Questar Corporation (STR)
Q1 2006 Earnings Conference Call
April 27th 2006, 9:30 AM.
Executives:
Steve Parks, Senior Vice President; Chief Financial Officer
Keith Rattie, Chairman, Chief Executive Officer
Charles Stanley, President, Chief Executive Officer of Questar Market Resources
Allan Bradley, President, Chief Executive Officer of Questar Pipeline
Alan Allred, President and CEO
Analysts:
Sam Brothwell, Wachovia Securities
Scott Soler, Morgan Stanley
Jay Yannello, Pali Capital
Shinur Gershuni, UBS Securities
Richard Gross, Lehman Brothers
David Thickens, Deephaven Capital
Carl Brown, Cramer Rosenthal
Joe Magner, Petrie Parkman & Co.
Faisel Khan, Citigroup
Carl Kirst, Credit Suisse
Monroe Helm, CM Energy Partners
Operator
Good morning, my name is Brian and I will be your conference operator today. At this time, I would like to welcome everyone to the Questar Corporation First Quarter 2006 Earnings Conference Call. Operator Instructions. At this time, I would like to turn the conference over to Mr. Steve Parks, Senior Vice President and Chief Financial Officer. Please go ahead, Mr. Parks.
Steve Parks, Senior Vice President; Chief Financial Officer
Thank you Brian, and good morning. Welcome to Questar Corporation's first quarter 2006 Conference Call. Yesterday we reported that Questar's first quarter 2006 net income was up 44%, driven by 23% increase in the natural gas and oil -- excuse me, natural gas and oil equivalent production and higher prices for natural gas, oil, and natural gas liquids. You can access our earnings release on our website at http://www.questar.com/.
Following my remarks this morning, Keith Rattie, our Chairman and CEO will comment on operations and update our guidance for higher 2006 earnings and production. After Keith's comments we'll take your questions. We have with us today other members of Questar's senior management, including Chuck Stanley, President and CEO of Questar Market Resources; Allan Bradley, President and CEO of Questar Pipeline; and 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. These statements are made in good faith and we believe they are reasonable representations of the company's expected performance at this time. Actual results may vary from our stated expectations and projections, due to a variety of factors that are described in our Form 10-K and 10-Q filings with the Securities and Exchange Commission.
Now, let me briefly recap our first quarter financial results. Questar's first quarter 2006 net income was up 44% to $137.2 million, or $1.57 per diluted share compared to 95.2 million or $1.10 per share in 2005. There were 84 -- I'm sorry, 87.4 million diluted average common shares outstanding in the 2006 quarter compared to 86.7 million in the 2005 quarter.
Our Market Resources subsidiary had another strong quarter. Net income was up 67% in the first quarter compared to year ago. Market Resources engages in gas and oil exploration, development, and production, gas gathering and processing, wholesale gas and oil marketing, and gas storage. Market Resources net income was 94.7 million in the first quarter 2006 compared with 56.6 million in 2005.
All four Market Resources subsidiaries, Questar Exploration and Production; Wexpro; Gas Management; and Energy Trading, posted significantly higher earnings. Questar E&P net income was up 94%, driven by a 23% increase in natural gas production and higher realized prices for natural gas, oil, and NGL. Wexpro net income was up 18%, driven by a 16% increase in investment base over the past 12 months. Gas Management net income was up 10%, due to higher processing volumes and margin. Energy Trading net income nearly doubled on higher volumes, increased storage activity and improved margins.
Questar Pipeline, our interstate pipeline and storage business, earned $11.4 million in the first quarter 2006, up 37% from 8.3 million in the first quarter of 2005. This increase was driven by new transportation contracts and higher NGL prices. The new contracts included the November 2005 completion of an expansion of its southern system and the December 2005 completion of a new interconnection between Overthrust pipeline and the Kern River pipeline. Also, the July 2005 FERC settlement of an NGL sales sharing dispute added $600,000 to revenues in the first quarter of 2005.
Questar Gas, our retail gas distribution utility, reported first quarter 2006 earnings of $29.4 million, 2% higher than a year ago. The utility benefited from a 4.2% increase in customers and the settlement of a long-standing dispute with Utah regulators over safety-related gas processing costs. Higher revenues were partially offset by increased bad debt expense and a 2% decline in weather-normalized usage per customer, compared to a year ago. Now I'll turn the microphone over to Keith Rattie, Questar Chairman and CEO.
Keith Rattie, Chairman, Chief Executive Officer
Good morning, everyone. Thanks for joining us. The bottom line is we're off to a pretty good start in 2006. Note, that we've bumped both earnings and production guidance for 2006. We now estimate that this year's earnings could range from about 450 to 480 per diluted share. That's a $0.20 increase from our previous guidance. We put a table in our release to reconcile the current and previous guidance. Note that we haven't changed our price or basis assumptions for the guidance we gave in February. That $0.20 increase reflects better execution and generally a quick start in 2006.
Also note for reference that the current Rockies basis is about $1.80 per million Btu and current mid-continent basis is about $1.45 per million Btus in the west and about $1.30 per million Btus in the east. Both of those are less than what we've assumed in our guidance.
Note that we've now hedged about 68% of forecast 2006 gas and oil equivalent production at significantly higher realized prices than in 2005. So, as a result, we've taken commodity price risk pretty much out of the equation for Questar in '06.
Also note that we've now hedged 60 bcf of gas in 2007 at an average net to the well price more than $1.00 above the average hedge price for 2006 production. And note that we've also added some hedges in 2008 at higher prices.
Let me turn to highlights from operations. Questar E&P reported production of 32.3 billion cubic feet equivalent in the first quarter, that's up 23% from the first quarter a year ago. Excluding a one-time increase of 7/10th of a bcf equivalent from the settlement of an imbalance, we grew first quarter production 20%. And that's on the heels of 15% year-on-year increase in Q4 and 16% year-on-year increase in Q3 2005.
We now estimate full-year 2006 production could range from 124 to 126 bcf equivalent. That's compared to previous guidance of 122 to 124 bcf equivalent. This assumes 45 to 48 wells at Pinedale, which is unchanged from our previous guidance. Also note that first quarter gas and oil equivalent production was up significantly in every Questar E&P operating unit from the year-ago quarter. Pinedale production was up 29%, Rocky's legacy production was up 24% -- 7% if you exclude the imbalance settlement -- and new Vermillion Basin volumes offset normal declines from mature properties. I'll talk about Vermillion here in a bit.
One of the biggest highlights, mid-continent production was up 26% driven by our Elm Grove tight gas play in northwest Louisiana and the successful high working interest exploratory well in the Arkona basin.
We had seven rigs operating at Pinedale this past winter. That's compared to just two rigs during the winter of 2004 and 2005. Note that due to winter access restrictions we did not complete any new wells at Pinedale in the first quarter of this year. So, we'll come out of the winter with 33 new wells to complete in the second and third quarter of this year.
We are going to add two more rigs for a total of nine this summer. Now, I will remind you that our production typically declines during the first and second quarters due to winter access restrictions at Pinedale and elsewhere in the Rockies. But with a big inventory of new wells coming out of Pinedale mid-summer, Questar E&P production should turn up again in the third quarter and then again in the fourth quarter.
Our Pinedale team continues to drive drilling efficiency higher, and if that continues, there's some upside in our estimate of 45 to 48 new wells this year.
Recall that in 2004 we averaged about 65 days to drill, log, and case a typical Pinedale well. In 2005, we reduced that to 47 days. This winter we've averaged less than 42 days per well, and if you strip out a couple of problem wells, our average is under 40 days. Our Pinedale team is delivering these results on directional wells that average 14,300 feet measure depth. We are not aware of any other operator at Pinedale that's getting these results.
Let me briefly update you on our Pinedale Deep test. Recall last September we produced gas from the Hilliard Shale at peak extrapolator rates of 10.7 million cubic feet a day equivalent for about 32 hours and then the well plugged off and flow abruptly stopped. For safety reasons, we shut down for winter but we're now moving back on location to re-enter and clean out the well. We hope to circulate out the obstruction and re-establish production from the Hilliard.
Now, depending on what we find, we'll either continue testing the Hilliard or we'll move uphole and test our primary target the Rock Springs. Note that from logs, we've identified multiple completion intervals in the Rock Springs at depths from about 16,000 feet to about 18,000 feet.
Turn briefly to Gas Management, our gathering and processing company had another good quarter on the heels of a 70% jump in net income in 2005. And Gas Management has another big construction program this summer. We are building a 20-inch pipeline from our Blacks Fork plant to Kern River pipeline near Opal, Wyoming, we're expanding the Blacks Fork processing plant and building additional gathering facilities to handle growing Pinedale production volumes.
Now, let me give you an update on our emerging new play in the Vermillion Basin. The bottom line here is that well performance thus far has been repeatable, well costs are coming down, and our confidence in this play is growing. Recall that the targets are the overpressured Baxter Shale and the deeper Frontier and Dakota tight sands formations, the Baxter really is the key. There's an enormous amount of gas in place across an interval of about 3,500 feet at depths of about 9,500 to about 13,000 feet. But as you folks know, with Shale gas, it's all about rate and recovery, not gas in place. And overpressure is one of the keys to rate and recovery. We believe that Baxter is overpressured over most of our now 146,000 net acres in the basin.
Recall that we kicked this play off over a year ago by re-entering two old wells, Canyon Creek 34 and Hiawatha Deep #2. We fag the Baxter, Frontier, and Dakota formations and today production has flattened in these wells at about 500,000 cubic feet per day from each well. The early performance of these wells suggest per well reserves of 2 to 4 billion cubic feet equivalent, but I would note that neither were optimally stimulated due to casings, cement, and other mechanical problems.
Our first modern well on the play, Alkali Gulch #1, went to sales in June last year and has produced almost a half bcf of gas in just over ten months. Production decline in this well has flattened at about 880,000 cubic feet per day equivalent, which, if you extrapolate that could mean reserves on the order of 3 to 4 billion cubic feet equivalent.
Production declined in our second and third new wells, Canyon Creek 41 and Hiawatha Deep #5, has also flattened at about 700,000 cubic feet per day and 600,000 cubic feet per day, respectively.
In the first quarter of 2006, we turned our fourth and fifth new wells to sale, Canyon Creek 30 -- excuse me, Canyon Creek 47 and Canyon Creek 61, and we've now recently completed our sixth new well, Trail 31.
Let me give you some numbers on these. Canyon Creek 47 has averaged about 600,000 cubic feet equivalent per day for the first 77 days. Canyon Creek 61 has averaged about 1.7 million cubic feet per day equivalent in the first two weeks of production and is now making about 1.3 million cubic feet equivalent per day.
Earlier this week, we turned the 6th well, Trail 31, to sales as well is currently making about 4 million cubic feet equivalent per day. Also note the location. Trail 31 well is 3.7 miles northeast of the nearest established Baxter production at Canyon Creek 61.
Further, we're drilling ahead on our seventh and eighth new wells, Canyon Creek 74 and Whitney Canyon.
And for those who are following this in detail, we're going to post a map on our website later today to help you locate all of these wells along with additional locations for some of our other 2006 drilling programs.
Again, what this means is that well performance thus far appears repeatable. And that's a good sign. Our technical team is focused on optimizing completion design to maximize frac extension and rate while driving down well costs.
Now, to give you some context and economics, if these wells recover an average of about 3 billion cubic feet equivalent, we're going to need to get our average well costs down to about 3.5 million to earn a 15% IRR at a $5.00 NYMEX gas price. If ultimate recoveries average 4 bcf equivalent per well, we'll earn about a 15% IRR with an average well cost of about $4.5 million. Obviously, we're going to benefit from economies of scale once we get to program drilling like we're doing at Pinedale. And I'd caution you that we're in the early days of this program. We still need additional production data from the wells we've already drilled to get comfortable with reserves. And we're going to need more wells to sample our large acreage block to determine the aerial extent of the play.
Finally, note that we've started the process for a new EIS for the project and don't expect that to be a limitation.
Questar owners are going to want to stay tuned. We plan to drill about 12 wells in the Vermillion Basin this year.
Let me turn to the Uinta Basin. First quarter production, as you know, was above plan, up 9% from the year-ago quarter. We began the year with about 80 Questar-operated and about 55 non-Questar operated locations yet to drill on 40 acre density in our core Wasatch upper Mesa Verde tight gas play. And this is at depths from about 8,000 to about 10,000 feet.
We now have about 65 Questar operated and about 50 non-operated 40 acre development locations left in our inventory. Our average working interest in these remaining locations is lower than the average of the wells we've drilled thus far, so we're going to meet success in other plays in the Basin to keep production headed up. Now, towards that end, we've stepped up the pace of our evaluation of a potential deep play, where the targets are unconventional reservoirs in the lower Mesa Verde, Blackhawk, Mancos, and Dakota formations.
Based on what we've learned in the Vermillion Basin and at Pinedale, we've now drilled and tested our first Mancos shale and Dakota formation wells -- well down to about 16,000 feet. Now, I will remind you, the Mancos is a thick, overpressured shale section. It's the age equivalent of the Baxter Shale and the Vermillion Basin and the Hilliard Shale at Pinedale. The Mancos and Dakota are present and overpressured across most of our Uinta basin acreage. Our first Mancos test, the Glen Bench 1628 well, averaged 1.4 million cubic feet per day for the first 41 days and is now making 1.2 million cubic feet a day, again, from the Mancos and Dakota formations.
Interestingly, this well performance is similar to what we have seen thus far in the Vermillion Basin. And we still have the shallower Mancos B and Blackhawk behind pipe to test at a later date.
The economics of a deep play in the Uinta Basin benefit for multiple targets and might be further improved by completing the shallower Wasatch formation tight sands on 20 acre density. The Wasatch alone, as we've said in the past, is probably not a candidate for widespread increased density from 40 to 20 acres, but some incremental reserves and some rate acceleration might lower the reserve threshold and improve the economics of the deep play.
As always, the caveat is that one well does not a play make. It's going to take a lot of wells to validate a play like this but we like what we've seen with our first Mancos to Dakota test and in fact, we're almost at total depth in our second Mancos to Dakota well and we plan to drill several more wells this year.
Turning to the Southern Uinta Basin. We've now drilled four wells on our Gar Mesa Flat Rock play. Our first well, the 100% Flat Rock 9P-36 is currently producing 2.2 million cubic feet a day equivalent and has already produced over 1 bcf of gas. We recently completed our second 100% working interest Flat Rock well, the Flat Rock 1P-36. This is a direct offset to the first well. It's currently making about 2.8 million cubic feet equivalent per day after about 20 days on line.
Our third well, the Wolf Flat 1P-1 well -- and this is the first under the JD with the northern Ute Indian tribe -- has averaged about a million cubic feet equivalent per day in the first 115 days on production and is currently making about 800,000 cubic feet equivalent per day. We have a 50% working interest in this well. We've also drilled, cased, and started testing a fourth well in the area. This is a 75% working interest wildcat. Note that it's located seven miles south of the Flat Rock area.
Just a reminder, under the terms of our deal with the Ute tribe, Questar has leases covering about 12,500 acres of tribal minerals and the tribe has the right to participate in the first well in each section with up to 50% working interest.
Let me turn to the mid continent. First quarter production was up 26% from a year ago. Our experienced teams are doing an outstanding job, replacing decline and growing production in mature areas. Our tight gas play in the Elm Grove field is driving the mid continent growth. We started this year with an inventory of over 100 operated well locations yet to drill at Elm Grove, with an average working interest of about 86%.
Note this, our current inventory could be about 50% larger. As we continue to develop our Elm Grove leasehold, our comfort in increased density drilling has increased. As a result, we now estimate that we have about 148 operated locations and another 105 non-operated locations yet to drill at Elm Grove.
Briefly comment on Wexpro. Under the 1981 Wexpro agreement, you know Wexpro recovers its costs and earns an unlevered after-tax return of approximately 19 to 20% on its investment base. In the first quarter of this year, Wexpro invested $12.2 million, which increased the investment base to 214.5 million on March 31, 2006. And that's 28.8 million or about 16% higher compared to the first quarter, or the end of the first quarter, '05.
During the first quarter, Wexpro produced almost 11 billion cubic feet equivalent on behalf of Questar Gas at a cost of service far below current market prices. The good news for both investors and for our utility customers, Wexpro has identified about $700 million of new investment opportunities that should drive continued growth in the investment base and therefore growth in net income while helping to keep Questar Gas rates among the lowest in the country.
Let's turn briefly to our regulated businesses. I hope you took note that Questar Pipeline earned a record 11.4 million in the first quarter, that's up 37% from a year ago. There were four factors. Number one, higher revenues from new firm transportation contracts in both the Southern system expansion project and on Overthrust pipeline. Two, operating improvements, including increased park and loan revenues and lower fuel gas consumption and NGL handling costs. Three, higher gas liquids prices. Under the settlement agreement with shippers last year, we share incremental liquids recovered at the Clay Basin in Kastler plant. And finally, ongoing costs reduction is flowing straight through to the bottom line.
Questar Pipeline also has a busy summer ahead. In the first quarter we finalized a 20-year contract to build and lease to pipeline sponsors the -- to the Rockies Express pipeline sponsors the western-most segment of Rockies Express pipeline, that goes from the Opal hub to the Wamsutter hub in Southwest Wyoming, and we will utilize capacity on our existing 36-inch Overthrust pipeline. This summer, we're going to extend Overthrust west to Opal and then next year we'll extend Overthrust east to Wamsutter.
Also in the first quarter, the Questar pipeline finalized a 12-year contract with Wyoming Interstate, WIC, for firm transportation of 125,000 decatherms per day from Opal to Kanda for delivery into WIC. To do this, we're going to install 5,800 horsepower of new compression to move the incremental volume through the Overthrust expansion.
Questar Pipeline also expects to finalize long-term contracts for another $58 million expansion of its Southern system from the Uinta Basin. That's a core Questar producing region in eastern Utah, which interconnects with Questar Gas, our utility, at Price, Utah, and Questar -- or Kern River pipeline at Goshen in central Utah.
In short, our pipeline company's task is to identify and eliminate bottlenecks in our core Rockies producing basins and I think the first quarter results show that they're executing well.
Turn briefly to our utility. Questar Gas net income was essentially flat in the first quarter compared to a year ago after adjusting for the settlement of the gas processing dispute. For the trailing 12-month period our utility earned a 10.9% ROE. That's below its 11.2% allowed return.
First quarter results benefited from strong customer growth in Utah. At the end of the quarter we were serving over 834,000 homes and businesses. That's up 4.2% from a year ago. But on the downside, high prices hurt utilities like Questar Gas. Of course, that's contrary to what the public believes. Average temperature adjusted usage per customer declined about 2% in the first quarter compared to a year ago. As you would expect, our customers responded to high prices by cutting consumption. Utilities like Questar Gas make money on the volume of gas we deliver to customers, not on the sales price of natural gas.
Of course, some customers respond by -- some customers had difficulty paying their bills. So bad debt expense was also up in the first quarter. That's another predictable consequence of high prices.
In summary, Questar's off to a good start in '06. We'll come out of the winter drilling season at Pinedale with about 33 wells to complete this summer. We're gaining confidence in our Vermillion Basin play. Well performance thus far appears to be repeatable and costs are coming down.
In the Uinta Basin, we are intrigued by our initial test of the Mancos Shale on our core acreage. The first well looks pretty similar to our Vermillion wells and unlike the Vermillion, in the Uinta Basin Deep Play, we have uphole reserves that may boost economics.
Our seasoned mid continent team once again surprised on the upside replacing decline and posting 26% production growth. Our midstream business posted double-digit growth on top of 70% growth in '05. Questar Pipeline had by far its best quarter ever. High prices hurt our utility, but despite declining usage, we're still earning near our allowed return. I want to thank you for joining us today. Thanks for your interest in Questar, and now we'll be glad to take your questions.
Question-and-Answer Session
Operator
Thank you, sir. Operator Instructions. Our first question comes from the line of Sam Brothwell with Wachovia Securities.
Q - Sam Brothwell
Hi, good morning.
A - Keith Rattie
Good morning, Sam.
Q - Sam Brothwell
Keith, refresh my memory. Had you talked about your drilling plans in Vermillion previously? I know you said on this call that you're planning to drill 12 this year.
A - Keith Rattie
Yes, we have, Sam. That 12 number is really unchanged from what we discussed in our first-quarter call. We're now drilling ahead on our seventh and eighth wells. We have the rigs basically in the queue to drill several additional wells. Some of the locations that we're going to drill this year are going to be on a map, we're going to post on our website later today.
Q - Sam Brothwell
Right. And I guess my second question is, as you continue to accelerate the development of the E&P business and you're also ramping up development in your pipeline business, we're continuing to see good growth in both pieces. Have you looked at -- have you revisited the whole question of restructuring the company along those functional lines at some point in time?
A - Keith Rattie
We look at that on a pretty regular basis, Sam. It's frequently discussed with our board. We have no plans to restructure at this time, but we are focused on value creation and if restructuring -- if it becomes apparent that we're going to have to do something different with our structure to realize the value of this unique set of assets, then you can count on this management team to do just that. We think we've got a lot of low-hanging fruit in our pipeline business, just to use them as an example. You've seen some of the projects we've executed in the last 12 months or so and you've seen the first-quarter results, we've got several of those types of projects that they're generally de-bottlenecking projects in our core producing basins in the Green River and the Uinta Basin. And we believe if we execute on that, shareholders will realize the benefits. But restructuring is something that's always on the table for discussion. No plans to do anything at this time, but plans can always change.
Q - Sam Brothwell
Okay. Thanks, Keith.
Operator
Our next question comes from the line of Scott Soler with Morgan Stanley.
Q - Scott Soler
Hi, good morning. Keith, I had a few questions. One was around the hedging policy and hedging basis is -- with Rockies basis right now averaging approximately $1.75 on average with Henry hub, and your estimates have continually been that you would -- to be conservative, model two and a quarter. Is -- to my recollection, you've historically hedged net to the well head on what your estimates are for the 12 months of PDPs more or less? And –
A - Keith Rattie
That's correct.
Q - Scott Soler
-- given the confidence that it seems like you have around -- or increasing confidence that you guys have around the success in your production, is -- why not hedge the basis more aggressively at $1.75 or so over the next couple of years to give you a bit more protection against -- and then once we get these pipelines up and running in '08 to 2010 in the Rockies, basis should come back in, but that was my first question.
A - Keith Rattie
Scott, some of us around the table probably wonder if you were in our recent planning meeting, because we had a pretty sensitive discussion about that topic. The -- our analysis shows that there's significant basis risk over the next two to three years for Rockies producers. Current basis, as I noted in my remarks, is significantly wider than it historically has been and that's the market's way of saying we need more pipe, it needs to get built, and it's got to get built fast. The most important project for Rockies producers on the table today is the Rockies Express project. That -- the sponsors have publicly said they're on track to build that in stages over the next several years. I think the full extension all the way to Clarington will be in place if they stay on schedule in late 2008. If that project slips, you're going to see basis significantly wider than what the current market is. We, historically, have shunned basis hedging in favor of using simple fixed-price swaps, which give us a known price for a fixed volume of equity gas at the relevant pipeline sales point. But given the fundamentals right now, we are warming up to the idea of doing a little bit of basis hedging. Unlike the swaps that we use, these would not be cash flow hedges under FAS 133. And our reluctance to use basis hedging has been in part because we don't want to introduce a little bit of uncertainty in the quarterly earnings, as you mark to market the basis hedges. But it's something that -- you should not be surprised if we do a little basis hedging at some point down the road, to reduce that risk.
Q - Scott Soler
Yeah, I think locking in better returns on capital and free cash flows probably more important. But the second question I had is, on your production growth for the first quarter, I know that there was a number of wells which were completed in the first quarter which made the production growth numbers very strong relative to a year ago. Long term you tend to guide people to the fact that Questar's goal is to grow production at a rate of at least 10% or so a year. Is there anything that's an inflection in the first quarter that might set you to be a little more comfortable on a higher rate of growth long term, or should that not be over read and extrapolated?
A - Keith Rattie
I would caution you not to over read and extrapolate that, Scott. We executed very well in the first quarter. We had some problem wells. You always do. But none of them significant. This is a tough business. You've got uncertainty about rig availability, you've got challenges sometimes with permits and access. But to the first quarter -- in fact, the last three quarters, as I noted in my remarks -- have been very strong. Our team is executing well. We've got a big inventory of identified wells to drill in our core plays. And for the next few years, it's really all about execution.
Q - Scott Soler
Okay. Then my final question, Keith, is, I was just trying to reconcile a couple of numbers. When -- back last -- late March or so of '05, when you -- when the fompany first estimated -- that full examination of 2-P, 3-P, the estimation was a little over three trillion cubic feet. And then that was updated, obviously, this year, when you filed your 10K to 3.4 trillion cubic feet. But that's not a big change and I guess what I'm trying to get to is on March 9th of '06, on the Wyoming BLM's web site there was a petition for 4,000 locations on 153,000 acres on most of that Vermillion acreage. And so when the initial assessments were made early '05, it doesn't seem as though -- I mean, you all had not done any significant testing in the Vermillion and so it -- I don't think there's a lot of what might be out there long term in the 3.4 TCF. I just want to double-check that. Because I was going through our notes and also looking at that filing on the website and trying to reconcile the assessment of what the reserve potential –
A - Keith Rattie
Your basic assessment is correct. I'm going to let Chuck add some color to that, Scott. Thanks for the question.
Q - Scott Soler
Okay.
A - Charles Stanley
Scott, keep in mind that the -- when we issued the 2 P, 3 P release last year, we had not yet turned our first well -- new well to sale. So, we had no direct evidence of commercial productive capacity in the Baxter or the Frontier Dakota. As we stated earlier in our year-end conference call, it's our intention to update the probable/possible assessment. We are delaying it a little bit because we wanted to collect important information from these wells that we're currently drilling in this season's drilling campaign before we do that, but, obviously, the results that we recovered to date from the wells would suggest that the number will go up substantially as we go through the exercise later this year.
Q - Scott Soler
I mean Chuck, as a sample size, when you have fairly consistent production, how many test wells do you typically do to then extrapolate off of a given sample? Because I recall the last time I met with you in person -- or the last time we at least went on the field trip back in the -- last summer, I think there was something like 15 test wells would be enough to get enough -- you know, to build very good type curves to get a better assessment. Has that changed, or is that --
A - Charles Stanley
Not really, Scott. You know, there's two things. One is time. We need sufficient time to get comfortable with the absolute shape of the production decline curves in each of these wells, because as you know it's the shape of that curve and really, where the decline flattens and how flat it actually is that ultimately determines the per well reserves. And then the second thing that's very important is spatial sampling. And very important in the spatial sampling is going further down dip. Right now most of the wells that we've drilled have been on or slightly off the crest of the structure, the Trail 31 well was the most down-dipped well we've drilled. We'll put a map out later on today and you will see that we're going to drill a well smack dab in the middle of the area between Canyon Creek and Hiawatha, which will be a definitive well to prove that there's gas down-dip of the Trail 31 well that we've drilled. In order to convince our independent reserve evaluators, Ryder Scott, that the larger area can be classified as probable, we have to prove the presence of producible gas down dip of these wells. And that's the spatial sampling element that we need to do next.
Q - Scott Soler
Okay. That's clear. Thank you.
Operator
Our next question comes from the line of Jay Yannello with Pali Capital.
Q – Jay Yannello
Good morning. Most of my questions on Vermillion were answered. I just have a quick petty question. The $1.57 does that include the settlement of the Questar Gas dispute and the gas imbalance?
A - Keith Rattie
Yes, it does Jay.
Q – Jay Yannello
Okay. How much is that roughly?
A - Keith Rattie
I don't know -- I don't think we have a net income impact of the 7/10th bcf equivalent. It wasn't very -- it wasn't significant.
A - Charles Stanley
About a million bucks.
A - Keith Rattie
About $1 million, so about a penny. The gas processing dispute you recall was -- the order was issued in the fourth quarter of last year. Under that order we were allowed to recover gas processing costs going back to the 1st of February last year. So there was only one month in the first quarter of last year that we didn't have that.
A - Charles Stanley
Million bucks.
A - Keith Rattie
That number was about $1 million, too. So if you want to put those two together, that's about a penny each.
Q – Jay Yannello
Okay. I guess -- you talked about the basis differential and the risks going farther out. On '08, should we expect throughout the normal course of business as we work further through '06, that you'll be lobbying on some additional hedges, subject to the risks with basis? Because we're still seeing some good pricing out there and you're still moderately to significantly unhedged in '08. Can you just give us a little more flavor on how you'll be thinking about '08 through this year?
A - Keith Rattie
We're going to continue to add hedges when the market gives us the chance to lock in the returns in margins that we need to keep the pedal to the metal on our E&P program. The market is currently giving us that opportunity. One of the things that you will note that we've done in the last couple of years is we're being careful not to go too far out with our hedges because there's a lot of volatility that can occur and generally, we try to avoid hedging too much into back gradation. But '08 right now, those prices are currently attractive and basis is consistent with what we would see as attractive from a return on capital, cash flow, and margin standpoint. So you should see us continuing to take some of that risk off the table over time.
Q – Jay Yannello
Okay, guys. Congrats. You've got a lot of great things going on.
A - Keith Rattie
Thank you, Jay.
Operator
Our next question comes from the line of Shinur Gershuni with UBS Securities.
Q - Shinur Gershuni
Hi. Good morning, guys. Great quarter. Just had a couple questions. Some of the previous callers asked most of mine. That said, with respect to the Vermillion Basin, have you seen an improvement in cycle times as you've drilled each new well and have you been able to reduce your costs and so forth? And if possible if you can update us as to what it's costing currently to drill at this point?
A - Keith Rattie
I'll let Chuck handle that one. The answer is yes.
A - Charles Stanley
We're still in the jumping around phase, as I would describe it. We're -- when I answered Scott Soler's question, we're trying to delineate the aerial extent of this place, so there's a lot of cost involved in moving the rigs. The rigs that we're using right now are sub-optimal for full-scale development. They move in a lot of truckloads, they're slow to take apart, slow to put back together. And we're not pad drilling. We're drilling single wells from single surface locations to delineate the aerial extent of the play. So there's a lot of delay and costs in moving -- in rigging up and rigging down. That being said, we're seeing a significant decrease in the number of days it takes us to drill each well. We had a breakthrough starting with the Canyon Creek 61 well, continuing with the Trail 31 well, that proved to us that using PDC bits could substantially increase the rate of penetration and therefore reduce the number of days to drill. So we're driving down the cost. We're still doing things in these wells that we would not do as a matter of routine in the development well, like testing some individual zones separately rather than doing full completions, which is driving up the costs. Prices -- costs right now are $4.5 to $5 million. We think, obviously, there's a lot of economies of scale and there's also a lot of technology yet that I think that we can bring to bear to drive down drill times and therefore drive down costs. So stay tuned. We have a group of people who have proven that given time and their focus, they can bring down drill time substantially as they've done at Pinedale and continue to do at Pinedale.
Q - Shinur Gershuni
So it's not unreasonable that if you were to pursue this play, that we could see drilling costs in the 3 million territory as you used more optimal equipment and so forth and as you learn to play a bit better.
A - Charles Stanley
I think that's going to be a stretch, given the current industry environment, because we haven't seen a stabilization of rig day rates and in fact new build rigs are 15%, 20% higher day rates than the current averages. So I'm reluctant to say that we can get them down in that range. I think a $4 million well is certainly achievable. We can probably do better than that, but there's a lot of variables out there right now. We are still optimizing our completion design and there's a lot of costs that potentially can come out of the completions as we learn more about how to stimulate these wells.
Q - Shinur Gershuni
During the prepared remarks, you guys had mentioned something about the effect of at 3.5 million, at $5 NYMEX, it was based on 3 bcf of gas and then if it cost 4.5 million, you would need 5 bcf of gas.
A - Charles Stanley
Four.
A - Keith Rattie
Four.
Q - Shinur Gershuni
Sorry, 4 bcf of gas. My mistake. Can I just linearly figure that out, if you were only able to recover 2 bcf of gas to figure out what your costs would be?
A - Charles Stanley
That's probably a reasonable way to do it. It's probably not a straight line but it’s close enough for --
A - Keith Rattie
It would be close enough for probably -- for purposes of what you're going to use it for right now.
Q - Shinur Gershuni
Okay. And just two final questions, and one of them is really just a continuation of Scott's question. You sort of -- in March of last year, you put out your 2-P and 3-P numbers. There was also petroleum resources there. My understanding is the Vermillion Basin wasn't even included in the petroleum resources number. Based on my notes and some research and so forth, assuming -- call it 400 bcf per square mile recoverability in the Vermillion Basin on 140,000 acres, if I work that through, assume you can only work, let's say, 30% of the area and just only a 5% recovery, I'm doing that math and I'm coming up with 1.5 to maybe even 2 TCF of potential recoverable reserves. Is there something wrong in the way I'm thinking about my math there?
A - Charles Stanley
I think you're a little high on your recovery factors. Typical shale gas reservoirs range from 5%, 10% recovery factor.
A - Keith Rattie
He said 5 –
A - Charles Stanley
So 5%'s okay. So yes, you're in the right range. The question ultimately becomes, at what density do you have to drill the wells to recover those reserves? Is it on 40 acres, 20 acres or 10 acres? And that ultimately drives the per well recoveries. And ultimately the economics. The other thing that I mentioned to Scott is we're still not sure if this is a structural play; i.e., that the gas is limited to the structures and only covers a portion of the acreage, or whether it covers a broader area. In answer to your question on the 2-P, 3-P, at the time that we released that information, we had a handful of old wells that had good gas shows and some very limited short duration drill stem tests. But we had no idea whether or not we could effectively fracture stimulate the Baxter and make it flow long term, as we've now demonstrated that we've been able to do. So I don't want to front run what we're going to do here with the 2-P, 3-P, but at the time we were -- we recognized that it was a potential resource. We didn't put a lot of credit on the old tests and now we see from evidence of modern wells that we can recover gas at economic rates here.
Q - Shinur Gershuni
Okay. Just one last final question. This is related to the basis argument. You'd mentioned earlier in the call that the completion of Rockies Express would certainly help the basis differential, and that if it slips, it certainly would negatively impact basis differential. Are there any other pipeline projects that are in the planning stage that you think that would help the basis differential coming out of the Rockies; i.e., I guess El Paso's Continental Connector project or any other project?
A - Allan Bradley
This is Allan Bradley. Continental Connector, of course, El Paso's project, moves gas from the Cheyenne hub in eastern Wyoming to the mid continent and on to the Perryville pipeline hub in northwest Louisiana, where the gas would be delivered into long haul pipes that move gas currently from the Gulf of Mexico to markets in the upper -- in the Middle East and upper -- the mid-part of the Eastern U.S. and northeast. There are other projects under discussion, but I would heavily discount the likelihood that they are going to be in service in the period that I think is relevant to your question.
Q - Shinur Gershuni
Okay. Thanks a lot. I really appreciate you answering all of my questions.
Operator
Our next question comes from the line of Richard Gross with Lehman Brothers.
Q - Richard Gross
Hi, good morning.
A - Keith Rattie
Hi, Rick.
Q - Richard Gross
I've got, I guess, a sequence of E&P questions here. The first is on Vermillion. When you're completing these new wells, are you completing them only in the shale, or are you still experimenting with a combination of sands, shales, and are they different in each well? Because when you talked about Uinta, you talked about having uphole zones from the shale that you don't have at Vermillion, so I'm confused as to what you're doing at Vermillion as far as testing these individual wells.
A - Charles Stanley
Okay, Rick. Chuck Stanley. The geology is a little different. The shale the Baxter Shale, which is equivalent to the Mancos Shale, it's roughly the same thickness, slightly deeper in the Uinta basin than in the Vermillion Basin. The uphold stratigraphy is fairly similar, but keep in mind that in the Vermillion Basin for years and years Wexpro and Mountain Fuel have developed the shallower Mese Verde and Wasatch equivalent section in the Vermillion Basin in the old Canyon Creek and Hiawatha and other fields. Wexpro still owns that interest, still drills and produces those sands, and so they remain a Questar core asset and a source of future investment opportunity for Wexpro. Significant future investment opportunity.
Q - Richard Gross
Okay. That's fine then. But as far as the Dakota and some of the deeper.
A - Charles Stanley
Okay. So the deeper section is slightly different. In the Vermillion Basin we have a well developed frontier section, a marine and fluvial frontier section that offers opportunities to complete most of the wells in the frontier section. Several of them the frontier's been pretty skinny and we've only stimulated a single zone. Several of them we've stimulated two zones. The Baxter is uniformly present and we typically put eight stages, eight frac stages, in the Baxter. The Dakota's hit and miss. In some places we have a well-developed Dakota sandstone. In other places we do not. And that I'm still talking about Vermillion Basin here.
Q - Richard Gross
Okay. So, when we're getting these flow rates and these decline rates, we're still getting a mixture of sands and shale in most of the wells?
A - Charles Stanley
That's correct, although we have deliberately completed and isolated Baxter only in order to gather Baxter-specific production rates.
Q - Richard Gross
Okay.
A - Charles Stanley
And Baxter-specific reserves. Now, going to the Uinta Basin, there is no well developed frontier section. It's all shale. The frontier is basically gone as a sandstone unit. There's a silt in the Dakota -- the upper part of the Dakota that we complete in, and then there are sporadic relatively low porosity sandstones at the basin of the Dakota. In this first well that we drilled in the Uinta Basin, we completed in the Dakota silt and also in the uphole section, the typical Baxter-like Mancos section.
Q - Richard Gross
Okay. And then go to the Vermillion again. From a standpoint of Vermillion, is it, if you make the decision to drill the Baxter horizontally, is that a second half of the year?
A - Charles Stanley
Yes, it is. And –
Q - Richard Gross
And will we have results from that by your typical November analyst review, the E&P meeting?
A - Charles Stanley
We hope to. It depends on which rig we choose to drill that well with. We'll show you the location that we're planning to drill it at. It'll be in the Canyon Creek area because we have a lot of vertical control there and we think we know where we want to target, the horizontal lateral.
Q - Richard Gross
Okay. My assumption also would be, then, if the horizontal is the way to go, that all of the well economics quoted earlier are beside the point.
A - Charles Stanley
They all change, that's right. Of course, the downside, which I think you were hinting at, is that you forego the opportunity to complete in the sands beneath the Baxter.
Q - Richard Gross
Yeah. Okay.
A - Charles Stanley
Now, just to clarify Keith's comments on the Uinta basin, the difference in the Uinta, obviously, is we do own the entire section above it and it's not segregated between Wexpro and Questar E&P. There is a significant amount of potential in the lower Mesa Verde as well as in the Wasatch, and if this deeper section works, we could potentially develop our existing acreage that's currently been drilled to the upper Mesa Verde and in some places only to the base of the Wasatch, on 40-acre density down to 20-acre density. Get some incremental reserves out of that shallow section, which helps the overall well economics to drill to the deeper Mancos and Dakota targets.
Q - Richard Gross
Okay. Jumping over to the Midcontinent real quick, a couple of one question, or one, maybe, observation. At Elm Grove you've been bumping the number of potential wells to drill. Under the current number that Keith quoted I think it was 148 plus 105 non-operated, is that principally on 160s, or is some of that 80s? My assumption is that none of it's 40s.
A - Charles Stanley
Some of it is on 40s. The northern if you will recall, our acreage in Elm Grove is in two distinct areas. The northern area we've already drilled to below 40 acre density. In fact, I think the average well density there's about 32 acres or so.
Q - Richard Gross
Yeah, okay. What about the bigger southern block.
A - Charles Stanley
The bigger southern block is currently developed on less than average on average of less than 160 acres. The numbers that we're quoting assume that we go to 40-acre density and the only reason that we're not saying that we'll reduce below that is we don't have enough subsurface data yet to get comfortable. But we're pretty sure on that acreage that ultimately we'll end up at 40-acre density.
Q - Richard Gross
Okay. And then the rest of the Midcontinent, you were worried about getting rigs. Is it possible that you're actually doing better than you thought because of forced pooling, other people have rigs and you're joining?
A - Charles Stanley
We're certainly -- that's a good observation and, yes, it's true. We're certainly seeing a lot of outside operated well proposals that we are participating in and we've also picked up a couple of rigs. We've identified now and gotten comfortable with an inventory of wells in the Anadarko Basin and have picked up a rig that we're using well-to-well now, but we've got tied up for the foreseeable future, which is really helping sort of stabilize our development plans out there.
Q - Richard Gross
Okay. Then you mentioned an Arkoma wildcat that was successful. Is that either the thesis, is that extrapolatable, or is the wildcat discovery got significant legs on development?
A - Charles Stanley
There are some offsets to it. In fact, we've got one drilling right now. The size of it will be limited. I mean, the typical mid continent type play, we don't have an extensive acreage position rig. It's important because it was a higher rate well. It was as averaged about 6 million cubic feet a day gross and we have about a 94% working interest in the well. So it was a significant contributor to our eastern mid continent production during the first quarter, and certainly needs to be pointed out.
Q - Richard Gross
Okay. And then the last thing was going back to Pinedale. You're currently drilling from pads, and with kind of extended reach you can get so many wells and as you drill off of these pads, do you have an expectation as to in effect when you would run out of locations from the existing pads let's assume you don't go deep and then, does that push you toward maybe, as we've kind of talked about before, maybe doing a five-acre pilot this year?
A - Charles Stanley
Well, we believe that we currently have the number I think we have now constructed all of the pads necessary to develop this field, regardless of the ultimate subsurface well density. We may need a couple of more pads in the southern area where we haven't drilled the sort of southwestern panhandle of our acreage extensively, but in general our plan going forward is to simply enlarge the existing pads to accommodate more surface facilities and well heads if we go to increased density. We will likely do some piloting on five acres this year in order to make a determination, ultimately, because obviously it's much more economic and much more efficient to determine the ultimate subsurface density and drill the wells while you're on the pad rather than moving off and then coming back later to drill infill wells at 5-acre density. There's also a good likelihood that some of the sands will be in communication from well to well and obviously drilling through partially depleted sands causes additional drilling headaches if you wait.
Q - Richard Gross
Okay. And then one last - going back to Uinta Flat Rock area.
A - Charles Stanley
Yeah.
Q - Richard Gross
When you mentioned you're drilling an offset, is that an offset a mile away? 640 acres, or is that -- how am I --
A - Charles Stanley
These are 160-acre offsets.
Q - Richard Gross
It is the 160 acre offsets. Probably too early to tell whether you will down space.
A - Charles Stanley
Probably not much lower than 160 at this point until we get more production data.
Q - Richard Gross
Okay. Thank you very much.
A - Charles Stanley
You bet.
Operator
Our next question comes from the line of David Thickens with Deephaven Capital.
Q - David Thickens
Good morning. I applaud you guys on the call and the amount of information coming out of this call. Thank you. Most of my questions have been answered, but a couple of specifics. How much of the Vermillion acreage is controlled by Wexpro?
A - Charles Stanley
That's a, that's a difficult question to answer. The acreage is actually vertically segregated, so there are old, shallow fields that Wexpro owns and operates and Questar E&P has the development rights beneath the current shallow production.
Q - David Thickens
So the stuff that you've been testing recently has all been Questar E&P?
A - Charles Stanley
Actually, no. Some of it has been -- has basically been -- Wexpro shallow minerals that we drill through and then are developing the deeper section, which is the 100% or 70% Questar E&P owned and Wexpro owns nothing.
Q - David Thickens
Okay, okay.
A - Charles Stanley
The mechanics the operation of the Wexpro agreement segregates Wexpro's ownership vertically and laterally to known, existing, producing reservoirs.
Q - David Thickens
Okay. But most of the targets that we have been talking about in these 12 wells you're drilling this year are largely Questar E&P.
A - Charles Stanley
They are Questar E&P either 100% or Questar E&P and working interest partners, and we have basically one working interest partner in the area that in some places is up to a 30% working interest.
A - Keith Rattie
But not Wexpro.
A - Charles Stanley
But not Wexpro.
Q - David Thickens
Okay. Kind of overall, how much -- I mean, can we just kind of average the zero to 30%? And if we're trying to figure out how much of this potential –
A - Charles Stanley
Our working, our average working interest in the section that we're targeting here is 90 plus percent.
Q - David Thickens
Okay. Fair enough.
A - Charles Stanley
In the deep section.
Q - David Thickens
Fair enough. And can you touch a little bit more -- I know Keith and Steve and I talked about this a little bit down in New Orleans, but talk a little bit more about what you think the realistic probabilities of accelerating your drilling rates are.
A - Charles Stanley
In which area?
Q - David Thickens
Well, you could kind of go down them.
A - Charles Stanley
Well, you know, I think the -- it's amazing to me that we've been able to cut drill times in places like Pinedale, 67 days down to 47 days down to -- now wells in the low 40s to upper 30 days and it's all about eliminating loss time, loss motion and focusing on drill bit design and optimization. We've been working with drill bit manufacturers to come up with new cutter designs on bits and searching for specific bits to drill certain parts of the geology out there, and once we find a bit that works well then obviously we stick to it and then further tweak it. That's the key to any kind of resource play and that's the ability to drive out cost, which further enhances economics. And drilling programs like Pinedale and like other plays like the Vermillion Basin, you're afforded the opportunity to repeatedly drill the same section over and over again, and just like any kind of manufacturing process, you can find ways to improve it over time. That's key to the success of any resource play and that's our focus. We also obviously focus on completion technology to reduce the number of days between the time a well reaches total depth and the time we sell our first molecule with gas. And those things together drive down well costs. We've seen the same kind of improvements out of our Elm Grove program. It used to take us about 30 days to drill a well there, it now takes us about 10 days. And if you have been out in the field with us and you have seen the culture of focus on cost and on time savings, you would see how we do that.
Q - David Thickens
All right. Thank you very much. Great quarter.
A - Charles Stanley
Thanks.
Operator
Our next question comes from the line of Carl Brown from Cramer Rosenthal.
Q - Carl Brown
Hi. Keith, I had a question for you. I know you get a lot of questions about the corporate structure and I know you've talked about the operational benefits of being somewhat integrated. I was curious if you think that there's a strategic downside to separating the companies. Because what I'm thinking is the motivation would be presumably, the reason to do that is because you think you're not getting full value for the E&P business. But I feel like if you were to do that and you look at the upside on the E&P business with Vermillion, 4,000 wells at 3 to 4 bcf per well is obviously a huge number, a huge target to be going after. Uinta Basin seems to be catching up and looks to be shaping up very nicely, and then you've got the remaining pieces of your 980,000 net acres in the Rocky Mountains. It seems to me like the situation that I worry about is the bulk of that upside being realized by shareholders of a different company. And I'm wondering if having the regulated entity in the mix, does it give you an extra line of defense against that scenario playing out in some fashion?
A - Keith Rattie
I don't know if I'd characterize it as a defense. We are very focused on value, as you've heard us say, Carl, many times. We think with a mix of businesses we offer a lower risk way to invest in natural gas. We think that if you look at cash flow, for example, about 50% of our cash flow is not particularly sensitive to commodity prices. And we manage the commodity price exposure in the other 50% with our hedging program when prices are attractive. The question is one that we answer all -- we try to ask all the time and try to answer honestly and we're looking at whether or not there's a consistent gap in the implied value of the sum of the parts versus the value that we're getting from the mix of businesses as a whole. The challenge of course is trying to figure out what's the relevant time period. If you look at that on a 30-day basis, it gives you one answer. If you look back over the last five years and look at the performance of the mix of businesses in both higher price environments and lower price environments, we tend to perform pretty well over a full cycle. The other factor that you mentioned, Carl, as we've discussed, is that our business is, or the mix is somewhat unique in that we are very physically and commercially integrated, focused on the Rockies. We have a pipeline company that's sole mandate is to identify and eliminate bottlenecks in pipelines in our core producing basins in the Green River and in the Uinta basin. The gathering business really runs hand-in-glove with our E&P business. Chuck has responsibility for both segments. If he is ready to flow a Pinedale well that's going to make initially over 10 million cubic feet a day, if that gathering line's not there and the processing deal's not in place, he knows whose neck he can grab to deal with it. When you're dealing with third parties, they see risks associated with working with an E&P company and those risks get priced into gathering, both in terms of gathering rates and often times delay in getting the facilities in place to flow the gas. At some point, it may no longer be arguable that we get significant benefits from having affiliates work to try to add value to our E&P strategies, and of course when that day comes, then the structure issue is one that needs a serious look.
Q - Carl Brown
Thanks. And a follow-up. On the 4,000 locations that were filed for, it seems like the math works out to that's roughly 40-acre spacing across the entire acreage position. Is that the methodology behind that number? Or does it imply tighter downspacing on a smaller portion of the acreage? Could I know that the draining radius you've been seeing on these wells is really tight right now?
A - Charles Stanley
Carl, it's Chuck. You know, we don't know yet. We haven't done enough closely spaced drilling to determine that. We had to start out with a number. We chose a number that we thought would cover our activities for the foreseeable future. And ultimately, the geology will determine what the spacing is.
Q - Carl Brown
Okay. And finally, on the map that you're going to show us later on today. Will that have where the horizontal will be drilled?
A - Charles Stanley
Yes. And it's going to be basically right in the guts of where we've drilled those Canyon Creek wells already.
Q - Carl Brown
All right. Thanks very much.
Operator
Our next question comes from the line of Joe Magner with Petrie Parkman.
Q - Joseph Magner
Thanks for all the information on today's call. I'm not sure I have any additional -- one question. The deep gas play in the Uinta basin, you threw out a few different horizons, Mancos, Blackhawk, the lower Mesa Verde. What sort of things, what sort of characteristics are you looking for within each of those horizons and what sort of reserve contribution might we expect or might you expect from the different horizons? Do you know enough yet?
A - Charles Stanley
Not really. I'll give you a little color. The first thing we're looking for that I think is absolutely important in these -- especially the shale gas play, is overpressure. Overpressure drives gas in place, overpressure is necessary, in our minds, to generate sufficient reservoir energy to efficiently unload the large volume of water that we've put away in these slick water fracs when we stimulate the shales. Talking about reserve potential is just right now what we're seeing with initial rates in the Mancos would indicate that these are -- these wells probably going to recover one to two bcf or more just from the Mancos section. The Dakota silt and potentially Dakota sands, too soon to tell. We just don't have enough information. You know, the Blackhawk sands, from our experience, can be pretty good reservoirs. So we have one very good Blackhawk well and several other wells that have recovered in excess of a bcf. The very good wells probably going to be four or five bcf well, just from the Blackhawk. There's certainly variability across the acreage. We don't pretend to understand it yet. It could be a natural fracturing, it could be inherent reservoir properties that we just don't have enough information to decipher. Shallower, the lower Mesa Verde, upper Mesa Verde, together could add another B or two of reserves. So, ultimately on a risk basis we could be exposing ourselves in one of these deep well bores to four or five bcf per well, which certainly, at least at first blush, looks to be intriguing. But as Keith said in his remarks, one well does not a deep play make. We've got another well that's drilling below 6,000 or 16,000 feet this morning, on its way to 16,700. We'll get that well down, hopefully sometime this weekend and get it cased and we'll have another data point. But we need a lot more information.
Q - Joseph Magner
Okay. Thanks for that. And then to go back to the 2-P, 3-P study. Did that include any of the resource potential in the Flat Rock area? It seems to me that came together after that study was done.
A - Charles Stanley
No. We didn't have the acreage at that point. We hadn't drilled our first well.
Q - Joseph Magner
Okay. And what was the plans that drilling plans for that area going forward? You're drilling your fourth well now, but what should we look for?
A - Charles Stanley
Well, we've TDed our fourth well. We want to evaluate that well and learn from the results before we make our next move, but it will likely be to test another one of the Wildcat prospects on the 12,500-acre EDA lands that we have with the northern Ute tribe.
Q - Joseph Magner
Okay. Thank you.
Operator
Our next question comes from the line of Faisel Khan with Citigroup.
Q - Faisel Khan
Good morning.
A - Keith Rattie
Good morning, Faisel.
Q - Faisel Khan
On the production guidance, does the -- how many of the Vermillion wells that are you're currently drilling has the guidance included in production?
A - Charles Stanley
Faisel it ladders in the remaining wells that we have in our total of about a dozen that we'll drill out there this year, and the first well that Keith enumerated in that list was the Canyon Creek 47 well. So we've drilled, so far, three. We have two currently drilling ahead and so we have seven left to drill for the remainder of this year and they'll come on sequentially throughout the remainder of the year.
Q - Faisel Khan
Okay. And then just quickly on the deep well at Pinedale. You guys secured, I guess you call it a snub unit and crew, to fish out that obstruction?
A - Charles Stanley
Right. We have a snubbing unit moving on the location and should be ready to start cleaning it out sometime in the first week of May.
Q - Faisel Khan
Great. Thank you very much.
Operator
Our next question comes from the line of Carl Kirst with Credit Suisse.
Q - Carl Kirst
Good morning, everybody, and thanks for the time here. I think all of my questions have been hit, just to kind of clean up, the first is from a very 30,000-foot standpoint, as we are looking at the production profile throughout 2006, you obviously have a good amount of development wells coming in for the second and third quarter. Should we then take that that there shouldn't be any dip here sequentially from first quarter?
A - Keith Rattie
No. We -- I think -- I tried to clarify in the remarks that our production will decline or could decline in the second quarter of this year. I won't say that we can overcome it, but it typically does because we have winter access restrictions at Pinedale, for example, that result in no completions being added in the first until late in the second quarter, and really, that production doesn't start to impact our results until the third and fourth quarter.
A - Charles Stanley
And keep in mind, Carl, that we have -- the majority of our acreage is federal leases in the Rockies and as a result, there are restrictions on a lot of the acreage that impact our ability to turn wells on until the summertime. So Keith's right. We still have an inclined solid tube production profile and you should anticipate a decline in production basically from our fourth quarter of each year through the third quarter of the subsequent year.
A - Keith Rattie
That obviously doesn't mean that on a quarter-to-quarter, year-to-year basis, you should count on some volume growth.
Q - Carl Kirst
Great, okay. Now appreciate that clarification. Then just lastly, on Pinedale. Given the amount of the efficiencies and reduced cycle time that you guys continue to eke out here and I guess we're going to, what, nine rigs here for this summer? And I don't know if that's going to stay around for this winter, but, geez, it would seem that if you average eight rigs next year at even only 45 days you get a 50% bump in what you'd be able to drill at Pinedale next year.
A - Charles Stanley
That's good math. Keep in mind that, number one, we had an exception last winter that allowed us to put a seventh rig out there. We don't anticipate getting that again next winter. So we'll only have six rigs working through the winter instead of seven. Secondly, you need to build into your analysis the fact that these rigs have to ultimately move from one pad to the next and that takes time to rig-down, move, and rig-up. So in between wells on a pad, the skidding of the rig is a fairly quick and easy thing to do because you don't take the rig apart. But there is a time lag that you need to factor in, in moving from pad to pad.
A - Keith Rattie
Third point I would add to that, Carl, you also have to keep in mind that Wexpro has a significant amount of that inventory of $700 million of identified new investment. And Wexpro is at Pinedale. And of course, Wexpro volumes are not included in the Questar E&P volumes that we report.
Q - Carl Kirst
Correct.
A - Keith Rattie
At one of the rigs -- the 7th rig we added this year was really drilling on a Wexpro operated location.
Q - Carl Kirst
All right. Well, great. Congratulations and good luck.
Operator
Operator Instructions. Your next question comes from the line of Monroe Helm with CM Energy Partners.
Q - Monroe Helm
Great numbers, and congratulations on a great inventory to drill over the next few years.
A - Keith Rattie
Thanks, Monroe.
Q - Monroe Helm
Just had one additional question that has to do with this deep -- what you're trying to do on this deep test at Pinedale. Once the snubbing units got this obstruction removed and you get a chance to test this particular well, is there a chance that you would do any additional deep tests on another well here this summer?
A - Charles Stanley
Monroe, Chuck Stanley. This is the only well we have drilled to total depth in the Hilliard and Rock Springs. Our plan for this well is to -- depending on what we find when we go in to clean out the obstruction, if it's just a small, relatively isolated obstruction, resume testing the Hilliard Shale to see if we can establish a stabilized rate. If, however, we find that the well bore is filled with debris from the Hilliard Shale, it would probably be unlikely to go back to that zone -- we'll probably put a plug over it -- and come up and test a series of sandstones similar in nature to the overlying Lance Pool Sands, stack lenticular sands in the Rock Springs formation by multistage fracture, stimulating, and testing those zones. We at Questar want to see the results from this well and understand what it means before we initiate drilling another deep well.
Q - Monroe Helm
Okay. Sure. One other question last year you’re drilling -- for '05, your drilling program, you'd been drilling a lot of PUD so the reserve adds weren't as significant as they would have been otherwise. Is the drilling program this year going to be oriented toward fewer PUDs?
A - Charles Stanley
By nature of the sort of logical development of this field, with pad drilling, directional drilling of spottable locations, we will drill a substantial inventory of PUDs going forward. We're not moving our drilling rigs around simply to manage reserve growth. Well we know the gas is in the ground. We can record it in non-proved categories for investors. Hopefully investors will understand that our decision to develop the field is one based on economics and on reducing well costs rather than just managing proved undeveloped reserve growth to meet some imaginary metric.
A - Keith Rattie
Just to put some additional numbers on that, Monroe, at the end of the year we -- of the 932 identified locations, we had 788 yet to drill. Of those 788, 585 had not yet been booked. And in the last call we gave you some reserve estimates. Again, these are only for Questar E&P. We estimated that proved, probable, and possible at Pinedale is north of 2 trillion cubic feet with about 870 bcf equivalent of that in the probable category. Pretty high quality probables.
A - Charles Stanley
To put the cost in perspective, it costs about $0.5 million to rig down a drilling rig, move it from one pad or one location to another, simply to add some proved undeveloped reserves, and since we are a successful effort shop, these proved undeveloped reserves come into the leasehold pool at Pinedale, which has a de minimis impact on DD&A rate and earnings. So, probably less than a penny, a penny and a half, of ultimate impact on our DD&A rates. So, we just don't think it is prudent management to go out and move a rig around, simply to add PUD reserves.
Q - Monroe Helm
Right. Okay. Well, thanks for all the great comments today, and good luck.
A - Keith Rattie
Thank you.
Operator
At this time there are no additional questions.
Keith Rattie, Chairman, Chief Executive Officer
Okay. Very good. Well, we appreciate your interest. You can -- you can get a copy of our earnings release on our website. We are going to post that map later today. We're going to be back in New York and Boston in May and look forward to seeing some of you all then. We'll also be at some other conferences over the next month. Thanks for listening in.
Steve Parks, Senior Vice President; Chief Financial Officer
Brian, if you could now, we'd like to ask you to provide information on how to access the recording of today's presentation.
Operator
Thank you, ladies and gentlemen, for participating in today's Questar Corporation First Quarter 2006 Earnings Conference Call. This call will be available for replay beginning at 11:30 a.m. Eastern time today through midnight on Thursday, May 4th, 2006. The conference ID number for the replay is 421-1224. Again, that conference ID number for the replay is 421-1224. The number to dial for the replay is 1-800-642-1687, or internationally 706-645-9291. Again, the number to dial for the replay is 1-800-642-1687 or 706-645-9291.
This does conclude today's conference call. You may now disconnect.
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