors and contractors to finalize the capital costs. So, later on this year I think obviously we’ll have a better number before we begin construction. And we will update you on probably the third quarter.

Carl Kirst - Credit Suisse

Great and then just the last question on DP Uinta as we are all looking for this ultimately to move into the development stage overtime. Are we still from an average benchmarking Chuck? Are we still looking at average EUR 3 to 5 fees $6 to $7 million well cost, is that a fair number?

Chuck Stanley

The reserve number certainly is in the range. And just to be clear Carl, that's an aggregate reserve number, gross reserves including all zones from Dakota up through the Mesa Verde section and potentially including the Wasatch.

Well costs are highly depending on where on that 120,000 plus acre block the wells are drilled. On the northwest, basically the geology all dips to the northwest. So, the northwest corner of our block we see well depths of over 16,000 feet in the southeast corner of our continuous acreage block we can drill through the entire section in less than 15,000 feet. And the well costs are directly related to obviously the depth and also the nature of the geology. So, in the northwest parts, we have to drill wells with an additional casing string and that adds to the cost.

We have seen in the past several wells, as I mentioned earlier, a fundamental decrease in the number of days to drill. We add over 16,000 feet in the well in 50 days, in the winter that use to take us 80 days. So, we are making the kinds of changes that come to expect out of our drilling folks, when they really put their mind to it and they have some data to work with to improve well design and performance.

Well cost, $5 million to $7 million is certainly reasonable over that range of days.

Carl Kirst - Credit Suisse

Great. Thanks so much for the extra detail guys.

Operator

Your next question comes from the line of Carl Brown with Cramer Rosenthal.

Carl Brown - Cramer Rosenthal

Chuck. I had a quick question on the horizontal well in Vermillion. That 5 million a day is that all coming from the Baxter, or is there any production coming from the shallower zone where Wexpro would have an interest?

Chuck Stanley

No, sir. It's only completed in four stages in the horizontal portion of the Baxter.

Carl Brown - Cramer Rosenthal

Okay. And generally speaking in terms of horizontal development, in general, is there any reason that there wouldn't be the same opportunity to have some production and cost sharing of the shallower zones with Wexpro?

Chuck Stanley

No reason, theoretically. Right now, obviously, we don't want to. How should I say it? Pollute the production information that we are receiving from this new horizontal well by commingling shallower Wexpro reservoirs. After we get comfortable with well performance and decline curves and reserves from the horizontal well, then we can go back and add the shallower horizons.

Obviously, the other limitation on cost sharing and production as you can only add the Wexpro reserves and production in areas where it exists. So, going back to our IR presentation, there is a map in there that shows the crude outline of the shallow historic producing fields in the Wexpro-operated Canyon Creek and Trail units and those outlines obviously the areas under which we would expect to build, allocate cost, and share development cost between Wexpro and QEP.

Carl Brown - Cramer Rosenthal

Great. And since the bigger equipment, the blow-out preventer isn't going to be ready until the summer time. So, in regards to the next horizontal, might you play with not casing the well and not fracturing it?

Chuck Stanley

Carl, the decision to case or not case or to cement the casing or not to cement the casing is sort of independent of the drilling process. The fundamental problem we have is when we encountered these fractures, we get a lot of gas in the well bore and we need to be able to safely handle that gas kick without compromising well safety and well control.

The blow-out preventer in this rotating head allows you to have pressure at the surface. Normally, we don't like to see a lot of pressure at the surface when we are drilling. We try to keep the mud weight high enough to control the amount of gas we see at the surface.

At Pinedale, we will allow the mud weight to be slightly lower and we will actually take some gas at the surface, but we don't have natural fractures at Pinedale. So, the probability of drilling into a natural fracture swarm and having a sudden rapid loss of drilling fluid which didn't allows the gas to come in is much less.

In the Vermillion Basin, we now know we have fractures and there may be some big ones and it's conceivable that you could be drilling ahead in the horizontal section. Let the well take a big drink and suddenly have the full force and pressure of a gas zone at the surface almost instantly. That requires a very carefully designed and very well thought out drilling strategy and this rotating equipment is part of it.

Probably, the key point here is, we have a new rig that we specifically had built. It’s about 12 feet taller than any of the other rigs. So, that we can stick this additional equipment underneath the sub structure, and this rig will have all of the other bells and whistles that the newer rigs have with respect to the top drive et cetera.

Carl Brown - Cramer Rosenthal

How did you know to order that ahead of the time, was that because of the Trail, where you encountered on the Trail well, the vertical one?

Chuck Stanley

We’ve had some problems drilling a number of the vertical wells and that part of the well cost has been spending several days whenever we encounter a strong gas is circulating and building mud weight to try to get these wells back under control. So, we had hints that this was the problem. And we knew that if we were going to drill horizontal wells and we were going to encounter fractures that we would need to have this capability on this rig. So, maybe a little clear volume.

Carl Brown - Cramer Rosenthal

Okay. And if you do find that because of these natural fractures you don’t need to artificially fracture the rock. How much would that save in terms of well cost?

Chuck Stanley

It depends. If we are talking about 3,000 foot laterally it could save a couple of $3 million in stimulation cost. We don’t know you yet Carl.

Carl Brown - Cramer Rosenthal

Okay.

Chuck Stanley

There was a camp on this 79H well, after we encountered problems that actually wanted to, this is internal camp that actually wanted to, after we ran casing in the horizontal section, move a coil tubing unit and then drill some open hole beyond the cased interval to experiment with just a simple open-hole completion in the shale.

I was the final decider as somebody said once that I had decided not do it because I didn't want to compromise the mechanical integrity of what we had accomplished today.

There is an argument that you might not even need casing, you could simply run a surface production string down into the shale, cement it, drill a horizontal well, the horizon section and just open it to sales.

Obviously, we've had some bad experience with that in Hilliard Shale up to the North of Pinedale. So, we got to think carefully about whether we really want to do that or not because obviously, if it collapses then you are back to square zero.

Carl Brown - Cramer Rosenthal

And then last question. Could you just elaborate a little bit more on the Glen Bench well that's producing 6.5 million a day just from Dakota. Do you normally frac the Dakota, what's different about this well, any thought as to why it would be so productive from just the Dakota. And then, what's the plan for going back and completing the shallower zone?

Chuck Stanley

I’m glad you asked about that Carl. First of all, the Dakota, we've drilled to the Dakota and the number of these deep wells out in the Uinta Basin. Each one of them has encountered Dakota sands. The distribution of Dakota sands is very much like the distribution of sands at Pinedale. There is always sand present, the amount, and fitness, and quality of the sands is highly variable. The Dakota is a major producing interval up in the Green River Basin on the Moxa Arch, where both Questar E&P and Wexpro operate production.

Historically, most of the wells on the Moxa Arch were not fracture stimulated in the Dakota. We've tried to frac some of the wells in the Dakota, and we've met with varying success. In fact, we've tested the Dakota natural and then frac'd it and actually reduce the productivity after fracting. This particular well, encountered Dakota sand near the bottom at a depth of a little over 16,000 feet at the bottom of the Dakota section, which is different than the Dakota that we've seen anyplace else in the Uinta Basin. It was very porous. It looked to be somewhere between 16% and 20% porosity, on the porosity logs. And we decided that we would just, case it, and then perforate it and see what it would do. And obviously, the results were quite surprising. It came back very strong. The well is still making over 6 million a day. It's been at 6 million a day since we turned it on, very good pressures.

Where does this Dakota sand go? How widespread is it? How repeatable is it? I don't know. We've got four or five control points. We are going to produce this for a while. We wanted to see if it would produce before we frac it and then so obviously we don't need to frac it.

After we get some production history on it, at some point we'll get up and put a frac plug over it and come up whole and frac the Mancos and Mancos B silt above it. And probably the Mesaverde and Wasatch, but it will be a while. We want to watch this well for a while to see what it will do. Again there is some in our shop that say, why stop here. We know we can make 6 million out of Dakota. Let's put a frac plug over it and make a 20 million a day or 15 million a day well. Some patience here just to get some reservoir information and production information will be useful; we'd like to know how big the sand is? It's not very big. But it seems to be holding up like it covers a fairly large area.

Carl Brown - Cramer Rosenthal

Great. Thanks a lot. I appreciate it.

Chuck Stanley

Thank you Carl.

Operator

And your next question comes from the line of John Mansfield with SAC Capital.

John Mansfield - SAC Capital

Hi, yes. I just wanted to ask you more questions about the Uinta. What kind of spacing do you think that will ultimately be drilled on? Can you give us a feeling for that?

Chuck Stanley

This is Chuck again. It's tough to say at this point. Obviously, the shales, the 40 acre density are probably not draining a very large area and so there is probably an argument in the shales that you could drill on an increased density beyond 40 acres, 20 acres with vertical wells.

The shallower sands, we've done some experimentation, we've drilled some 20 acre infill wells in the Wasatch formation. We've seen some signs of interference and that's one reason why we don't believe that you can just simply support an infill drilling program with only incremental reserves from the Wasatch formation.

Mesa Verde section, Blackhawk, discontinuous sands in the Mesa Verde probability is high that you can drill on less than 40 acres in the Mesa Verde. Obviously, what we're focused on here is the ability to complete multiple horizons, the shales in the Mancos, potentially the Dakota sands below it. And then, have the opportunity to recover incremental reserves on infill drilling in the Wasatch and potentially all new reserves in the Mesa Verde.

So, 20-acre density is probably reasonable. In some areas it may even be better than that. We just don't have a lot of data yet, so frankly answer to that question is in definitive way.

John Mansfield - SAC Capital

All right. And then, with the completion of some of the pipeline projects later in the year, is there any new thinking on MLP?

Keith Rattie

We are continuing to analyze that. We've told you in the past that we are taking a hard look at forming an MLP. Once we complete the Overthrust expansion project late this year, Overthrust would have a high tax basis or some other advantages with it bringing along with it some incremental growth potential.

I will tell you though there are a lot of question marks on this in our mind, right now. I don’t see formation of an MLP being a strategy. I see it as a way to redeploy capital out of our pipeline business while preserving some of the strategic mandate that we've given our pipeline which is to concentrate in our core producing areas and eliminate pipeline bottle mix.

I think we’ll have some more to say on this issue in the next call. But I want to give you some caution about thinking that Questar is going to form an MLP anytime soon.

John Mansfield - SAC Capital

Okay. Well congratulations on the quarter. Thanks very much.

Operator

And at this time, I show there are no further audio questions in queue.

Steve Parks

Thank you very much everyone. You can get a copy of our updated IR presentation on our website. You know how to get a hold of us. We will be back in Boston and in New York the first part of June. Appreciate your interest in the company today.

Operator

Thank you for participating in today's Questar first quarter 2007 earnings release conference call. This call will be available for replay beginning at 10:30 a.m. Eastern Time today through 11.59 p.m. Eastern Time on Thursday May 3, 2007. The conference ID number for the replay is 6008106. Again, the conference ID number for the replay is 6008106. The number to dial for the replay is 1-800-642-1687, or 706-645-9291. Thanks for participating and now you may disconnect.

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