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Ultra Petroleum Corp (UPL)

Q2 2007 Earnings Call

August 8, 2007 11:00 am ET

Executives

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

Marshall D. (Mark) Smith - Chief Financial Officer

William R. (Bill) Picquet – Vice President Operations Rocky Mountains

Stephen R. Kneller – Vice President Exploration Domestic

Analysts

Brian Singer – Goldman Sacks

Subash Chandra - Jefferies & Company

Clay Cummings – Johnson Rice & Co.

Ray Deacon – BMO Capital Markets

Wayne Andrews - Raymond James Associates

TRANSCRIPT SPONSOR
Wall Street Breakfast

Operator

Good Morning Ladies and Gentlemen and welcome to Ultra Petroleum’s 2007 second 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 but 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 10K 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.

Mike Watford

Thanks Kelly. Good morning and thanks for joining us. Sharing the conversation with me this morning is Mark Smith our CFO, Steve Kneller VP of explorations and Bill Picquet, VP of Operations.

As the press release headline states Ultra Petroleum achieved record production in the second quarter of 2007. The highest quarterly production in our history, up almost 60% over a year ago numbers, achieved with no acquisitions adding to the increase, all organic drill-bit growth.

As for the six month comparison, Ultra’s production increased almost 50%. Of course, everyone is aware of the weak national gas prices in the Rockies. We certainly are. And given this low pricing environment, we are quite proud of the resiliency of our margins. At an average national gas price of $4.38 per Mcf, Ultra’s net income margin for the second quarter was still 31% and cash flow margins 70%. These margins are comparable to our competitors at approximately $8.00 per Mcfe gas. Clearly our competitive advantage is our low cost structure. Ultra’s second quarter all-in costs totaled $2.62 in Mcf, well below others in the industry.

With growing production, low casts, a vast resource and expanding pipeline capacity out of the area just around the corner, we have elected to increase our capital budget and take advantage of the increasing productivity of our rig fleet. We are also increasing production guidance for the year while we assume no production from China in the fourth quarter due to a potential sale and some continued level of [sharedealing] in Wyoming.

Now let me ask Mark to share the financial details.

Mark Smith

Thanks Mike. For the second quarter our corporate production was up 57% compared to prior year levels to a record 30.5 Bcfe. With a Wyoming production up 63 year-over-year compared to 27.9 Bcfe.

As Mike stated our second quarter production was again registered as the highest quarterly production level in the company’s history and was largely due to our continued increase in year-over-year activity in Wyoming and our associated improvement in drilling efficiency. You will hear more about this from Bill in a minute.

Our realized natural gas prices for the second quarter were $4.38 per Mcf while china crude prices registered 59.72 per barrel for the quarter. Primarily as a result of our increased production levels offset in part by these reduced commodity prices revenues for the quarter registered 156.8 million compared to 129.9 million for the second quarter of 2006.

Corporate lease operating expenses for the quarter decreased to $1.11 per Mcfe primarily due to the increased mix of our Wyoming production which has lower unit operating cost combined with decreased severance and production taxes due to lower commodity prices.

Our DD&A rate for the quarter increased year-over-year to $1.25 per Mcfe largely as a result of increased cost being allocated from unevaluated properties to our full cost pool in China.

General administrative expenses were down on the interfaces to $0.12 per Mcfe. Interest cost increased to $0.14 per Mcfe as a result of our increased buying levels in support of our capital program and our share repurchase activity.

The main effect of these factors was a $0.22 per Mcfe year-over-year increase in overall corporate costs to $2.62 per Mcfe. Looking at our cash costs in Wyoming, excluding severance taxes, they increased on a unit basis to $0.45 per Mcfe in the second quarter from $0.39 in the prior year period as we continue to see year-over-year effects of water handling treatment.

Largely as a result of the increase in revenue that I mentioned earlier combined with our continued focus on cost, our cash flow increased 19% over a comparable 2006 quarter to 109.1 million providing a cash flow margin, as Mike indicated, of 70%.

Pretax income registered 77.3 million for the quarter for a 49% margin and income was 49.1 million for the quarter registering at 31% net income margin and $0.31 per diluted share. In terms of recurrence for the second quarter on an annualized basis, our return on equity was 28% and our return on average capital employed was 21%.

At the end of June we had repurchased stocks in the aggregate amount of 237.2 million constituting 4.7 million shares for stock. This resulted in an outstanding share count of 151,892,000 shares as of June 30th. We continue to execute our share repurchase plan and through July we have repurchased an aggregate of 252.9 million and that is 4,979,000 shares in the common stock.

Net cash from operating activity during the quarter amounted to 107.3 million with net cash used in investing activities totaled 214.3 million. Reinvestment activities were primarily comprised of 194.7 million in oil and gas related capital expenditures combined with a 25.3 million increase in payables related to prior periods. Over the quarter, net cash provided a financing activities total of 95.4 million consisting of 115 million in net borrowings and in our senior bank facility combined with 11.6 million of proceeds from stock option exercises and tax benefits from stock based compensation offset by 30.2 million used in our share repurchase program.

Moving to the first six months of the year, 49% higher production volumes offset by 21% decrease in prices led to an 18% increase in revenue. On a unit basis our all-in costs were up only slightly again driven by increased interest costs and higher DD&A rates offset in part by reduced lease operating expense in G&A. As a result, cash flow was up 17% over first half 2006 levels to 242.5 million. Net income for the first six months was largely flat over the prior year period of 115.7 million or $0.73 per diluted share.

In terms of our returns for the first half, on an annualized basis our return on equity was 34% and return on average capital employed was 25%. Net cash provided by operating activity during the first half amounted to 257.8 million with net cash used as in investing activities totaling 365.6 million. These investment activities were largely comprised 361.5 million in oil and gas related capital expenditures together with 9.85 million decrease in payables related to the prior period CapEx.

Over the six month period, net cash provided financing activities totaled 110.6 million primarily consisting of 135 million of borrowings in our senior bank facility and 16.4 million in proceeds for stock option exercises and stock based compensation offset by 39.7 million used in our share repurchase program.

Turning to our liquidity as of June 30th it remains strong with 19.4 million of cash and cash equivalents on hand and 300 million in senior bank debt. As of June 30th our PV cover in our new senior bank facility effectively sets our borrowing capacity at just over $1.3 billion with us liking to set our commitment amount at $500 million. Our board has approved an increase in our 2007 capital budget to 740 million. We believe that our liquidity continues to remain more than adequate to fund this increase through the use of our cash flow from operations combined with our expanded revolving credit facility.

Looking at pricing, natural gas prices softened in Wyoming through August. First of the month index prices at LPAL were $3.37 per mmBTU for August. Cash prices at LPAL are currently running approximately $4.00 per mmBTU.

In terms of basis, second quarter basis differential ran at $3.86 compared to $1.44 for the same period in 2006. As we’ve moved into August, that basis has continued to be volatile and it’s currently just under $3.00.

Looking at our hedge position, one can turn to our press release for the details. Generally, for the summer of 2007 we have 40 thousand mmBTUs per day hedged at a price of roughly $6.73 per Mcf in Wyoming with 10,000 mmBTU per day hedged at $4.98 in Wyoming for the remainder of the year. And over 31% of our forecast production hedged at roughly $7.45 per Mcf in Wyoming. And for calendar 2009 we have a smaller portion of our production hedged at $8.15 per Mcf in Wyoming.

In terms of China crude prices we’ve seen demand for Chinese fuel rebound with crude continuing to sell at a premium to ICP (inaudible). At present, China crude prices are over $66 per barrel. We lifted a 187,000 barrel cargo in July and have a joint lifting tentatively scheduled for September.

In terms of guidance we’re increasing our third quarter guidance to 29 Bcfe and are reestablishing our guidance for the fourth quarter to 28.5 Bcfe, as Mike said, in recognition for potential disposition China’s potential continued [sharedealings] by some of our partners. This brings our full year guidance up from 114 Bcfe to 116.5 Bcfe. This represents a 27% increase over 2006 levels all organic drill-bit growth.

For 2008 and 2009 we’re maintaining our production guidance at 135 and 160 Bcfe respectively. In Wyoming we saw operating expenses are expected to run at $0.22 per Mcfe and gathering $0.25 per Mcfe. We currently expect our Wyoming DD&A rates to run roughly $1.17 per Mcfe.

In China we expect operating costs to average roughly $6.50 per barrel and our DD&A rate to average roughly $13 per barrel. Our effective income tax rate in the country continues to be 35%. Corporately we see our G&A cost at approximately $0.15 per Mcfe for the year.

Now I’ll pass it over to Steve for an update on our drilling activity.

Steve Kneller

Thanks Mark. The second quarter of 2007 saw the continued acceleration of our Pinedale drilling program. This acceleration is due in large part to the significant increase in drill rig performance coupled with the increase in capital budget. Bill will be discussing the details of the improvement in rig efficiency shortly so I’ll leave the details to him.

During the second quarter, 59 gross, 26.1 net new producing wells were brought on stream in Wyoming. For the first half of the year 90 gross, 44.1 net new wells were placed on production. On a net well basis, this is 275% of the level we achieved during the same period in 2006. The average peak twenty four hour rate for the new Pinedale producers was just under 8 million cubic foot of gas per day.

Now let’s review the progress on some of the ongoing projects we have undertaken to improve our understanding and increase the size of Ultra’s Pinedale field output. During the last conference call, I updated you on the success we had in the South Boulder and East Warbonnet areas. In these areas there were a group of new wells that had not been on production for the year end reserves evaluation and they are now on production. With our in house evaluation of the well production performance for these wells we reworked the estimated ultimate recovery math. From this work an increase of gross reserves on Ultra interest’s land of over half Tcf could be realized.

Since then, our delineation work has continued with five additional delineation wells drilled proceeding and plans to drill an additional 13 before year end. One of the new delineation wells, the Warbonnet 5c1-11b which is on the East side of the Warbonnet area that we addressed earlier came on production during the second quarter for the peak 24 hour production rate of 14.3 million cubic foot per day.

Early indication from the other new delineation wells are that they too have met or exceeded our expectations but it is still too early to project total impact of these wells on the overall reserves outlook for Pinedale. We expect to have production performance and other test data on the majority of these wells in time for the year end reserves evaluation.

Shifting gears to the ongoing increase density work, in June Ultra and Shell in a joint application before the Wyoming oil and gas conservation commission received approval for ten acre well density covering an additional 11 square miles of the Pinedale field. Ultra owns an interest in 71% of the area of this approval. This application was brought in support of the drill planning contemplated in the FTIS process.

Also at the same hearing Shell, with Ultra’s support received approval for a five acre pressure pilot project in the riverside area on jointly owned land. During these hearings, data was presented to the commission on the results of six different pressure pilot projects now gathering data in the field. The conclusion of this work is that with wells drilled on less than 10 acre density or less than 660 feet apart, down to as little as 250 feet apart which would be less than five acre density 64% of the 109 (inaudible) did not show effective pressure communication.

This pressure data further supports the need to drill wells in the field at well density less than ten acre to effectively recover the tremendous resource present here. In addition to this work, we’re continuing on our evaluation on all the existing wells in Pinedale that have been drilled at inner well distances less than the 660 feet of a ten acre wall density. At the present time, we have identified over 160 wells that fall into this category. We have been accumulating and evaluating the data of these wells and transferring this information in (inaudible) so they can incorporate this data into the year-end reserves work.

The third major initiative is the evaluation of the non-sand portion land section. This work impacts our understanding in two ways. The land section on average is over 5600 feet thick, of which only about 25% needs the current cutoffs for the physical model that school uses to asset the original gas in place for the field. Plus there’s a lot of room for conceived increase for the gas. By continuing to test the assumptions used in deriving the current day cutoffs and developing the data needed to move those cutoffs in the direction that adds more value to the property.

In the current reserves evaluation process (inaudible) uses, original gas in place is a factor in determining what the only reserves assignments can be in a given area. That being said, having the gas in place be as high as is reasonable to insure us the best outcome on the reserves assignments that Ultra gets from its own soil.

Under our current completion practices, the current interval included in the stages is only equal to about 41% of the land’s interval. Given that the core work and information indicated that the entire section is gas saturated, we thought it prudent to attempt to get economic production from that portion of the land’s interval not now producing.

You can think of this as essentially a shale play sandwiched in with the land’s tight gas in play. The portion of the land section right now not currently being completed could be viewed as the equivalent of the 30 foot lateral in a gas saturated shale section. And since we will be drilling a well [borsh] for the sand section anyway, there’s only completion drops relating to bringing these additional reserves to production.

Ultra is currently in the early stages of testing these ideas with an eight well pilot program now underway. Two wells are currently drilling, two are waiting in completion, the remaining four are already in production. Today we have gotten production logs run on the first two producers to measure the production from the completed zones. The evaluation of the production logs on the first two wells gives us a very preliminary look at the results. On first flush, these initial two wells appear to have been successful t adding production and reserves from a stimulated non-sand intervals at economic rates.

We plan to run a series of production logs on these wells to verify these early results. From we can determine the contribution from the non-sand zones and also assess how production rates change over time to support the economic decisions. Our goal is that as this production in reserves on top of the current volumes from the wells for only the cost of the added completion stages.

By keeping the costs for the additions at less than the finding development costs the overall program, this could be a huge win-win from a reserves, production, and economic standpoint. This project will continue through the year gathering more data and adding additional wells to be tested as needed to support the effort to both move the cutoffs downward for the ongoing reserves work, and at the same time, increase the overall work per well production rate and an average finding a develop costs less than or equal to our $1.20 per MCF goal for 2007.

With success in adding economic reserves and production this program could easily be expanded to the majority of the wells remaining to be drilled in the field.

Updating in the progress on the exploratory well on Pinedale, the rig was moved back on the path and drilling resumed on June 17. At the present time, we’re drilling below 12,200 feet in the land section. We expect to reach our planned 19,500 foot total depth, to test the Hilliard, Blair, and Rocksprings formations by mid-November.

The timeline for testing will depend on what we find and the time needed to evaluate and incorporate all of the data that we are gathering into a sound completion plan. Very briefly on Pennsylvania, testing of the margins unit, number two wells continuing. The margins number three tested water in the (inaudible) and we are reevaluating the wells to determine the next course of action there.

The margin number continues to produce at 3.1 million cubic foot per day. We are reassessing our strategy for this property to determine how best to move this forward to the benefit of the company and the shareholders. With that let me pass this on to Bill Picquet, for his update on Wyoming operations. Bill?

Bill Picquet

Thanks, Dave. [Oakford’s] activity has increased significantly in 2007 in Wyoming. This is mostly the result of increased efficiencies in our operations. We’re drilling more wells per rig this year, and are continuing to build momentum on the significant improvements in our Wyoming drilling efficiency.

The following stats provide a glimpse of our performance year to date. We set a new Ultra record for drill time on the Pinedale in the second quarter, spud to TD in 22.8 days. Our average year to date spud to TD for Pinedale was just under 40 days. In the second quarter, our average spud to TD was 33 days. Our average year to date spud with rig release is 46 days; in the second quarter average was 39 days.

These stats confirm that our second quarter performance continues to improve substantial over the first quarter. The best rig performance has been in our fit for purpose skid capable rig drilling multiple wells on our simultaneous operations. Recent performance is clearly confirming our belief that we’ll have a great deal of success in the future drilling efficiencies on pad applications with fit for purpose skid capable rigs.

Reemphasizing the magnitude of our improvement year to date at Pinedale, our overall first half averaged drilling time spud to TD was 39.9 days, a 35% reduction from the 61 days well average for full year 2006. We expect performance improvements in both drilling time and costs continue trimming downward as we gain more experience in the oil based mud and as we pursue additional technology proficiencies, we’re continuing to improve our overall rig fleet, and we feel that the future upside in performance efficiency is still substantial. Our drill fleet continues to evolve. We’re currently operating 12 rigs in Pinedale and are expecting delivery and late Q3 of our new Patterson skid rig. This rid can drill five well pairs, to a total of ten wells using extending capability without moving any of the rig equipment.

We’re continuing to evaluate our options for future rig operations and we’re maintaining flexibility in our commitments in the anarchy.

As Steve noted earlier, we’ve been very active during the first half of the year in our completions operations. We’ve pumped a total 817 (inaudible) during the first two quarters of 2007, compared to 411 in the same timeframe during 2006, almost twice the level of completion year-after-year. Ultra’s averaging of delivering a case well ready for completion every four days. This is the product of our improved drilling efficiencies and we’re very excited about the futures as we look forward to continuing to improve our overall operations performance.

Now a quick update with the FDIS. We have a participating record decision later in 2007 as the BLM continues to work through the public process. However, as we stated previously, our 2008 operations plans are not dependent on the timing of the rod. With that, let me turn things back over to Mike.

Mike Watford

Thanks, Bill. Let me pause and summarize what I think we’re doing and where I think we’re going. But first a reminder as to who we are. Simply an exploration production company focused on profitable growth. We’re doing an excellent job delivering on this goal for the last five years with a combination of returns and our growth is second to none. We plan to continue this leadership. Our primary asset is the Pinedale field itself in (inaudible) Wyoming, a legacy asset, currently estimated as the second largest natural gas field in the US. And it grows in five each year.

Ultra is the largest owner. We have booked prep reserves of 2.4 (inaudible) cubic foot equivalent. Year-end at ’06 and current production of about a little of 300 million a day net. We have what is most likely the lowest cost structure in the business.

So what are we doing now? We have three initiatives focused on expanding on our resource base in Wyoming, as Steve mentioned. First, expansion of the Fairway true delineation drilling. Second, reviewing performance of producing wells drilling at increased density and their orientation to determine if current reserve estimated for un-drilled locations are reasonable. Our guess is they’re little.

And third, determining if some portion of the non-sand component of our thick land vertical section is effective. On access issues, for the development of the resource and in accessing more markets, we’re moving forward. For the FDIS process for our partners, we are moving toward a time of more access to the Pinedale field which will aid in the development of the secure US long life natural gas resource. We are participating in making a more interesting pipeline capacity available to Rockies producers, by being an anchor shipper on REX and committing to 200 million cubic feet of data for transportation.

For the increasing productivity from our rig fleet at lower cost, we’re improving our well economics.

The next question is where are we going? First, in less than five short months, REX will be operational, and we believe Rockies natural gas prices will rebound strongly. For 2008 we believe an average $7 [print TFE] natural gas price for Ultra’s production is not unreasonable. With almost one third of our [forecast] ’08 production edged currently $7.45 per NCFE in Wyoming. For prices for 2009 are even stronger, at about $8 per NCFE in Wyoming. For a potential sale of a Chinese asset our already industry cost structure will improve further. We have provided preliminary production guidance for 2008-2009 which to judge approximately 40% organic production growth over the two year period.

Earnings in cash both for 2008 can easily increase 60-70% over 2007. In terms of resource potential, we have a third party identified resource pays net to Ultra of approximately 10 trillion cubic feet equivalent. With our internal expectations of growth, to 12 trillion cubic feet, without any expiration of acquisitions assessed. That’s four to five times Ultra’s currently booked proofed preserves. All within the existing Fairway. All low decline, low asset intensity, long line, low cost, natural gas resources.

We are very positive about Ultra’s direction and our ability to continue creating profitable growth. Also I’d like to thank Jim Rowe, our retiring director for his service, council, humor, and perspective. We will miss his contributions.

On our transfer from the AMEX to the NYSE we wish our friends at the AMEX well and look forward to developing new relationships at the NYSE.

And now I’d like Bill to make call for questions.

Question-and-Answer Session

Operator

Thank you. We will now begin the info session. (Operator’s instructions) Our first questions come from the line of Brian Singer of Goldman Sachs. You may proceed.

Brian Singer – Goldman Sachs

Thank you. Good morning. Based on the improved well results, the ability to drill more quickly, and as you look forward over the next few years, assuming the SEIS gets approved, is there any change to your thought process on what the capacity is in terms of well completion?

Mike Watford

Well, capacity well completions, the SEIS is studying 285-300 wells a year, or something along those lines. Those are the gross wells, not net wells. Clearly, probably half those wells, more than half those wells, will be drilled by Ultra, so it will require us from going from, you know, 90-100 wells a year of gross operating to at least 150 or 200. So can we go above that, yes, but not uniformly or consistently. I think that would sort of be the feeling that you could bob and weave around. Billy, you want to answer any more of that?

Bill Picquet

Uh, I think that as we’ve said, there’s room for continued improvement as far as efficiencies are concerned, Brian, and it just kind of depends upon how many rigs we wind up thinking is the appropriate level of rigs. As Mike said, we’re analyzing a greater number of rigs than the SEIS, so that gives us continued capacity at that point in time, to see where that goes.

Mike Watford

Now Brian, let me partially reverse myself from what I just said, as though well count were the ceiling. We know we could pierce through that for a bit, but probably not aggressively, but that was, the derivation of that was number of rigs running and the emissions and surface disturbances and what not. So I think what Bill’s saying is to the extent that we can continue to bring down the days to drill, and effectively drill more wells per year with the existing equipment, with the existing pads, with the existing emissions. That would probably go a little faster.

Brian Singer – Goldman Sachs

That’s great. In the eastern Warbonnet area, you mentioned some of the stronger results that you’ve seen. Do you have, can you talk a little more about what you think is driving that and how widespread that may extend?

Steve Kneller

Hi Brian, it’s Steve. What we told you about the last call was the group of wells that we had drilled on that edge. We had encountered better quality sand than we had anticipated, normally as you get towards the east edge of the field, you start to see a little deterioration in the sand quality in this particular area and kind of the east edge of the boulder area. We’re not seeing it deteriorate as quick as we had thought it would, and the well completions are reflecting that. We’re getting very good completions, we have Warbonnet and 521 11b that I mentioned earlier in the call, is the easternmost well in the particular area, and it came on with a very high initial rate. We’ll wait to get enough production performance to see what the ultimate EUR is on that, but pre-drill it was about a 6 Bcf well, so I would anticipate it will be somewhere about that, how much further we just don’t know at this point. But it seems to be mainly the same quality driven it, issue over there.

Brian Singer – Goldman Sachs

Great, and if I could just get one more in. Given the strong rates that you mentioned and the greater wells that you’re drilling, what is the driver of production guidance that’s down in the third quarter versus second quarter?

Mike Watford

It’s just less oil production from China. That’s all.

Brian Singer – Goldman Sachs

Great. Thank you.

Operator

Our next question comes from the line of Subash Chandra of Jefferies. You may proceed.

Subash Chandra - Jefferies & Company

Hey Mike, on the two wells, do you have an average cost to drill, and an average cost to complete?

Mike Watford

Bill, do you want to do that?

Bill Picquet

Well, I’ll just talk about our cost performance in general, Subash. We said in the last call that we thought a reasonable target ultimately, when we get all fit-for-purpose rigs in, would be around 6 million all in to drill and complete. And we’re actually experiencing wells below that number with our best performing rigs today, so we know that that’s a realistic target. Our current performance year-to-date is actually 7 million, and that’s due in part to the fact that we have a number of rigs still in the fleet that are older and less efficient. They move slower, and so they’re not pad-skiddable rigs. We’re also drilling a fair component of delineation wells, which means we have to move more often, so we still expect that number to continue to come down on performance on actual drill time, even though the older rig has come down substantially this year, so, on cost we’ll continue to improve and we’ll continue to make decisions go forward to improve the fleet.

Subash Chandra - Jefferies & Company

How many pad rigs do you have?

Bill Picquet

Right now, we have four, we’ll be getting a fifth in late 2-3, so of the 12 rigs right now, we have four that are skiddable.

Subash Chandra - Jefferies & Company

How many wells were drilled in the second quarter?

Bill Picquet

Oh, drilled by us, or drilled by everyone?

Subash Chandra - Jefferies & Company

Everybody, if you’ve got a net number?

Bill Picquet

There were a total of 91 new wells in the second quarter that we had active, that’s the total , so 47 wells in the second quarter versus 44 in the first. Those are wells that were studded in the second quarter.

Subash Chandra - Jefferies & Company

That’s the gross number, right?

Bill Picquet

Yeah. Yeah.

Subash Chandra - Jefferies & Company

OK, I can do the net, I think.

Bill Picquet

Net is about 21. I don’t have the exact number in front of me Subash.

Subash Chandra - Jefferies & Company

No, no that works. Thank you. And final one is, so now I guess we’ve got to get from the draft SEIS to the final SEIS as an intermediate step before the ROD. Do you kind of have a timeline for that?

Mike Watford

It’s difficult Subash to predict an exact time. The DLM runs a process, and it’s progressing along as far as the writing goes. I guess it’s taken longer than we anticipated, but it’s still moving along.

Subash Chandra - Jefferies & Company

All right, and then finally, a flavor on those wells where you are testing additional zones, and I guess the couple that you have. So what additional IP you think you’re getting, and the additional well cost.

Unidentified Company Representative

On the cost side, your typical frack stage is about $108,000 a stage, the production logs we’ve run on those first two wells, the average on those stages is such that we would think we’re getting right about that buck twenty m kind of F&D for the investment. It’s hard to say right now, I mean we’re so early in this game. We’ve got just one production log and one snapshot point in time. We are expected to get additional productions logs here yet this summer and then on into the fall to try to build a curve for those zones. So it’s, right now, it’s the very preliminary data point, but at least at this point we feel that first blush it looks like it’s economic.

Subash Chandra - Jefferies & Company

That still helps, thank you.

Operator

Our next question comes from the line Clay Cummings of Johnson Rice. You may proceed.

Clay Cummings – Johnson Rice & Co.

Good morning. Just a follow-up on the wells, pad wells, rather rigs, just curious, is the plan to move to, you know, eventually have a fleet of all fit-for-purpose skid-capable rigs, and are your partners following suit?

Mike Watford

We have a mix of rigs that are pad rigs that are skiddable and very efficient moving delineation rigs. So ultimately, it will take some time to get to that point, but that’s ultimately where we’re going. As far as the other operators are concerned, I’ll let them speak for themselves as far as what their plans are, but they also have a small component of skid capable rigs at this point in time.

Clay Cummings – Johnson Rice & Co.

OK, great. Just I wanted to clarify a question previously asked, on the impact in the second half of the year. Press release noted that, not only were you not counting China production in the fourth quarter, but that there were partner shut-ins that were going to impact production. Can you quantify the anticipated shut-in, or rather impact to production of those shut-ins, to Ultra?

Mike Watford

Well I can, the question is will I? Let’s do it this way, I mean, we have another operator up there that’s had some shut-ins in gas already this summer and is talking about possibly continuing to have some shut-ins, so we’re just trying to cover that, and we’re also trying to cover the loss of production from the China assets in the fourth quarter. So let me answer it this way. Of our revised charter of 116.5 Bcfe for 2007, which is what, a 27% increase over last year, we could easily be at 119, or 120 Bcfe’s for the year, if we didn’t have to cover some of these potential shut-ins or loss of production due to sales.

Clay Cummings – Johnson Rice & Co.

Ok, that's great. And then regarding the Pennsylvania shale, that second rig they encountered, the second well that encountered water. Can you just comment on as far as location goes on the reservoir, would you [down dip] to the previous successful well, or what happened in that well, I guess, as opposed to the [marsh] on number one?

Unidentified Company Representative

Well, to be completely honest. I’m not really sure. Data quality doesn’t let us know for sure where we are, but we didn’t get something that looked exactly like the first well, we pumped it anyway and got water. And we’ve got a lot of evaluation to do at this point to decide what the right path forward is at this point. We’re still in a very preliminary stage out there, and I’m going to leave it at that for the moment.

Clay Cummings – Johnson Rice & Co.

And then last question, can you just update us on your existing inventory of drillable locations on the Pinedale, with this recent increase, or approval of 10-acre spacing.

Mike Watford

It doesn’t really change the inventory, what it does is it moves some wells, you know, some locations, you know [Netinsul] had already identified them in the reserves report, it just puts the commission approval finally in place for those, so it was about 280 10-acre locations that were in that area. But again, they were already in the inventory, already in the reserve report.

Clay Cummings – Johnson Rice & Co.

OK, great, thank you very much.

Operator

(Operator Instructions) Our next question comes from the line of Ray Deacon of BMO Capital Markets. You may proceed.

Ray Deacon – BMO Capital Markets

Yeah, hi, Steve or Mike, I was wondering with the 12 CCF internal number you guys are talking about, does that include anything for the shales, or the 5 acre spacing or anything for the deep well?

Unidentified Company Representative

It does include a possible contribution from delineation, a possible contribution from further increase [subsidy] work and the work on the [hair cuts] are possible contributions from the shales, it doesn't include any contribution from the deep section.

Ray Deacon - BMO Capital Markets

Ok, Got it. Ok, with the shale contributions. What would that mean to your costs and, would you be able to tap into those, on the existing wells, where you've already completed and it would just mean an upward revision to the reserves you can get from the wells you have. Or would it change the completion method going forward?

Unidentified Company Representative

Mainly going forward; the existing well boards are already perforated in the sand, top to bottom. The ability to go back in and re-complete in between is pretty challenging. There would be an addition on, any future wells that we could drill. Obviously you’re adding cost, which is why we're looking at some (inaudible), when we add the costs, and get more production and more reserves [just] that the average F & D stays in line with what our goals are.

Ray Deacon - BMO Capital Markets

Right.

Unidentified Company Representative

And the other part of this is Ray, and Steven is much more eloquent on it than I am, is just the opportunity to increase gas in place. If you’re successful in getting any sort of economic contribution from part of the shale is that the whole gas in place estimate that [Netsonil] is using or some of the cutoffs we have in reserve, the evaluation would all help us improve.

Ray Deacon - BMO Capital Markets

Got it, Thanks. Ok, for the economic cut-off, it's spun out. Any, I guess, Bill, can you talk about where you think you can drive that (inaudible) release from the 39 days you in the second quarter, where do you hope to be able to get that?

Unidentified Company Representative

Well, we're seeing right now that it's going down as low as 33, so (inaudible) rig we're seeing drill times below 30 days, and skip times [Potentially less..]So, on tad wells, those days can go down into the low 30's.

Ray Deacon - BMO Capital Markets

Right, got it. Thanks a lot.

Unidentified Company Representative

Thanks Ray.

Operator

(Operator Instructions) And our next question comes from the line of Wayne Andrews, of Raymond James, you can proceed.

Wayne Andrews - Raymond James Associates

Good morning Gentlemen; another excellent quarter. Most of the questions have been asked, but I want to get some additional clarification on how you quantify delineation wells and is that related to your 4Bcf cutoff, and then maybe what other areas other than Warbonnet, will you be trying to extend the limits of the field?

Unidentified Company Representative

As far as delineation wells, generally how I'm classifying is, if it's the first well drilled in any given quarter section, that clearly would be a delineation well. Additionally if a subsequent well in that quarter section where you've got the first well down, and there were issues with it, maybe you didn't get open hole logs, or you had some problems with it and you’re drilling a second well to confirm what you found in the first one. That would also classify as delineation well. In the SEIS process the core development area, as the BLM defined it for Pinedale, was what they saw is the core of the field, and within that area we have 50 quarter sections, but we haven't had the first wall drilled in yet, so we still have a lot of drilling in what is seen as the core.

If you add the half-mile buffer zone around the outside that has been discussed with the BLM, that would add an additional 50-quarter sections where the first well hasn't been drilled yet, and, I don't want to say we're going to add that entire area, but I think at least the results to date would say we're going to have chunks of that mainly on the east side of Warbonnet, and in the area between Warbonnet and Boulder, and the east side of Boulder, that's the area where we're going to have the most significant expansion of our fairway at this point.

Wayne Andrews - Raymond James Associates

And that would be an expansion, or essentially pushing that 4Bcf contour line further out from the center of the field?

Unidentified Company Representative

Correct. Moving the gas in place line out and correspondingly moving the EUR contours out.

Wayne Andrews - Raymond James Associates

Excellent. You've got a lot of work to do still.

Unidentified Company Representative

Oh yeah.

Wayne Andrews - Raymond James Associates

Very good, thank you.

Unidentified Company Representative

Thanks Wayne.

Operator

(Operator Instructions) And there appears to be no further questions at this time. I would now like to turn the call over to Mike Watford for any closing comments.

Mike Watford

Well, thank you very much for your time, and obviously if anyone has any additional questions, please don't hesitate to give us a call. Thank you. Bye.

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