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Ultra Petroleum Corp. (NYSE:UPL)

Q3 2007 Earnings Call

October 31, 2007, 11:00 AM ET

Executives

Kelly L. Whitley - Manager, IR

Michael D. Watford - Chairman, President, and CEO

Marshall D. Smith - CFO

William R. Picquet - VP, Operations

Stephen R. Knelle - VP, Exploration Domestic

Analysts

David Tameron - Wachovia Capital Markets

Brian Singer - Goldman Sachs

Brian Kuzma - JP Morgan

Richard Tullis - CapitalOne Southcoast

Clay Cummings - Johnson Rice

Subash Chandra - Jefferies & Company

Noel Parks - Ladenburg Thalmann

David Heikkinen - Tudor Pickering

Raymond Deacon - BMO Capital Markets

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2007 Ultra Petroleum Earnings Conference Call. My name is Nicole and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will conduct the question-and-answer session towards the end of this conference. [Operator Instructions]. As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the call over Ms. Kelly Whitley, Manager of Investor Relations. Please proceed.

Kelly L. Whitley - Manager, Investor Relations

Thank you, operator. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's 2007 third quarter earnings conference call.

Before I turn the call over to Mike Watford, Ultra Petroleum's Chairman, President, and Chief Executive Officer, I'd like to let you know that our remarks this morning will contain forward-looking statements about the future operations and expectations of Ultra Petroleum. We make these statements in good faith. We believe that they are reasonable representations of the Company's expected performance at this time. Of course, actual results may vary significantly from our current expectations and projections due to a variety of factors that are described in our Form 10-K filing with the Securities and Exchange Commission.

Also, this call may contain certain non-GAAP financial measures. Reconciliations and calculation schedules for the non-GAAP financial measures can be found on our website at www.ultrapetroleum.com.

At this time, I would like to turn the call over to Mike Watford.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Thanks, Kelly. Good morning, and thanks for joining us.

With me today is Mark Smith, our Chief Financial Officer; Bill Picquet, Vice President of Operations; and Steve Kneller, our Vice President of Exploration.

While the third quarter brought with it several challenges and hurdles we had to over come. I’m impressed with our resiliency both financially and operationally. We over came unimaginably low natural gas prices to pose strong production growth and attractive financial returns. We gained momentum and are continuing effort to decrease our time and consequently our cost to drilling complete wells. Our rig efficiency and productivity is up. We secured early positive results to several resource expansion projects currently underway any one of which would add sizably to our un-booked reserved potential. We are ever so much nearer these strategically important startup of the Rockies Express Pipeline, with its immediate 23% increase in takeaway capacity from the Rockies, and an eventual 27% increase all to new markets.

Ultra is an anchor shipper with 200 million cubic feet of data firm capacity. And we recently sold our only international asset our Chinese properties contained within our wholly owned subsidiary Sino-American Energy. Affectively, we sold 1% of our proved reserves at year-end 2006 for over $200 million. The transaction is closed, we have received our money, but the speed of the sale and timing just before quarters’ end necessitated the current quarter accounting complexity involving discontinued operations.

With that as a lead end, I’ll ask Mark to update us on the financials.

Marshall D. Smith - Chief Financial Officer

Thanks Mike. I just like to begin my comments this morning by adding to what Mike said and noting that our financial reporting format has changed, I recalled that Mike indicated on September 27, we announced the execution of a stock purchase agreement for the sale of Sino-American Energy, representing all of our interests in Bohai Bay for $223 million. Despite having owned Sino through the third quarter, under GAAP Sino’s operations are classified as discontinued operations for the entire period as low as for the prior year period. As a result in our press release in our Q, one will see that the revenue and expenses associated with Sino are reclassified into one line item discontinued operations. For clarity of analysis portions of my commentary this morning will include reference to combined operations, which is meant to include both continuing and discontinued operations.

For the third quarter, our performance was largely impacted by combination of factors affecting Rocky Mountain takeaway capacity that in turn affected regional pricing and led us to voluntarily curtail production volumes. Some of these factors included a fire at a major compressor station on the Cheyenne Plains Pipeline that took out as much as 450 million a day of capacity. Ongoing integrity management repair activities on the Northwest Pipeline and maintenance outages on other pipelines of storage fields in the Rockies. But despite our voluntary shut-ins during this time, corporate production was up 22% year-over-year to 28.7 Bcfe, with our Wyoming production at 26% year-over-year to 26.9 Bcfe.

Realized natural gas prices for the third quarter were $4.04 per Mcf compared to $5.68 in the prior year period. China crude prices registered $67.02 per barrel for the quarter compared to $70.61 per barrel in the prior year period. Primarily as a result of these decreased price levels offset in part by our increased production volumes, combined revenues for the quarter, again, to be clear here, by combined revenues I mean revenues for both our continuing Wyoming operations and our discontinued China operations. Combined revenues registered $136.5 million compared to $145.4 million for the third quarter of 2006.

Combined corporate lease operating expenses for the quarter decreased to $1.18 per Mcfe primarily due to decreased severance and production taxes in Wyoming, as a result of lower commodity prices offset part by higher production costs in China. Our corporate DD&A rate for the quarter increased year-over-year to $1.25 per Mcfe as our expected future development costs increased through 2006. G&A expenses were down on a unit basis to $0.13 per Mcfe, interest costs increased to $0.19 per Mcfe, as a result of our increased borrowing levels in support of our capital program and our share repurchase activity. Net effect of these factors was a $0.34 per Mcfe year-over-year increase in overall corporate cost to $2.75 per Mcfe.

Focusing on our cash costs in Wyoming, excluding severance taxes, they decreased on a unit basis to $0.49 per Mcfe in the third quarter. You see stabilization in the year-over-year effects of water handling and treatment. Marginally as a result of the decrease in revenue that I mentioned earlier combined with higher production costs and severance taxes in China, our combined cash flow registered $90.4 million, providing a cash flow margin of 66%. Combined pretax income registered $57.6 million for the quarter or 42% margin, while combined net income was $37.4 million for the quarter registering a 27% net income margins and $0.24 per diluted share.

I think it is important to note here that on our continuing operations in Wyoming, the average gas price of $4.04 Mcf for the quarter. We registered a net income margin of 28% and a cash flow margin of 70%.

In terms of returns for the third quarter, on an annualized basis, our return on equity was 21% and our return on average capital employed was 14%. To the end of September, we repurchased stock in the aggregate amount of $282.1 million, constituting 5.5 million shares. This resulted in an outstanding share count of 152.3 million shares as of September 30.

Net cash from operating activities during the quarter amounted to $100.3 million with net cash used in investment activities totaling $162.9 million. These investment activities were primarily comprised of $166.6 million in oil and gas related CapEx in part offset by $10.2 million increase in payables related to prior period CapEx. Over the quarter, net cash provided by financing activities totaled $53.9 million consisting of a $95 million in net borrowings under our senior bank facility combined with $3.6 million of proceeds from stock option exercises and tax benefits from stock-based compensation, offset in part by $44.8 million related to our share repurchase program.

Looking at the first nine months of the year, 39% higher product volumes offset by 21% decrease in overall prices, led to a 10% increase in combined revenues. On a unit basis, our all in costs were up slightly, again, driven by increased interest costs and higher DD&A rates offset in part by reduced lease operating expenses in G&A. As a result, combined cash flow was up 7% over the first nine months of 2006 levels to $333 million. Combined net income for the first nine months was $153.1 million or $0.96 per diluted share. In terms of returns for the first nine months on an annualized basis, our return on equity was 30% and return on average capital employed was 21%.

Net cash provided by operating activities during the first nine months amounted to $358.1 million, with net cash used in investing activities totaling $528.5 million. These investment activities were primarily comprised of $517.1 million in oil and gas related CapEx, offset in part by $2.5 million decrease in inventory. Over the nine month period, net cash provided by financing activities totaled $164.5 million, primarily consisting of a $230 million of borrowings under our senior bank facility, and $20.1 million of proceeds from stock option exercises and stock-based compensation, offset by $84.5 million related to our share repurchase program.

Looking at our liquidity as of September 30, it remains strong with $10.9 million of cash and cash equivalents on hand, and $395 million in senior bank debt. Recall that our PV covenant in our new senior bank facility effectively sets our borrowing capacity at just over 1.3 billion, with us currently electing the centre commitment amount at $500 million. If you use the proceeds of the sale of Sino-American repay bank debt and currently outstandings registered $235 million. While on the topic of Sino and factoring in our after tax sales proceeds, our estimated return over the life of our investment approximately 23%, again, this is on an after tax basis. Now, we believe that our liquidity continues to remain more that adequate to fund our approved $740 million CapEx budget for the use of our cash flow from operations, combined with our revolving credit facility.

Looking at pricing, natural gas prices softened in Wyoming through September, with daily spot price on September 30, registering $0.83 per MMBtu. Our first of the month index prices for October Opal covered $1.20 per MMBtu and cash prices at Opal continue to strengthen in the currently running in access of $4.50 per MMBtu. In terms of basis, third quarter basis differential ran $3.77 compared to $1.57 for the same period in 2006. As we have moved through October this year basis continue to be volatile, but continues to improve and is tighter than $3.40 currently.

Now, the Rockies Express Pipeline continues to anticipate that the REX-West project will be placed in the services on January 1 as planned. Company stated that interim transportation service on REX-West maybe provided upstream of the Panhandle Eastern interconnect in Audrain County Missouri, depending upon construction progress. We are aware that purchase of oil field has already began for specific sections of REX-West.

And looking at our hedge position for the balances of ’07, we have 10,000 MMBtu per day hedged at $4.98 per Mcf in Wyoming. The summer of ’08, we have 60,000 MMBtu per day, hedged at $7.40 per Mcf Wyoming. And in then in calendar 2008, we have a 100,000 MMBtu per day hedged at approximately $7.41 per Mcf in Wyoming. And then for calendar 2009, we have 40,000 MMBtu per day, hedged at roughly $8.02 per Mcf in Wyoming.

In terms of guidance, despite reduced production volumes in the third quarter and the absence of Sino-American volumes in the fourth quarter, we’re maintaining our full year guidance at a 116.5 Bcfe. For 2008 and 2009, we are tweaking our production guidance. 2008, we are estimating a 135 Bcfe to 140 Bcfe in production, while for 2009, we are projecting a 160 Bcfe to 165 Bcfe. In Wyoming, lease operating expenses are expected to run $0.22 per Mcfe and gathering $0.25 per Mcfe. We currently expect our Wyoming DD&A rate to run roughly at $1.18 per Mcfe, we see our G&A costs at approximately $0.17 per Mcfe for the year.

Now, I will pass it off to Bill for an update on wealth stats and drilling activity. Bill?

William R. Picquet - Vice President, Operations

Thanks, Mark. Ultra’s Wyoming operating efficiency continues to improve quarter-over-quarter during 2007. In the third quarter, 54 gross, 25 net new producing wells were brought onstream in Wyoming, bringing the count since the start of the year to a 144 gross, 67.3 net new producers in our Wyoming properties. The average initial 24 hours sales rate for these new producing wells was 8.7 million cubic feet per day. Ultra’s 59 operated Pinedale wells averaged 9.8 million of cubic feet of gas per day, while the non-operated wells averaged just over 8 million cubic feet per day.

The high point was from Ultra operated Mesa 2B-34D, which flowed at 22.1 million of cubic feet of gas per day, one of the highest rate wells from the lands formation in the Pinedale fields to date. At the end of the quarter, there were 11 Ultra operated rigs drilling in Pinedale and an additional 8 non-operated rigs running on Ultra interest lands. There were 9 gross and 4.4 net wells in completion, and 23 gross, 8.4 net wells waiting on completion. We are drilling more wells per rig this year and continue to build momentum on this significant improvement in our Wyoming drilling efficiency. And key performance measures include recent new Ultra record for drill time on the Pinedale Anticline, spud the TD in 18.6 days, down over 18% from our previous record of 22.8 days in Q2.

Average spud to TD for Pinedale year-to-date is 38 days, an improvement of 38% versus 2006 full year. 65 Ultra operated wells have been drilled and cased through the end of Q3, and we forecasted 90 wells will be drilled and cased by year-end versus 57 in 2006, a 58% increase year-over-year with a slight reduction in total drilling days for 2007. We will average just slightly less than 12 rigs for the full year in 2007 versus 12.7 rigs for the full year in 2006.

Performance continues to steadily improve. The best rig performance continues to be demonstrated by our skid capable rigs, drilling multiple wells on our simultaneous operations adds and our aggregate fleet performance is improving as well. Both drilling time and cost continue trending downward as we gain more experience in the use of oil based mud and as bit designs improve and other technologies provide additional savings.

We're also continuing to improve our overall rig fleet makeup. We're currently operating 11 rigs in Pinedale. We just accepted delivery of our fifth new skid capable rig and this rig can drill 10 wells, skidding from well-to-well without moving any of the rig equipment. We've committed the two additional new skid capable rigs, one for delivery is Q1 2008 and one for delivery by mid year 2008, bringing our total to 7 skid capable rigs by mid 2008 and continuing to position Ultra for improved pad drilling efficiency in the future. We are evaluating options for future rig operations, while maintaining flexibility in our commitments in the interim. Our latest generation skid capable rig will be able to drill up to 16 wells without moving any of the rig equipment. These newest rigs are equipped with dual mud systems, allowing us to drill with water based mud in the top portion of the hole, and converting to oil based mud in the bottom portion of the hole on slide without any downtime for switching mud systems.

These pad rigs continue to set new standards for drill time and also for drilling cost. The latest record well costs less than $3 million to drill and case, including a full rig move. We're now routinely drilling and casing pad wells in the $4 million range and our percentage of sub $4 million wells is increasing. Including the cost to complete and equip, with full production facilities, we’re now averaging about $6.3 million per well on recent cost performance. The record well translates to full cost of less than $5.7 million equipped and fully ready for production including the full move cost.

Current production is gradually bringing down… our current performance is gradually bringing down our aggregate cost per well for the year. Our cost earlier in the year was somewhat higher due to cost to equip our rig fleet with oil based mud capabilities and other one-time expenditures. We stated in the last call that our target is $6 million per well for development wells, and we're aggressively pursuing that performance level. Delineation wells are a more expensive component of our activity due to the full move cost required for each well, and in some cases, we need to run an extra casing strength to ensure a full well evaluation. The premium for delineation well is currently ranges from an extra 500,000 to 1 million per well depending on the casing design. We're taking steps to reduce this cost differential between delineation and development wells. We're having some success in reducing move costs and capping move costs exposure.

We're confident that the future upside for continued drilling performance sufficiency improvement is still substantial. We have only been drilling with all base men and alters operations fleet wide now for six months. The transition has been very smooth and we continue to gain experience that combined with the improved bit technology and additional bit for purpose drilling rigs in our fleet make the target cost of $6 million for operator development that wells very realistic. Cost of services is going down, we are seeing new benchmark for day rates for fitful purpose state-of-the-art skid capable rigs settling to the low $20,000 per day range, per day rates. Other services are reducing as well as we negotiate new long-term contracts where most of our service areas. The main message we are going our drilling performance is we are drilling faster, costs are getting lower and we are getting more wells online producing for sales sooner. Our completion program continues to be very active, we completed a total of 64 operated wells during the first three quarters of the year and pumped a total of 1215 frac stages year-to-date. We are estimating a total of almost 1650 frac stages for the full year compared to 1180 during the full year 2006, a 40% increase year-over-year. Ultra’s completion activity is keeping pace with the drilling activity and providing very short times from rig release to first production averaging 17 days year-to-date. We are delivering a case where we are all ready for completion every four days during Q3, our fracs are averaging about $105,000 per stage year-to-date and slightly over 20 stages per Pinedale well.

Couple of comments regarding production. During Q3 we curtailed a total of 50.6 bcfe of production from our combined operated and outside operated Wyoming production capability. An interesting positive impact from the curtailment is the flush production component of the individual well performance as we bring wells back on line during October. We are still learning about the extent of this component of production and we’ve actually been facility limited on some of the older wells as they come back on line at higher flowing tubing pressures and rates than they have experienced in quite some time. We are currently producing at record levels, 340 million cubic feet of gas, net to Ultra and Wyoming.

Quick comment on status of the SEIS. The BOM announced in late August that they would provide a redraft including two additional alternatives for public comment later this fall. We expect that redraft to be issued soon and the process will continue to progress toward a record of decision, now expected sometime in summer 2008. As we have said before this added time in the SEIS process will have no adverse effect on our 2008 plan. We believe the end result of the added time will be a better public process allowing for additional public comment and ultimately an improved record of decision.

With that I’ll turn things over to Steve.

Stephen R. Knelle - Vice President, Exploration

Thanks Bill. Well you have heard all the numbers, the well counts and details from Mark and Bill. Now lets move on to some of the fun stuff. First, let’s update the status of our delineation drilling program Pinedale. Our plans call for the drilling of 21 delineation wells this year, with the majority of them being drilled in the second half of the year. So far six of these new delineation wells have been on production long enough to be able to project the ultimate reserves.

All six have reserves above the pre-drilled estimates by Netherland Sewell and associates. In fact the total estimate ultimate recovery for these six wells are a 167% of the pre-drilled reserve estimate. Some of the highlights are the warm water 5C-111D on the East edge of the field which came on with the initial 24 hour flow rate of 14.3 million cubic of gas per day.

Just to the North the Warbonnet 4B-11D came on for 10.3 million cubic feet of gas per day and four miles to the North West, the Boulder 10A-30 came on for 17.7 million cubic feet per day. To help put this delineation program into context, within the Pinedale field we have identified over 100 quarter sections where delineation wells could add substantially to our reserve position.

The vast majority of the delineation quarters are around the edges of the field in areas where, here in 2006 Netherland Sewell did not give Ultra credit for the locations due to lack of data points from which to evaluate them. It should be noted that all these delineation quarters have been evaluated using our expensive 3D seismic data set.

We believe there is a good chance for success for drilling in them or they would not be on this list. 11 delineation wells have been drilled and are in production, completing or waiting on completion to-date in 2007. All appeared to have been successful at meetings or exceeding our in house pre-drill expectations. Thus providing confidence we can continue our string of positive drilling results as we move forward with the delineation program. The drilling of successful delineation wells in these core sections could add a large number of new locations, the over 5000 locations identified in the Year end Reserve report. Additionally in areas where there were locations already on the books, these could be upgraded from possible or probable to proven and the… per well, per location reserves will increase. Bind together successful results in this delineation program, the result in recognition of new locations in reserves over a large portion of the field.

As we discussed in the last conference call, the results of a smaller group of wells in the East Warbonnet and South Boulder area resulted in a potential increases of reserves in this area of over a quarter tcf net to Ultra. This sort of result extended to the 100 plus quarter section, would add significantly to Ultra’s year end 2006 and tcf reserves. Our work on the evaluation of the appropriate density for development for the Pinedale is proceeding on schedule. We’ve finished the data gatherings from the 155 wells in 68 well clusters currently drilled at inner well distances less than 10 acre density in the field. This massive data has now been delivered to Netherland Sewell and our in-house reserves engineers for evaluation and further analysis. We’ve also formed a multi-disciplinary team in-house which sifts in its determination of how best and when to drill the 5 acre increased density wells.

To further this effort, we will be going to the Wyoming oil and gas transportation commission in December for 5 acre pilot projects on four quarter sections in Warbonnet but we’ll be able to drill pilot wells this winter. This additional data should be very helpful in furthering the evaluation. On to the non-sand portion of thick land section, the work is continuing. We have fractures stimulated 21 stages in 8 wells and have run the initial production logs in these wells. The average gas logs and production logs over these stages, is just over a 125,000 cubic fetter flow per stage. Flow rate is not like the initial 24 hour rates that we report, but rather these flows are taken out after the well has been in production for a period of time and the initial flush production has been decreased somewhat.

We do need to run additional production logs over time to see how the productions from these inner wells sustains. If these knowns produce similarly to the overall land section, each known could average about 100 million cubic foot of gas of added production and reserves each. Given that these frac stages cost about $105,000 each. This is adding additional reserves in production over and above the normal lands reserves in production and improving the already robust economics of the Pinedale field. As an added benefit, this work will also assist Ultra and Netherland Sewell in the ongoing evaluation of the total resource potential of the Pinedale field. If we prove by production that the current pay cut offs in the Petrophysical model are too high, this could add substantially to the already staggering original gas replace for Pinedale.

Now, let’s talk about the de-test that has been ongoing for sometime now. We have encountered the top of the Blair Formation at 16,204 feet, at a depth of 17,504 feet, we were drilling with 17.6 pound per gallon drilling mud and a continuous gas flare. We decided to stop drilling at this point run logs to evaluate what we had drilled so far and set a drilling liner to protect Blair. We ran an extensive suite of wireline logs and recovered a large number of side wall cores to get lock data to calibrate the log data. In comparison to the Stewart Point 15-29 well, we have encountered thicker sands of overall better quality based on the logs, core plugs [ph] are core logs for analysis. And we should have a much better picture of the reservoir quality soon. Of course, all this good fortune cannot go unpunished. After studying and cementing the liner, the drill pipe came stuck in cement inside the casing, up at about 13,000 feet. We are currently washing over the fish and recovering the pipe. It will take some time, but we expect to be able to recover the fish and continue drilling to our planned 19,500 foot total depth to test the Hilliard. Sending further evaluation of all the data gathered to date, we are now formulating plans that could lead to the drilling of a second Blair only test just this winter.

That's all from my update. With that, let me pass it back to Mike.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Thanks, Steve. So, where we ended up here, I believe we have reaffirmed our 2007 production guidance of 116.5 Bcfe. We are not using our properties sale or productions shut-ins to revise it downward. In fact, if I remember correctly, we actually revised it upward on two occasions this year. So, we are forecasting a 29% per share production growth for 2007. For 2008 and 2009, we are suggesting an upward bias to earlier production guidance by offering a range of productions for the two years with our previous guidance providing the floor.

On drill times and costs, we are realizing significant reductions. Additionally, we are seeing increased productivity from our rig fleet. All wells at lower costs per rig per year is a good thing. Our expectation is that our well costs will be lower next year than they are this year. On resource expansion, our primary value driver, we are making headway on a number of fronts. The success of our delineation drilling is the easiest to measure with continued progress expected on all 100 plus quarter sections or 16,000 acres remaining to be tested. Our five acre analysis on proper field spacing is ongoing with more pilots planned. The non-sand pay project is off to an early success, but more zones and more wells producing for more time is needed. Deep exploration well is showing positive signs. It is likely that our un-booked to booked resource ratio of 4 to 1 will be expanding.

REX, the interstate pipeline is almost complete, in fact, they are hinting at an early startup for interim service. Our VP of Marketing, Stuart Nance has described REX as the most efficient pipeline in the U.S., transporting the lowest cost natural gas in the U.S. 1,700 miles to ultimately the highest value of natural gas market in the U.S. Strategically, it’s very important. Our China sale allows us to reduce debt and reallocate capital to higher return projects, and we are delighted with the price we received. Financially, we are in good shape with 2007 earnings exceeding 2006 only to be further exceeded by 2008. I like the trends.

And now, I would like to open up the conference call to questions.

Question and Answer

Operator

[Operator Instructions].

And your first question comes from the line of David Cameron with Wachovia. Please proceed.

David Tameron - Wachovia Capital Markets

Hi, congrats on the production number in the quarter.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Thank you.

David Tameron - Wachovia Capital Markets

Couple of quick questions. Fourth quarter impact related to Cheyenne Plains. Is that backup online yet, or can you give us some feel for what your expectations are? And what you have got built in your drill numbers for the fourth quarter?

Michael D. Watford - Chairman, President, and Chief Executive Officer

Well, Cheyenne Plains is not backup yet, not thoroughly, partially. And they originally came backup just free flowing some gas and they added some rental compression, I don’t know exactly today where they are in terms of volume transforming, surely we can get that information if you want the detail. But our… maintaining our year-end production target of 116.5 Bs, we are assuming that Cheyenne Plains is not backup until the middle of November, but not later than that, if we can still achieve our targets of achieving reasonable gas prices.

David Tameron - Wachovia Capital Markets

Okay. I think that's what I was looking for. And then, for the D&C cost, I mean, I think you talked about getting up to that 6 million target kind of where drilling day is today whenever you put the press release I think they have averaged, I want to say 38 or 39 whatever is in the press release. I think, is that a year-to-date number, or is that a quarter-over-quarter snapshot?

Marshall D. Smith - Chief Financial Officer

That’s a year-do-date number. The Q3 numbers are trending downward from that. So, we are continuing to average down as we go through the year.

David Tameron - Wachovia Capital Markets

All right. And then your average… your D&C cost that $6 million target. Is that 12 month target? At what point do you think you will be able to start?

Marshall D. Smith - Chief Financial Officer

We think it’s achievable, once we get to the point where we have more skid capable rigs in the mix. And right now, we are experiencing costs below that where a number of wells that are drilled by skid capable rigs. But, our aggregates are higher than that and it won’t reach 6 million this year just due to the fact that we're drilling a fair component of delineation wells which are more expensive and we only have five skid rigs today. Just recently went to… so that’s an evolving process and we're just working our way down to six.

David Tameron - Wachovia Capital Markets

Okay. So I mean mid ’08, is that a better timeframe? I’m trying to peg you down to a timeframe here?

Marshall D. Smith - Chief Financial Officer

Yes. We’ll see how fast that progresses. But we're pretty satisfied with how fast it’s progressing right now.

David Tameron - Wachovia Capital Markets

All right. Fair enough. I’ll dial that, let other people jump on and I’ll circle back in. Thanks.

Marshall D. Smith - Chief Financial Officer

Thank you.

Operator

And your next question comes from the line of Brian Singer with Goldman and Sachs. Please proceed.

Brian Singer - Goldman Sachs

Thank you. Good morning.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Good morning.

Brian Singer - Goldman Sachs

You highlighted in greater detail than maybe previously some of the differences in Ultra operated wells versus the non-operated wells can you talk to why you think that is?

William R. Picquet - Vice President, Operations

I’ll start and let Steve jump in. This is Bill, Brian. We're fracing a few more stages per well typically than the other operators and we're also using different fluids. The other operators are using at least in a portion of their wells thick water in their fracs as opposed to gels. And we're not doing that yet. We're still convinced that we're getting improved performance with gels.

Stephen R. Kneller - Vice President, Exploration

Brian this is Steve. In looking at where the wells are located, what they’ve been drawing how deep we're going stratographically in the section. There’s very little difference. Obviously what started from majority of their wells roughly the Mesa area, ours have been Warbonnet and a mix of Mesa riverside wells as have shales. You don’t see a whole lot of difference geologically or in the section. I do see a difference in how we pick what we frac versus what the other folks do. We are a little more perhaps aggressive in what we're seeing as pay and fracing more inner holes from pumping more stages on average. Getting more of a section open as we have seen from the non-sands number, we are getting contributions from stuff that’s below what we had even been calling as our pay cut offs and the other parties haven’t got as aggressive on their cut offs as we are so. I think we're just, we're opening up more of the total over pressured land section to the well bore and as a result getting more production.

William R. Picquet - Vice President, Operations

I think it also is contributing to our sudden increased well costs above our competitors out there to the other operators because we are fracing more stages that cost more money, but we think we have better reserves.

Brian Singer - Goldman Sachs

That’s helpful. Switching to the non-pay section. Can you talk a little more historically? Why was this not non focused on and what has changed to potentially make these new areas commercial?

William R. Picquet - Vice President, Operations

History, one on one… the… what is constitutes pay in tight gas sand has always been a little bit of a puzzle. Going back when we first began in this area and early work in Jonah, we… industry Ultra as the other parties had kind of decided what month possibly produce, what part of this section and decide… determine pay cut offs from that and that’s what we fraced. And over time, we began to realize that perhaps we weren’t getting the right answer. You recall several years back, we entered into a big program cutting a lot of core, try to get rock data to better understand what this reservoir really was. Out of that it come to recognition that the whole thing was gas saturated, we didn’t have any real water tables or perched water or anything like that in the lands, it was gas saturated top to bottom. And Netherland, Sewell at that time, recalibrated the Petrophysical model for us. Lower the pay cut off, we started fracing more data. There is some more sections in gathering more data. The more data we gathered, the more work we did, or we begin to realize it even at these lowered pay cut offs, there was still stuff that was escaping us. We were seeing sections why we are drilling, we are getting strong gas shales on the mud logs and yet no apparent stand on the wireline logs.

But finally, we said that let’s go and test this and see what there and see if we are being full by that’s or not. So, we started picking zones that had good shales on the mud logs, but no log indication or not good luck indication on the wireline logs and started fracing and we are seeing production from those stages now too. All in all, it confirms in my mind that this whole section is totally gas charged and it is strictly a matter of creating good enough pathways from the formation back to the well bore allow the gas to flow even out of the tightest stuff. Same token, you’ve had all the shale play going on all over the country, where people have made tremendous progress and opening up our production from section to this nobody ever dream possible we have produced. They knew the gas was there, we never knew how to get it out, and whether it plays in the Barnett and Woodford and Fayetteville or Appalachian plays or the Michigan basin plays or any of these other shale plays, people are getting gas down out of rock, was never possible. We are just continuing to move that velocity into this play too.

Brian Singer - Goldman Sachs

And that upside is sand… and those wells are separate from the delineation wells in terms of resource?

William R. Picquet - Vice President, Operations

Yes. I mean basically the non-sand piece, at least, to date, we are seeing it pretty much over the whole area. We have fraced wells already from the South Mesa area all the way down in the Warbonnet in the section, and we are seeing contribution. And so, the senses that… I don’t see anything now that we won’t see this kind of contribution over our acreage block and even some of the delineation wells we have fraced in the [Technical Difficulty] already to help test that stuff out on the edges. So, we are seeing it everywhere.

Brian Singer - Goldman Sachs

Thank you.

Operator

And your next question comes from the line of Brian Kuzma with JP Morgan. Please proceed.

Brian Kuzma - JP Morgan

Hey, good morning guys.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Good morning.

Kelly L. Whitley - Manager, Investor Relations

Hi, Brian.

Brian Kuzma - JP Morgan

One quick question on the non-pay that you guys are looking at here. It looks like only frac, I am reading this like 2.5 stages… additional stages per well?

Stephen R. Knelle - Vice President, Exploration

Basically what we are doing… we are trying to crawl before we get up and start walking and start running. We are selectively targeting zones to frac in amongst the overall completion project we are doing on each one of these wells. The test different parts of the section, test different characteristics to the section, try to get a better understanding of the overall value of this before we roll into a full blown do it everywhere kind of a project. We are still early in the data gathering phase. We have run production logs on the first eight wells, we need to run several more production logs on those wells to see how the production history plays out. I find it hard to go in a pilot program, jump into tons of this, we have a better idea whether it’s really going to work for us. I think the data has been very… the results have been very positive.

Brian Kuzma - JP Morgan

Based on the criteria that you guys use for these pilots, what would you say of that gross land section, how much additional footage to the… would that give you guy?

Stephen R. Knelle - Vice President, Exploration

Well, I mean, if… of the total land section, right now, our completions cover about 40%, so they gives us 60% play. How much of that turns out to be alternatively productive, it’s too early to tell. We are still gathering the data, but even if you add… even small percentage of that over the whole area, it turns out to be a very big number. And it’s inside existing well bores that we have already paid, spend the money to drill for the land sand anyways. So, this is all, as they would say in New Orleans they would say lagniappe. We are just adding a little bit of production reserves for a little bit of money.

Brian Kuzma - JP Morgan

Got it. I think, what was the precocities like on the Stewart Point deep test, you guys… and were they like on this one?

Stephen R. Knelle - Vice President, Exploration

The data we have at this point indicates that our average porosity is about 1 to 1.5 porosity units higher then what starts on average on our joint Stewart Point 15-29 well.

Brian Kuzma - JP Morgan

And then, I guess my final question is, have you guys thought or done any more work into looking into doing in MLP structure with your older wells?

Stephen R. Knelle - Vice President, Exploration

No. We haven’t.

Brian Kuzma - JP Morgan

You plan on doing it anytime.

Stephen R. Knelle - Vice President, Exploration

No.

Brian Kuzma - JP Morgan

Thank you.

Operator

And your next question comes from the line of Richard Tullis with CapitalOne Southcoast.

Richard Tullis - CapitalOne Southcoast

Hey. Good morning. Couple of quick questions for you. Do you have any production currently curtailed in the Rockies?

Michael D. Watford - Chairman, President, and Chief Executive Officer

Yes.

Richard Tullis - CapitalOne Southcoast

Can you give us the estimate about how much?

Michael D. Watford - Chairman, President, and Chief Executive Officer

No.

Richard Tullis - CapitalOne Southcoast

Okay. Moving on to the rig count in Wyoming, it’s down to 20 at quarter-end. I think it was 11 operated, non-operated, if I’m not mistaken.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Yes.

Richard Tullis - CapitalOne Southcoast

What you foresee going into… through the rest of this quarter and into… beginning of’08, the rig count?

Michael D. Watford - Chairman, President, and Chief Executive Officer

I’m going to help answer. Typically, in the winter in Wyoming’s, it decrease rig count not increase rig count. I don’t think that will change this winter.

Richard Tullis - CapitalOne Southcoast

Okay. What about going into beginning of ’08.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Probably we can speak for ourselves and we have 11 operated rigs right now and we are going to operate between 10 and 12 I guess, roughly for 2008 is just the current plan, although, it is not finalize.

Richard Tullis - CapitalOne Southcoast

Okay.

Michael D. Watford - Chairman, President, and Chief Executive Officer

We don’t forecast a significant rig… operated rig increase that where we are going.

Richard Tullis - CapitalOne Southcoast

Okay.

Michael D. Watford - Chairman, President, and Chief Executive Officer

We can achieve our very aggressive production growth numbers without increasing rig count, because of the tremendous improvement, that enable to workout of the existing fleet, plus the improvement of the mix of those rigs.

Richard Tullis - CapitalOne Southcoast

Okay.

Stephen R. Kneller - Vice President, Exploration

Richard, this is Steve. One thing you keep in mind, on a net well basis, we operate about 70% of our total well count, the wells that we are drilling. Of the 11 wells… operated wells that we run I mean that’s the important component. For the non-operated rigs which are obviously a much smaller component of our overall mix we thought that very little control how many actually are on our acreage at any given point or not. They kind get to see the problem because we could easily have plenty some rigs running, but, yes, there are non-operated ones and small interest pieces, so we don’t see much impact from them. So, focus on the operated rigs, because this is also that it really makes the difference at the end of the day.

Richard Tullis - CapitalOne Southcoast

Okay. How quickly you bringing wells on now, when you complete them?

Stephen R. Kneller - Vice President, Exploration

Once we… actually, EDA [ph] well cases, it is going to release drilling rig, it taken us an average of 17 days into what goes to sales year-to-date.

Richard Tullis - CapitalOne Southcoast

Okay. And going to China, real quick, I noticed the expenses were real high. Can you comment on that? I know it’s discontinued operations, but just looking of a little insight into that.

Stephen R. Kneller - Vice President, Exploration

Well, the two things we had impacting us, Richard, in the third quarter relative to China we had some West production downtime due to some pipeline issues there in China. So, that drove our unit operating cost up on a relative basis and we also had higher production and severance taxes. Recall, that the China introduced the special petroleum.

Richard Tullis - CapitalOne Southcoast

Right, right.

Stephen R. Kneller - Vice President, Exploration

Those were the two big factors that drove down performance in Chain in the third quarter.

Richard Tullis - CapitalOne Southcoast

Okay. I think that’s it form me today. Thanks very much. I appreciate it.

Operator

And the next question comes from the line of Clay Cummings with Johnson Rice. Please proceed.

Clay Cummings - Johnson Rice

Good morning. Just a quick question on the net resource potential that you spoke to in previous conference call, the additional two Tcf net and that to Ultra. Has that number changed since the last quarter call, based on what you seen from the delineation wells to date? And the non-sand pay section to date?

Stephen R. Kneller - Vice President, Exploration

Mike, may have a different answer for this, Clay. This is Steve, I think it’s still a very reasonable number. Obviously, we have lots of things we are working on right now. It can move that number, but the delineation wells when you look at the amount of areas we still have to delineate the field, the large number… a 100 quarter section that's 16,000 locations we can put economic reserves on all of that the 2 T number is certainly well within the range, on sand and some of the other things that could be added to that. But it’s early to quantify a lot of stuff yet the sense I have now is that, that’s still a reasonable number.

Clay Cummings - Johnson Rice

I guess from the initial results, would you say there is a bias, the upside to that number?

Michael D. Watford - Chairman, President, and Chief Executive Officer

I think I heard Steve just say is he thinks he can get the other 2 T just with delineation drilling success. Yes, there’s a bias.

Clay Cummings - Johnson Rice

Okay. And can we quantify what the non-sand pay would mean to you guys.

Michael D. Watford - Chairman, President, and Chief Executive Officer

It’s too early on that I don't think we can quantify at this point.

Marshall D. Smith - Chief Financial Officer

It’s greater than zero.

Clay Cummings - Johnson Rice

Okay. Fair enough. Moving on to the SEIS timing, looking at summer 2008. At what point in time, does that begin to affect your plans as far as exactly goes.

Michael D. Watford - Chairman, President, and Chief Executive Officer

It doesn't in 2008

Clay Cummings - Johnson Rice

So, let pass the summer of 2008.

Stephen R. Knelle - Vice President, Exploration Domestic

Yes. I mean, basically the way our drilling schedules laid out, if there is a delay, we don’t see a hiccup in our activity all the way through next year.

Clay Cummings - Johnson Rice

And. So, as hedges go, you guys looking at any hedges for 2008-2009--?

Stephen R. Knelle - Vice President, Exploration Domestic

You’ll see us manage our hedging position opportunistically as we go through time. Based on what we see… how we see prices back up against our long-term outlook.

Clay Cummings - Johnson Rice

Thank you.

Operator

And your next question comes from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra - Jefferies & Company

Hey Mike. Second deep test, I guess, I don’t really, if that was previously on the schedule or did that sort of merge lately?

Michael D. Watford - Chairman, President, and Chief Executive Officer

It’s been merged very lately.

William R. Picquet - Vice President, Operations

It’s called a Steve surprise and around here.

Subash Chandra - Jefferies & Company

Is that going to be… are you going to have partners in that? Isn’t it operate alone, right?

Michael D. Watford - Chairman, President, and Chief Executive Officer

No. There’s no… we haven’t confirmed that we are going to do this. Steve was just suggesting that there’s something that we are seriously concerned. Once we get all the data back, that’s currently being analyzed particularly all course.

Subash Chandra - Jefferies & Company

Okay. Has he… has Steve picked a location or--?

Stephen R. Knelle - Vice President, Exploration Domestic

Well. We've got… we've drilled one… basically two wells now through this section. Our well on the Stewart Point 15-29 from the seismic and from that we've mapped areas that could be as much as 30,000 acres largely under our acreage position. So, we're looking at a fairly large area and we've got 3D coverage over the whole thing. So Sally Zinke, our Chief Geophysicist, Geoscience Manager and the other folks in Denver have been working that area very hard trying to figure out what the right places to go. If we can come up with a good location and come up with good answers from the data we've gathered to date and I’m going to go back to Mike if we can convince him that this is worth doing. But this is a very large closure that we have underlying the Pinedale lands field and largely on our acreage position. So, it’s a large playground to work in.

Subash Chandra - Jefferies & Company

Do you need to get this… the well you currently stuck it, do you need to get that to TD and get a sort of a production test going before you make that decision?

Stephen R. Kneller - Vice President, Exploration

No. I think we will be making the decision… we may make it before we even get the TD on this. You never know.

Subash Chandra - Jefferies & Company

And judging say how you’re going to produce that well from how you're going to drill that well. How much more complicated is to you? Just try to figure out how you deal with all the pressures down there, and get the… get the gas out of the ground versus the difficulty of just reaching TD.

William R. Picquet - Vice President, Operations

As far as the completion goes, we need to spend quite a bit of time looking at the core data and so we have designed the completion. Mechanically it’s more difficult because of the higher pressures, you need variably more pump capability to conduct the frac that these pressures and there’s a combination of mechanical difficulty and just understanding what the rock requires as far as the completion is concerned. So we are going to spend some time evaluating how we are going to go about this before it actually goes completed.

Stephen R. Knelle - Vice President, Exploration Domestic

Plus one of the things, Subash, that I think will help our completion folks as compared to what was encountered in the 15-29 is not only do we have better quality sand with higher porosity but sand body seemed to be better developed and we just don’t have some of the problems that we encountered in that well, are apparent here. I mean the drilling challenges are there, the completion challenges are there, but I think we have got a better section to work with to start. It should help Bill and his folks have a better result at this location.

Subash Chandra - Jefferies & Company

Okay, okay. And I guess finally just back to sort of the non-op… non-op, not to ask you to speak for others but I mean do you see sort of the non-op rig count being a bit like… do you see the same sort of developments you have in which some of the these better… these skid able rigs you don’t need as many or is it a function of just some of your partners laying the rigs down?

Stephen R. Kneller - Vice President, Exploration

No, two things. Queststar’s acreage is big, they can run more rigs in the summers than they can ran. They currently are authorized to run in the winter, that changes the rig count there, but Shale you got to look at where we have interest under a large portion their operated acreage but not all of it though they decide to put a rig on, on… a rig that’s been on us, on another section of the leasehold, we may not have an interest but you have seen some shifting from that. That accounts bouncing up and down because of that kind of shifting.

Subash Chandra - Jefferies & Company

Alright, now that’s true. Okay. And finally Mark did you just cover the balance sheet again pro forma for the China sale?

Stephen R. Kneller - Vice President, Exploration

We want…

Marshall D. Smith - Chief Financial Officer

The total outstandings currently stand at $235 million.

Subash Chandra - Jefferies & Company

Okay.

Marshall D. Smith - Chief Financial Officer

The assets are down $100 million

Stephen R. Kneller - Vice President, Exploration

Yes.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Property?

Stephen R. Kneller - Vice President, Exploration

Yes.

Marshall D. Smith - Chief Financial Officer

On cost basis in those properties list, is just… is around a $100 million, Subhash.

Subash Chandra - Jefferies & Company

Okay. And did you have a working cap surplus deficit?

Marshall D. Smith - Chief Financial Officer

Yes, we had a slight working capital position.

Subash Chandra - Jefferies & Company

Okay, great, okay, thanks.

Operator

And your next question comes from the line of Noel Parks with Ladenburg Thalmann, please proceed.

Noel Parks - Ladenburg Thalmann

Good Morning

Michael D. Watford - Chairman, President, and Chief Executive Officer

Good Morning.

Noel Parks - Ladenburg Thalmann

Just had a few questions starting on the cost side. When I look at the longer term going out, the 15 –20 plus year time frame with the license of the wells and I compare that to what’s been going on over the last years so with your LOE and gathering guidance which together has been so that $0.45, $0.47, $0.50 and that range in Wyoming and do you get more improvement on both the recoverabilities and hooks around the costs in short doing a long term preferred value. Where do you see that the LOE component may be settling out as sought of long term for some of the wells. Just assuming that it’s going to be a lower number than say we were all thinking of a couple of years ago.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Okay, let me… let’s still answer the LOE number directly but the gathering numbers are going to change. It is, what it is and in fact if you go out, 10,15 years you think we need a lower operating pressure on the gathering systems, you might see increases in the gathering costs…

Noel Parks - Ladenburg Thalmann

Okay.

Michael D. Watford - Chairman, President, and Chief Executive Officer

But with number of years you don’t see any change there.

Stephen R. Kneller - Vice President, Exploration

What is our least concern, there are some inefficiencies that we will see over the course of time, obviously more wells give your efficiencies either more convinced operations and as part of what we are committing to in the SEIS process, we are committing to… look what’s gathering system which will improve efficiencies of transportation of condensate and water within the field.

I guess the last component that we are still evaluating that seems some encouragement on is on salt water disposable , we have drilled a couple of salt water disposables wells during the last year and we are still testing them but seeing encouragement that we will be able to at least a component of our produced water be disposed down hole and so how much impact that will have on our overall LOE that has to be determined but I see it going down in the long haul.

Noel Parks - Ladenburg Thalmann

If you compare back to say what may be what you envisioned a couple of years ago , how the improvements of the skid able rigs and so forth. I mean and what to… you feel looking for it now I mean what… I don’t know, say like a 15% ultimate improvement and ROE on a unit basis be reasonable?

Stephen R. Kneller - Vice President, Exploration

I would be guessing at this point in time, I think, we’ll know more over the course of this year and next year as we continue to evaluate how viable down hole salt water disposal is I mean right now they are not biggest components of these operating expenses and in the water.

Marshall D. Smith - Chief Financial Officer

So I think it’s a penny or two for NCFE reduction in water handling cost, that is a 10% reduction, $0.20, $0.18

Michael D. Watford - Chairman, President, and Chief Executive Officer

Bill’s right. Of that LOE expense, if it is water handling.

Noel Parks - Ladenburg Thalmann

Okay. Great. That kind of gives an idea. Another thing really that much mentioned today of your current thinking on Pennsylvania and just investing in the exploration of all that you have there versus your reinvestment opportunities at Pinedale. Any current thoughts on that?

Michael D. Watford - Chairman, President, and Chief Executive Officer

While I think we are still trying to put those thoughts together but I mean we are so delighted of what we have going on in Wyoming that with the upside with REX and with the resource expansion and cost reduction that given the large amount of capital, we will be able to reinvest there for decades. That’s the focus today; and we are still scratching our heads about what we are going to do in Pennsylvania.

Noel Parks - Ladenburg Thalmann

Okay, fair enough. And one other thing on the cost side, we’ve been hearing so much about service cost coming down in the Rockies over the past and so forth and I can recall that you guys have had a long term service arrangement with one of the big vendors and I was just wondering how the pricing on that arrangement is looking compared to say I guess when you used your last major negotiations. So favorable company insisted pushback on or little bit more given the current environment?

Michael D. Watford - Chairman, President, and Chief Executive Officer

Well we are in these negotiations right now and I guess, I’ll say our expectations are that there is going to be reduction and we are anticipating something in the plus or minus 10% range.

Noel Parks - Ladenburg Thalmann

Okay. Great. And over what timeframe would we see that actually hitting the income statement, sort of like a first half ’08 of or eighth of that?

Michael D. Watford - Chairman, President, and Chief Executive Officer

It will be beginning at 10 January, ’08.

Noel Parks - Ladenburg Thalmann

January ’08. Okay. And just my last one, you know after the tough… the tough time we’ve had in winter whether over the last couple of years and now pricing gains looking pretty strong going forward. If we think a little less defensively and start thinking more about the ball case looking into next year, if the strip holds and we have really robust prices. What… how would that affect your outlooks for the year. I mean assuming you took advantage of that just to feel at your activity sum, would you think more about expanding the traditional rigs that you can use your hands on easily or just committing more quickly the tomorrow purpose build rig?

Michael D. Watford - Chairman, President, and Chief Executive Officer

I think the commitment to rigs has to do more with the SEIS, but the mission requirements are going be there… than it does responding to marketplace signals. Right now we want to get the SEIS out and resolves so we know exactly what we are committing to… in terms of reductions of emissions over the next four or five years. So, that would drive that longer term answer. Short-term is whatever decisions… whatever the market does in terms of gas prices that might strengthen our desire to go faster, although, we have very strong desire to faster anyway, if you look at our production growth target. That… if we made a decision in March or April you not going to… a rig to show up even an existing rig for several months and it will really have no impact on ’08 activity either from a CapEx standpoint or production increase all that in ’09.

Noel Parks - Ladenburg Thalmann

Okay. And actually one last thing about when do you think you are going to really have ’08 to finalize on the budget?

Michael D. Watford - Chairman, President, and Chief Executive Officer

Once we get information from our partners.

Noel Parks - Ladenburg Thalmann

Okay. So I mean before the end of the year you thinking might have to wait until get a little further--?

Michael D. Watford - Chairman, President, and Chief Executive Officer

It depends on partners. Once Questar and Shell tell us what their plans are.

Noel Parks - Ladenburg Thalmann

Okay.

Michael D. Watford - Chairman, President, and Chief Executive Officer

I can’t tell you exactly when they are going to tell us.

Noel Parks - Ladenburg Thalmann

Okay. Great. Thanks.

Operator

And your next question comes form the line of David Heikkinen with Tudor Pickering. Please proceed.

David Heikkinen - Tudor Pickering

Good morning. I thought I was going to have to say good afternoon by the end of the call.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Where are you?

David Heikkinen - Tudor Pickering

I am in Huston. So, first question on your deep test, what’s the cost of the well you’re drilling?

Michael D. Watford - Chairman, President, and Chief Executive Officer

That’s expensive David.

David Heikkinen - Tudor Pickering

That’s expensive and it sounds like Steve gave you a little lagniappe on your well and drilling plans. So, deep test overall $10 million wouldn’t be outside the range to drill and complete.

Stephen R. Kneller - Vice President, Exploration

The deep test. Questar spent $20 million We are going to spend more than that.

David Heikkinen - Tudor Pickering

You going to be 15, I am trying to bracket here.

Stephen R. Kneller - Vice President, Exploration

Are you talking about the current one?

David Heikkinen - Tudor Pickering

The current well, yes.

Stephen R. Kneller - Vice President, Exploration

The projected one we are talking about or the one Mike…

David Heikkinen - Tudor Pickering

The Blair test, the projected well and the current well so I am trying to get my mind around.

Stephen R. Kneller - Vice President, Exploration

If we would drill a second well and we are still working up the costs, we are working up the drilling program and everything else I mean it’s still going to be a lot less than what we are doing on this current well, but as far as an absolute dollar, we don't have to get we still looking the drilling plan.

David Heikkinen - Tudor Pickering

Okay. And then the five acre pilots, do you have any partners participating in that proposal for five acre pilots?

Stephen R. Kneller - Vice President, Exploration

The anchorage involved in the pilot application is within the core area where we have Shell and Williams and Lance as our partners.

David Heikkinen - Tudor Pickering

Okay.

Stephen R. Kneller - Vice President, Exploration

We are talking with them about what we are planning and hopefully have them all on board its not much different than the similar five acre piloted shale.

David Heikkinen - Tudor Pickering

Yes.

Stephen R. Kneller - Vice President, Exploration

It shows we have got approval from in June

William R. Picquet - Vice President, Operations

Back in June Shell and Ultra went together on a pilot in Riverside. And we're on going…

David Heikkinen - Tudor Pickering

So you're working together still. I mean its just all that I was looking for so it sounds like that progress and working together still not expecting a surprise hearing announcements from Shell or anybody?

William R. Picquet - Vice President, Operations

Well till we get there. We will never know

David Heikkinen - Tudor Pickering

You never know they can always surprise you. And then the final question. Any indications you had from Netherland Sewell on the cutoffs analysis, I mean, Well incorporating that into your current reserve report this year or would it be next year?

Michael D. Watford - Chairman, President, and Chief Executive Officer

You mean the cutoff movement from the non-sand party?

David Heikkinen - Tudor Pickering

Exactly.

Michael D. Watford - Chairman, President, and Chief Executive Officer

No. I don’t, I mean I haven’t, heard anything from them yet. They are looking at what we're doing. But that’s… they are going to move probably slowly and in their normally conservative way there is to take advantage of this information as its fully enough developed to feel comfortable moving it. They're pretty much They’re out there pretty much they are out there pretty far with the gas in place number in their minds, so we're just trying to help them get more comfortable with that and move it forward.

David Heikkinen - Tudor Pickering

And would you expect them to want production per stage from that non-sand pay or any sort of analysis of just completing that or will just your cumulative production for those wells that had not been non-sand pay given enough.

Michael D. Watford - Chairman, President, and Chief Executive Officer

The periodic production logs the stores production log is the key one you got to get it series of logs over time. They can draw some points to determine what the production performance does over time to get the decline curve.

Stephen R. Kneller - Vice President, Exploration

It’s a multi year process.

David Heikkinen - Tudor Pickering

Yes. Okay. That’s what I thought. Thanks.

Operator

And your next question comes from the line of Ray Deacon with BMO capital market. Please proceed.

Raymond Deacon - BMO Capital Markets

Yes. Hey Mike. The question was on, or maybe for Steve. Just what is the completion going to look like and are there any analogies of deeper source rocks that you're modeling this on?

Stephen R. Kneller - Vice President Exploration Domestic

This, Ray. I wish I knew what the completion was going to look like…

Michael D. Watford - Chairman, President, and Chief Executive Officer

This has made our life a whole lot easier. Until we get all the data in we've got. I can see we've got a bunch of core already cut core plugs cut they are off to the labs. We've got to run a lot of sensitivity work and other tests on it to determine what you can do there as far as the deeper shale section that we have to incorporate the learning curves that have come from other shale plays into this factoring in the different debts and temperatures and pressures. But really until we get there and get all the data to even begin the analysis. My crystal ball is even that good.

Raymond Deacon - BMO Capital Markets

Got it. Now I guess I was just curious. Yesterday I mean OG’s call they talked about some of these deeper shales in the you went and they felt like there was a big influence from having sweet spots and which I guess would show up in the permeability, which sounds like you've got a sense so far that the permeability looks fairly encouraging I guess?

Michael D. Watford - Chairman, President, and Chief Executive Officer

Well what we have so far is data from the Blair stand not from the Hilliard Shale.

Raymond Deacon - BMO Capital Markets

Got it, got it. Okay, great. I guess I just wanted to question regarding REX and what that’s going to do to your cost structure as far as if you would get what you guys show as how your 2007 costs all win, kind of 265 and Mcf as far as the breakeven, this going to creep up a little bit I would think in 2008 right with higher cost to put your gas into REX, is that right?

Michael D. Watford - Chairman, President, and Chief Executive Officer

That’s not true, there’s no higher cost per gas into REX. We go into REX the same points, we go into Kern River in North West pipeline CIG now. So there is no increased cost whatsoever.

Raymond Deacon - BMO Capital Markets

Okay. Well, okay, but I guess in a sense, your realized price will be a little lower?

Michael D. Watford - Chairman, President, and Chief Executive Officer

No, I don’t think so, I think our realized price is going to be higher, that’s the whole reason for building REX.

Raymond Deacon - BMO Capital Markets

Right, right, okay. I understand, I got it. Right thanks a lot.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Okay.

Operator

And your final question comes as a follow-up question from the line of Subash Chandra with Jefferies, please proceed.

Subash Chandra - Jefferies & Company

Yes. What do you think based on Q3 realizations when do you… what do you think the pay out is on your sort of average Pinedale completion?

Michael D. Watford - Chairman, President, and Chief Executive Officer

If we use the average pud well year end ’06 which was like a 7B well and $4 dollar gas which was third quarter number I think the rate return analysis is 23% rate return, pay outs about two years.

Subash Chandra - Jefferies & Company

And $4 right, okay.. And your best guess now we talked before I guess the REX impact and all and so that would close the basis, but maybe lock the basis figuratively around a buck and half or so or buck in the quarter or buck and a half, still and that’s REX of course. Is that also the prevailing thought?

Michael D. Watford - Chairman, President, and Chief Executive Officer

We just got back from attending a pilot conference in New York as those folks a little smarter we are about forecasts and what’s going to happen, I think they are basis forecast for 2008 due to REX, Rockies is less than a dollar I think there… dollar term in 2008 is for a $0.92 for 2009. So they forecast, I mean if you look at the basis for Rockies, the $1.50 is going to raise a move the last couple of months which just tells me those are right the basis have no need to move

you just let it stay where it is. There is a margin, you think you may make the margin, let’s get in, let’s get REX to operate and see what happens.

Subash Chandra - Jefferies & Company

And when this I think November 7 or whatever some of this work gets done on that the compressor fire, et cetera. And that stuff comes on, and so if we fast forward September next year I guess the way you are looking at it is now you have committed capacity for 200 a day from.

Michael D. Watford - Chairman, President, and Chief Executive Officer

That's correct.

Subash Chandra - Jefferies & Company

And so depending on what pipeline condition are above the 200 will determine weather you have to shut in again or not.

Michael D. Watford - Chairman, President, and Chief Executive Officer

It’s hard to imagine there is one and a half days of additional supplies that comes on to Rockies next year, Subash. It is only 6.6 Bs in total there production now. So it’s possible.

Subash Chandra - Jefferies & Company

Okay. Great. Thanks.

Operator

And you have no further questions in queue at this time. I would now like to turn the call over to Mr. Watford for closing remarks.

Michael D. Watford - Chairman, President, and Chief Executive Officer

Well, thank you very much for taking time to listening to us. And if you have any other follow up questions, please don't hesitate to call or email us. Thanks.

Operator

Thanks you for your attendance on today’s presentation. This concludes the conference. You may now disconnect. Good day.

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