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Executives

Kelly Whitley – Manager, IR

Mike Watford – Chairman, President, and CEO

Mark Smith – CFO

Bill Picquet – VP Operations, Rocky Mountains

Sally Zinke – Director of Exploration

Analysts

Subash Chandra – Jefferies & Co.

David Tameron – Wachovia Securities

Kent Green – Boston American Asset Management

Mike Scialla – Thomas Weisel Partners

Ron Mills – Johnson Rice

Wayne Andrews – Raymond James

Jeff Davis – Waterstone Capital

Ultra Petroleum Corp. (UPL) Q2 2008 Earnings Call Transcript August 6, 2008 11:00 AM ET

Operator

Good day, ladies and gentlemen, and welcome to the second quarter 2008 Ultra Petroleum Corporation earnings conference call. My name is Heather, and I will be your coordinator for today. (Operator instructions) As a reminder, this conference is being recorded for replay purposes. And now I turn the presentation over to your host for today's conference, Ms. Kelly Whitley, Manager – Investor Relations. Please proceed.

Kelly Whitley

Thank you, Heather. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's second quarter 2008 earnings conference call.

Before I turn the call over to Mike Watford, Ultra Petroleum's Chairman, President, and Chief Executive Officer, I must 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 10-K filings with the Securities and Exchange Commission.

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

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

Mike Watford

Good morning. Welcome to Ultra's second-quarter earnings conference call. Joining me this morning is Mark Smith to discuss our financial results, Bill Picquet on the operations side, and Sally Zinke with an exploration update.

But before I get started, let me share with you a fortune I got from a fortune cookie yesterday at lunch. When I cracked open my cookie in the midst of the tropical storm raining here in Houston, the fortune said, "Your hard work is about to pay off." And I think that is certainly what we see reflected in our second quarter results with the success of the Ultra team.

We are very pleased with our second quarter. Ultra's team delivered impressive financial results. It is not everyday that you double your earnings and cash flow, in particular when you do it all organically without acquisitions and without dilution to your shareholders. Our returns on equity and capital are double what others hope to achieve. We established new records in all phases of our business – earnings, cash flow, production, and in fewer days to drill wells. Our six-month results equal or exceed any full-year results in our history.

Again, we are very pleased with our success. Key items that will be addressed by our team this morning are costs and margins, drilling productivity, resource expansion in Wyoming and Pennsylvania, and access.

Mark, would you like to share some comments?

Mark Smith

Yes, thanks, Mike. For the second quarter, our Wyoming production was up 23% on a comparable year-over-year basis to a record 34.3 Bcfe. Once again, our quarterly production registered 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, as well as our associated improvement in drilling efficiencies. You will hear more about this from Bill in a minute.

Realized natural gas prices for the second quarter were $8.06 per Mcfe, while condensate prices registered $112.44 per barrel for the quarter. As a result of our increased production levels, combined with higher commodity prices, revenues for the quarter registered $294.1 million compared to $156.8 million on a combined basis for the second quarter of 2007.

Corporate leased operating expenses for the quarter registered $1.55 per Mcfe, largely as a result of increased severance and production taxes due to higher commodity prices. With REX-West now operational to Missouri, we are incurring demand charges at an anchor shipper amounting to $0.77 per Mmbtu on our 200 million per day capacity. Again, these transportation charges essentially lock in our basis. The Midwest markets on these volumes were no longer simply an Opal price taker. These transportation charges amounted to $12 million this quarter or $0.35 per Mcfe on our total production volumes.

Our DD&A rate for the quarter registered at $1.25 per Mcfe, primarily as a result of our development cost increasing through 2007. General and administrative expenses were down on a unit basis to $0.13 per Mcfe, while interest costs also registered $0.13. The net effect of these factors was a $0.79 per Mcfe year-over-year increase in overall corporate cost to $3.41 per Mcfe. Looking at our cash cost in Wyoming, excluding severance taxes, they were down from the first quarter on a unit basis to $0.51 per Mcfe as we move past the onetime effects of outside operating costs.

Largely as the result of the increase in revenue that I mentioned earlier, combined with our continued focus on cost, our cash flow more than doubled over the comparable 2007 quarter with a record $222 million, providing a cash flow margin of 76%. Pretax income registered $177.4 million for the quarter for a 60% margin. Net income was a record $115.2 million for the quarter, more than doubling over prior-year levels and providing a 39% net income margin, $0.73 per diluted share.

In terms of returns for the second quarter, on an annualized basis, our return on equity was 47%, and our return on average capital employed was 36%.

We continue executing on our share repurchase plan. Through the end of June, we had repurchased stock in the aggregate amount of $363.2 million, constituting over 6.5 million shares. This resulted in an outstanding share count of just less than 154 million shares as of June 30. During the month of July, we repurchased an additional $67.8 million amounting to over 878,000 shares of our common stock. Additionally our Board has improved an additional $250 million of share repurchases, increasing the total authorization to $750 million under the $1 billion plan.

Cash from operations during the quarter amounted to $201.5 million, with cash used in investing activities totaling $199.7 million. These investment activities were largely comprised of $229.7 million in oil and gas related CapEx, partially offset by $23.6 million increase in payables related to prior period CapEx. Over the quarter, net cash provided by financing activities totaled $12.3 million, consisting of $51.2 million of proceeds from stock option exercises and tax benefits from stock-based compensation, offset by $38.8 million related to our share repurchase program.

Looking at the first six months of the year, 16% higher production volumes on a combined basis together with 53% higher natural gas prices led to a 70% increase in revenues. On a unit basis, our costs were up again due to increased production and severance taxes and higher non-operating expenses. As a result, operating cash flow was up 74% over the first-half 2007 levels to $423.4 million. Net income for the first six months increased 87% over the prior year period to $216.5 million or $1.37 per diluted share.

Moving to our liquidity, as of June 30, it remains strong with $60.3 million of cash and cash equivalents on hand and $300 million in senior debt. Our Board has approved an increase in our 2008 capital budget to $945 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 revolving credit facility.

In considering our price outlook for 2008, it is important to understand our hedge position. First, through October, we have 120,000 Mmbtu per day hedged through physical contracts, and our price is roughly $7.32 per Mcf in Wyoming. Second, we have 200 million a day of firm transportation capacity on REX to the Midwest where we are receiving midcontinent pricing. And finally, we have financial swaps in place at Wyoming through October at a price of roughly $7.69 per Mcf. For November and December, we have physical contracts on 100 Mmbtu per day, hedging our price at approximately $7.31 per Mcf in Wyoming. Then we have our 200 million per day affirmed capacity to the Midwest. The remainder of our gas has been exposed to index pricing at Opal by design, as winter months typically show strength. Bottom line, for the third quarter and through October we don't have exposure to index prices at Opal. As we move through November and December, we have only limited exposure to Opal index prices.

We move into 2009; for the summer, we have 90,000 Mmbtu per day hedged at a price of roughly $7.55 per Mcf, and for calendar 2009, we have 40,000 Mmbtu per day hedged at a price of roughly $7.91 per Mcf.

In terms of guidance, we continue our third-quarter production guidance of 34.5 to 36 Bcfe. Our new full year 2008 guidance is 143.4 to 147.4 Bcfe. In Wyoming, lease operating expenses are expected to run $0.27 per Mcfe and gathering $0.26 per Mcfe. We currently expect our Wyoming DD&A rate to run roughly $1.28 per Mcfe, and we see G&A costs at approximately $0.14 per Mcfe for the year.

Now I will pass it off to Bill for an update on our operations.

Bill Picquet

Thanks Mark. Wyoming in the second quarter we brought onstream 66 gross, 33 net new producing wells. The average initial 24-hour sales rate for these producers was 7.4 million cubic feet per day. Ultra's operated Pinedale wells averaged 7 million cubic feet per day, while the non-operated wells average 7.9 million a day. The high was from the Ultra-operated Warbonnet 5-9d [ph], which floated 11.1 million cubic feet of gas per day. At the end of the second quarter, there were 15 Ultra-operated rigs drilling in Pinedale. A total of 12 non-operated rigs were also active on Ultra interest in that. During the second quarter, our drilling and completion operating efficiencies continued to improve. Operational highlights this quarter include another Ultra record for drill time on the Pinedale Anticline, 15 days spud to TD, the average 22 days spud to TD for Ultra operated wells in the second quarter, an improvement of 37% versus our Q2 2007 average of 35 days. Ultra drilled and cased 44 wells during the second quarter of 2008 compared to 23 during Q2 2007, 91% increase quarter-over-quarter, eclipsing our previous quarterly high of 30 wells during the first quarter of this year. At our current pace of drilling, our projected rig count for the full-year 2008 we anticipate about 155 Ultra operated wells compared to 87 Ultra operated wells drilled in case during 2007, a 78% increase year-over-year.

Our overall drilling performance continues to improve. Currently we are operating 15 rigs in Pinedale. This includes nine skid rigs with a ninth scheduled for delivery later in the year. Skid rigs drilling on pads continue to set the standards for drill time and costs. For example, second quarter, our development wells have averaged 21 days spud to TD. Our pad rigs with skid capability have averaged just over $3.3 million to drill and case. Year-to-date, our total cost to drill, complete, and equip a Pinedale development well is $5.7 million. Record 15 day well mentioned earlier translates to a full cost of less than $5 million, drill to production. I am confident that our drilling performance will continue to improve. We continue to refine our practice of drilling underbalanced at along with new bit technology improvements, providing ongoing significant – (technical difficulty). We're having very good initial results with the other new technologies. We will provide the potential additional efficiency. We plan to expand their use in the future results; we're convinced that we will continue to see reductions in drill times.

Our approved record of decision in the SEIS, we see the potential for additional efficiency in our operations, drill rate moves, benefits of continuous drilling operations on a single pad location, same rig and the same crews and other operational synergies to closer proximity of operations in our concentrated development areas.

Cost of services has increased. Particularly, the cost of steel has increased substantially. We continue to drill faster, and we are offsetting these cost increases with our efficiency of drilling. Slight increasing cost of services in pipe [ph], we have held development well costs flat at $5.7 million per well in the second quarter. Drilling efficiencies are providing more wells to complete. Our completion efficiencies are allowing us to maintain this increased pace. Completion costs have decreased slightly during 2008 year-to-date versus our 2007 full-year average. We're bringing wells online quickly once they are cased and ready for completion. During 2008 we're continuing to increase our number of stages per well, averaging almost three more stages per well in the first half of 2008. Through midyear 2008, we have averaged 24 stages versus an average of 21 for the full year in 2007. Increase in stages is primarily due to continuing encouragement from our results in our low quality paid program. Sally will discuss this in more detail later. Overall, our completion efficiency and associated cost performance in the first half proved to more than offset the cost of these added stages, averaging slightly less than $2 million per completion, less than $100,000 per stage. We are forecasting that it will pump almost twice as many stages in 2008 versus the year 2007. Not any change in average time to first sales.

Regarding the SEIS, we're nearing completion of the process. Final SEIS was issued the 28th (inaudible) comment date period by 28th. Record of decision is expected sometime in early December. We're looking forward to transitioning to the new development rules in the end of the fourth quarter of this year. With that, I will hand things over to Sally.

Sally Zinke

Thanks, Bill. Reviewing our delineation drilling for the first half of 2008, this delineation program to continue field expansion has been increased from an expected total of 28 delineation wells to spud in 2008 to a total of 32 spuds during the year, primarily due to the increased drilling efficiencies described by Bill. This is a year-over-year increase of 146% from the 13 delineation wells drilled in 2007. At the end of the first quarter, four of these delineation wells had been drilled and completed. Due to access issues by the end of the second quarter, we had a total of six delineation wells drilled and completed, with an additional well waiting on completion. The production history from these six completed wells indicates that the reserves will be more than doubled the Netherlands Sewell predrill reserve estimates for these locations. We're excited about these results and our plans to accelerate them.

If we consider the year-end 2007 Netherlands Sewell estimates for the 90 square mile Pinedale field of approximately 53 Tcf original gas in place and a total field EUR of nearly 31 Tcf, the average OGIP per square mile is 588 Bcf with about 330 Bcf of recoverable gas. Based on early internal reserve estimates, the delineation wells drilled in the first half of 2008 are adding between 250 and 275 Bcf per square mile of recoverable reserves at the current edges of the field. Within access of 70 delineation wells planned by year-end 2010, we expect the field expansion to continue with at least 60 Tcf gas in place.

Now moving to activity related to increased density drilling; on July 15, 2008, Ultra and Shell received approval of a joint application from the Wyoming Oil & Gas Conservation Commission for 10 acre well density for an area, including nearly 100% of Ultra-operated acreage within the current boundaries of the Pinedale field. This will facilitate forward planning and efficiencies in the continuing development of the field.

Another of our ongoing programs is the low quality pay portion of the Lance Pool, something we previously called non-sand. As you will recall, we began a program last year to assess the addition of reserves and production from portions of the Lance considered to be below current Netherland Sewell pay cutoff. At the end of the second quarter of 2008, a total of 45 wells had been completed and 178 added stages with an average of four additional stages or 450 feet per well, meaning we are fracing 50% of the gross land section in those wells. Monitoring programs for those wells includes sequential production logs to evaluate sustainability and the quantity of production from the LQ stages. We have four wells with three production logs from which we can establish performance that matches traditional land sand completion stages with estimates that each stage is providing an additional 100 to 150 million cubic feet of gas reserves for the incremental cost of an extra frac stage at about $90,000 per stage. To date, much of our evaluation of LQ has been in the Warbonnet area. We feel the additional completion efforts provide continued reserve and production growth and anticipate expanding this assessment northward.

Now let's talk about our deep exploratory wells. We indicated in our last quarter call that we expected to begin completion of the 19,500 foot Mesa 10D-33 beginning with the Hilliard shale in the deepest portion of the well. The frac design is based on X-ray diffraction analysis of core, diagnostic fracture injection test or DFIT moving up-hole in a judicious manner to optimize the completion. We have proceeded with that completion operation and have currently perfed and fraced 1,400 foot thick Hilliard section in a total of seven frac stages, the most recent last week. At this point it appears that we have not accessed a natural fracture system in the Hilliard, and although the well has been flowing at rates above 5 million cubic feet per day at times, these rates are not sustainable. We're beginning plans to move up-hole to complete the 1900 foot Blair sand section.

Finally, Ultra's 2008 activities in Pennsylvania, in Pennsylvania Ultra has a 50% non-operated working interest in two Oriskany discovery wells drilled during the second quarter. These wells were drilled based on 115 square miles of 3-D seismic. From the flow test, the operator estimates the first of these wells to be capable of making over 5 million cubic feet of gas per day. The second well looks as good or better than the first well in early flow test results. These wells also indicate that the Marcellus shale potential in the area is comparable to productive areas to the north in New York and elsewhere in the trend. Oriskany production is structurally controlled, and the 3-D seismic indicates seven or eight additional wells on the current feature, with four or five more prospects within the 3-D outline. Also, in the second quarter of 2008, Ultra drilled two vertical Marcellus exploratory wells on operated lands in the Marshlands area. Both of these wells had promising shows in the Marcellus. The Bergey [ph] is scheduled for completion in late August, the Thomas has been fraced, and initial flowback is in progress. We're running tubing to further test this well, but are having trouble keeping the well dead in order to run the tubing. So currently we have no estimates of quantities.

Ultra has plans to drill two additional vertical Marcellus wells in the Marshlands area in the late September to early October timeframe. We plan to shoot a 3-D seismic survey in the Marshlands area later this year to further assess Oriskany, Marcellus, and deeper potential in that area. Ultra also expects to participate in at least 20 non-operated Marcellus exploratory wells over our 270,000 gross acre Pennsylvania land hold. The program is scheduled to begin later this week.

Back to you, Mike.

Mike Watford

Thank you, Sally. Let me quickly summarize where I think we are. We think we continue to lead our industry in growth and returns with a great deal of consistency. We're delivering double-digit production growth with triple digit earnings and cash flow growth. We have increased our 2008 production guidance in spite of the fact that we plan to shut in natural gas in September due to interstate pipeline maintenance. Our resource expansion continues in Wyoming with the delineation drilling success and low quality pay validation providing comfort that our 14 Tcfe target is achievable, a number which is over four and a half times our current proved reserves. Our early stage success in Pennsylvania appears additive to this target. Our drilling productivity is increasing, and access to our acreage should be improving shortly.

Thank you. Now we would like to answer some questions.

Question-and-Answer Session

Operator

(Operator instructions) Your first question comes from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra – Jefferies & Co.

Hi, good morning, Mike. On the takeaway issues and I always have a hard time getting my head around it, just do you think in a nutshell that there are any practical limits to you guys maximizing volume, say, over the next 12 months based on sort of a year-round case given current takeaway constraints or a lack thereof?

Mike Watford

No, Subash, I don't think there's any real limits to our growth over the next 12 months brought on my infrastructure issues. I think we are good.

Subash Chandra – Jefferies & Co.

Okay. And the second is Pennsylvania. I guess some of the things we're hearing from other operators there that the frac orientation is not well-known and some debate on whether you need it to be overpressured or normally pressured works fine or even if the Marcellus is normally overpressured and it, in fact, still might be underpressured. Can you shed some more light on maybe what you have seen so far in your vertical program?

Sally Zinke

Well, we are not in the underpressured or low pressure, we're in the high pressure portion of the Marcellus. And given the amount of gas we're seeing from the well we're testing right now, we don't foresee any problems. I don't think I can quantify a frac portion of it at this point with just one well completed.

Subash Chandra – Jefferies & Co.

Right, okay. So this big jump I guess it looks like the Pennsylvania well count from 32 to – from 15, is that mostly Marcellus, or was it some of these Oriskany and perhaps other horizons, Appalachian horizons?

Sally Zinke

At this point that only includes two Oriskany wells, so what you are seeing is a jump in the Marcellus.

Subash Chandra – Jefferies & Co.

And in that number, is there a horizontal component?

Sally Zinke

We have not yet made the decision to go horizontal. I think we're looking at our next two wells as helping us to make some decisions along those lines.

Subash Chandra – Jefferies & Co.

Okay, perfect. Thank you.

Operator

Your next question comes from the line of David Tameron with Wachovia. Please proceed.

David Tameron – Wachovia Securities

Hi. Can you guys talk about what is in 2009/2010 guidance? You just upped your well count for '08. Was that part of the plan when you originally formed that guidance?

Mike Watford

No, it was not in the plan when we originally formed the 2009/2010 guidance. Much of the increase in '08 CapEx is to fund the benefits of the drilling productivity that Bill's group is doing, as well as one of the other operators in the field likes to what I call batch drill their wells and spud a lot of wells at the end of the year and not complete them until the following year. We have to fund that this year, and that production will come on next year. So, there is no production increase this year with that. We're also, as Sally just mentioned, spending more aggressive spending money in Pennsylvania with additional 3-D we're going to shoot and almost doubling of the wells. We're not assuming any production contribution from any of those wells right now in '08. Certainly we have not revised our 2009/2010 guidance, so I don't know if I helped you there or not. And we've got a number of water disposal wells we're drilling too in Wyoming, which are going to help us with our LOE and don't help with production. But basically it is more delineation wells. We want to be more aggressive and get more of those wells drilled while we have a window to do it and at least drill more wells in Wyoming and lots more wells in Pennsylvania.

David Tameron – Wachovia Securities

Alright. And you have not incorporated SEIS into the 2009 and 2010, is that correct?

Mike Watford

That is correct. We have elected not to even revisit 2009/2010 guidance until we see the record of decision. At that point in time, we will revisit all that.

David Tameron – Wachovia Securities

Alright. One more question. Can you talk more about the deep, what you saw and what you did not see? Do you have plans for another test, just some more color?

Sally Zinke

I think at this point in time, we do not have any immediate plans for another test until we're finished with our completion of the Blair on this one. What we saw, we saw gas. We did see high-pressure. We just feel like we were not able to effectively frac in into an existing natural fractures system, and that that is a factor in expectations from the Hilliard.

Bill Picquet

We did not see any problems as far as formation (technical difficulty) – at that type of (technical difficulty) –

David Tameron – Wachovia Securities

Alright. And what is the timing on the Blair?

Sally Zinke

We expect to work on our design of that in the next couple of weeks and begin our fracing perhaps in late August. We're going to again be very deliberate and careful about how we proceed with it. I think we could hope for results sometime before the end of the year when we would be completely through with all of our fracing in the Blair.

David Tameron – Wachovia Securities

All right. I'll let somebody else jump in. I'll get back in the queue.

Operator

Your next question comes from the line of Kent Green with Boston American Asset Management. Please proceed.

Kent Green – Boston American Asset Management

Yes, I had a question about whether you are still acquiring land in Pennsylvania, and then give us an update on what kind of disciplines are being done by the company in that regard?

Sally Zinke

Well, I think if you look at our acreage count, it has gone up a little bit in the last quarter. We are still continuing to acquire acreage within the areas that we already previously defined as part of our target areas. In terms of disciplines, you have heard that we're going to acquire some additional 3-D seismic. I think with the Oriskany discoveries, we will be going back and looking at what we think we can pursue along those lines.

Kent Green – Boston American Asset Management

Then are you acquiring this acreage on the basis of the 50-50 joint venture in it? Who is that joint venture with? Excuse me; I'm not up-to-date in what you're doing over there.

Sally Zinke

The joint venture is with East Resources, and yes, a chunk of that acreage is being acquired within that AMI.

Kent Green – Boston American Asset Management

And is there anything unusual about that joint venture? Is it just 50-50 for everything?

Sally Zinke

It is 50-50 for everything.

Kent Green – Boston American Asset Management

Thank you.

Operator

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners. Please proceed.

Mike Scialla – Thomas Weisel Partners

Hi, good morning. In terms of your third-quarter production guidance, what are you planning in terms of downtime for REX? And I guess with no change there, is that because you have exceeded for July and August what you anticipated, or I guess I'm trying to figure out what you're anticipating there in terms of September?

Mike Watford

Well, we have been notified, Mike, that Rockies Express is going to take down a major portion of their line in and around the NGPL interconnect for 23, 26 days for that exact time. And so we will lose 100 million a day of our marketability of our 200 million a day of capacity. Others lose volumes as well, so this is just not us. When that was announced, you saw pace of differentials for September increased dramatically from the Opal marketing point, and at that point in time, we just said, well, this does not make any sense to try to sell into this elsewhere. So we will just shut that gas in. So we will shut in 100 million a day for the time of that outage in the pipeline. So we're estimating about 3 B's, a little bit less than that. But in terms of our internal planning, we assumed that we would shut in three B's for the month of September. But we are confident that we will still meet the previously advertised production targets for the third and fourth quarter. That is why we left those alone. But with the first and second quarter actuals being above what our earlier year guidance was, that is why we get a new total. So effectively we are increasing our 2008 total production guidance in the face of a possible three Bcf shut-in.

Mike Scialla – Thomas Weisel Partners

Can you give us some sense of where your current production is?

Mike Watford

It is all in Wyoming.

Mike Scialla – Thomas Weisel Partners

In terms of daily rates?

Mike Watford

Oh, items?

Bill Picquet

It is, we are 380, 390 million a day net on a gross basis; that is a large number. I mean our operating production hit a number of over 500 million cubic feet a day here not long ago, but we just focus on that – I mean our operating production and our piece of what Questar and Shell operate. We're between 380, 390 million a day net right now with month to month increases as more and more wells get completed in the summer window.

Mike Scialla – Thomas Weisel Partners

Okay. And then a question for Bill on the drilling efficiencies, are we looking at really apples-to-apples when you compare year-over-year? Are you drilling the same size hole there, or are these neural wells slimhole, or what is really driving – I think you've put it as the drill bit technology and more scalable rigs, but is it a fair comparison in terms of hole size?

Bill Picquet

We're comparing the slimhole cost with (inaudible).

Mike Scialla – Thomas Weisel Partners

Okay. Terrific. That is all I have. Thanks.

Operator

Your next question is from the line of Ron Mills with Johnson Rice. Please proceed.

Ron Mills – Johnson Rice

Yes, good morning. On the pipeline expansions that you have laid out in your press release, are you seeking any additional firm capacity on any of those lines, or is the major benefit there just going to be from a tightening of the differentials as those pipelines heading both East and West come into service?

Mike Watford

Ron, I think to be responsible that we're going to have to pick up some of that capacity. We have seen the capacity we have on REX to be economically attractive to us so far in terms of we have made actually money on the transport, or during the winter months, you are probably not going to make money, and the summer months you will make money. At least that is our history so far. There is a bit of a differential between those kind of prices and Rockies prices right now that sort of echo that. But no, I'm sure you will see us as a participant in either one of the pipelines going east.

Ron Mills – Johnson Rice

And this may be for Mark, but during the period of the shut-ins related to the REX testing, I'm assuming that you also will save a little bit of money from your transportation costs. Because I don't – as I recall, you're not going to be charged for the gas that is not being transported. Correct?

Mike Watford

That is correct.

Ron Mills – Johnson Rice

Okay. And then lastly, just in terms of the delineation, it sounds like you focus a lot of activity there around Warbonnet. As we look through the rest of this year and next, at what point do you think you will have a majority of the Pinedale structure delineated via that drilling to extend the field limits?

Sally Zinke

Well, I think much of the focus has been in Warbonnet early in the year because of access. We do have about half of our delineation program is up in the central portion of an Anticline going forward. In terms of timeframe at which we will be finished, I guess when we've reached the edge of the field, and I'm projecting that to be sometime after 2010.

Mike Watford

I don't think there's any way we get the field fully delineated short of three to five years from now, and that has to do with the access issues. That is why we only have six delineation wells I think completed so far this year, but we have over 30 on the schedule. There's a bunch of the area that we want to delineate available to us under current rules and a narrow window which has just opened up. So that is why we have lots of activity there.

Ron Mills – Johnson Rice

And will the pending record of decision also benefit the timing for the delineation program, or is that going to be focused more on where you have your concentrated ad development to drilling going on?

Bill Picquet

We are anticipating that will be a focus upon the concentrated development of the (inaudible) delineation.

Ron Mills – Johnson Rice

Okay. Thank you very much.

Bill Picquet

(technical difficulty).

Operator

Your next question comes from the line of Wayne Andrews with Raymond James. Please proceed.

Wayne Andrews – Raymond James

Good morning, everyone. We spent a lot of time, Mike, and I applaud your efforts on delineating the field. You mentioned a little bit on increasing the aerial extent and then even deeper horizons increasing the size of the field. We have not spent much time talking about the – you have begun to mention the lower quality pay. And obviously that is pretty low hanging fruit, particularly where you have already drilled wells. And my question is, of the 588 Bcf per square mile that is the original estimates of reserves in place, how much of that is really – is any of that counting the potential for low quality pay? And if so then maybe where could that recoverable number move to if it turns out that these are very economic completions?

Sally Zinke

None of that LQ pay or potential pay has been counted by current Netherland Sewell estimates. So you would look at all of that has being additive. And in terms of recoverable, if we're looking at an average of two or three stages per well and 100 to 150 million recoverable reserves per stage, you are looking at something in the order of 300 million per well across the board for undrilled wells. These are not where you could go back into existing wells and add this pay. But it would be certainly applicable to all future wells.

Wayne Andrews – Raymond James

I see and that is not something – these wellbores I know the wellbores you have today you've put certain fracs on certain good-looking zones. What is the potential at some point in time – I mean I suspect you will be producing here for many, many, many years. And what is your idea on re-frac potential 10 years from now to keep these wells flowing for an indefinite period?

Bill Picquet

(inaudible – microphone inaccessible)

Mike Watford

Sally is a little more subtle than I am, and what she was trying to say in our comments there was that the field has grown in terms of gas in place from 36 T's in 2003 to 53 T's here in 2007. And she is more and more comfortable that it is going to grow to minimally 60 T's over the next three to five years. She used some numbers about gas in place of 588 B's per square mile of Netherland Sewell's estimated recovery of that gas in place in excess of 330 B's per square mile. And then she went on to say that even on the delineation on the edges now where we are drilling, where we have 70 different wells planned over the next three years. For 2010 we are seeing our early estimates are 250 to 275 B's per square mile there, and I think those are probably low estimates.

But if you just – the 70 delineation wells are on quarter sections essentially, so you divide that by 4 to get to sort of a – square miles, and you've got what, 17.5 square miles of delineation drilling that we are going to do, and at the low end of that range, the delineation reserves recovery is 250 B's on 17.5, you get a number that is almost 4.4 T's of recovered gas, which she backs in to get her gas in place. And then if we had a 60% working interest in that, we would probably have a larger one because we own 80%, 85% of a lot of blocks on the edges. And so you are at a net to Ultra number of about 2.6 T's. You do the same kind of math on low quality and say it is two zones at 150 million of additional reserves per zone or 300 million per well, and you say, we've got 5300 undrilled wells, let's just say 2000 of those work with low quality, and we know the low quality works in the Warbonnet area. We're going to take it back up north in the field as we move our rigs now with access. But you get to 600 B's, and you do that times a 50% working interest of 300 B's of the some the 2.6 to 300, you're almost at three T's of net upside for Ultra on the top of the 10.7 T's at year-end '07. That is why we are so comfortable with the 14 Tcfe target. And she was trying to allude to that, but she is not nearly as direct as I am.

Wayne Andrews – Raymond James

Well, I was sort of working towards the same point. Is that you've got one of the best field with the best economics in the industry, and it is getting bigger every year in aerial extent, potentially getting deeper with additional horizons, and now you're even finding additional pay within the existing already-quantified pay zones. So it just keeps getting better, and I appreciate your efforts in continuing to make sure that we are well aware of that.

Mike Watford

Thanks, Wayne.

Operator

Your next question is a follow-up from the line of Kent Green with Boston American. Please proceed.

Kent Green – Boston American Asset Management

My question pertains to your hedging, and you laid out the total results. That includes basis differentials too I assume?

Mark Smith

The hedge prices that I gave you on both physicals, as well as the financials are at Opal, so yes, that would include the effects of basis.

Kent Green – Boston American Asset Management

What about going forward, are you going to continue your program of leaving a more open gas particularly in the winter season?

Bill Picquet

I think we see prices begin to firm up over the winter, so they tend to be softer over the summer. So we preferentially look toward the summer. So you will continue to see us look at our hedging program opportunistically as we move forward.

Kent Green – Boston American Asset Management

I see. And the final question, has the volatility both up-and-down in the domestic natural gas prices led to any potential changes in your hedging strategy going forward or considerations of what you might do?

Mike Watford

Volatility impacted our hedging strategy, that is the question?

Kent Green – Boston American Asset Management

Yes, and whether you may modify that going forward with this increased volatility?

Mike Watford

Well, I don't guess I mean – our plan is to hedge a portion of our production annually to certainly lock up our CapEx so that we can continue to grow the production and the enterprise in a nice way and make a lot of money. We are all about margins and making money, not just growth. So yes, we are going to be sensitive to the volatility in pricing and try and be opportunistic. Are we going to hedge more than 50% of our production I think is a more direct question I can deal with?

Kent Green – Boston American Asset Management

Sure.

Mike Watford

Probably not. The reality here for us is let's just look at 2009 for example. If my production in 2008 is in the 145 Bcfe range, which is whatever it is, greater than 25% production growth over comparable numbers in 2007, which is exceptional organically no acquisitions, if I get to 145 B's and I look at what I have hedged for 2009, and I'm going to count the transport on REX as a bit of a hedge. I mean we can physically hedge those at Panhandle or NGPL or those places. But if we are going to have access to further these points later in the year, I hate to do that now until I see what the markets over there are, i.e. I think those prices will be better. But if I target production for 2009 at this point in time, it is 190 B's. Well, I have not drilled those wells to get to 190 B's. So if I want to hedge, I really cannot hedge 50% of 190 B's. So effectively what I have done with the hedges that we have in place and the transport capacity on REX, as far I am concerned, I have hedged 106 B's of my 2009 production, which is 73% of 145 B's '08, which I'm confident I have, and it's about 56% of the 190. So I think I'm in a pretty tight range there that I'm comfortable with. Because we're not going to hedge what we have not drilled and have not put on production yet. So for us to look forward for hedging, we're really targeting 2010. As of yesterday, even with the volatility in gas prices and the decrease in the gas prices, I think the calendar 2010 Henry Hub number was 944. I think that we could hedge in Wyoming at Opal at a number that was like 665. We're not crazy about that number. We will really want something north of $7.00. But can we make money at 665? Absolutely. A year ago at this time our gas prices in Wyoming were 337, 340. So we're really – we made money then. So we're going to target some sort of $7.00 price for calendar 2010, and that is where you're going to see more of our hedging as we go forward.

Kent Green – Boston American Asset Management

Good answer. Are you looking forward to getting a plus differential on your Pennsylvania gas?

Mike Watford

We received that today. We like those prices up there in Appalachia. That's what makes some of the Pennsylvania activity that Sally was talking about. I mean some of those Oriskany wells have costs, and Bill can correct me, of like $1.3 million, $1.4 million – 1.2 million; I have been corrected. And we think bottom side of the reserves are 2.5 B's, more likely they are 4 B's per well right now. I mean that is fantastic economics. And then when you role into that the gas prices per unit, you get there. That is again why we're drilling twice as many wells up there, and we're going to shoot another 3-D.

Kent Green – Boston American Asset Management

One final question about Pennsylvania. Is there that – I do realize you have not made any plans for horizontal yet, but could you comment if that has been predicated on rig availability or skilled people in the Appalachian area?

Sally Zinke

Well, certainly rig availability and skilled people is a challenge back there. But I think if we make the decision to go horizontal, we will be able to handle that.

Mike Watford

We're still in the data accumulation mode. So –

Kent Green – Boston American Asset Management

Thank you.

Operator

Your next question is a follow-up from the line of David Tameron with Wachovia. Please proceed.

David Tameron – Wachovia Securities

I think I just got my hedge question answered, but on the SEIS, Bill, what did you say as far as timing?

Bill Picquet

I said early September.

David Tameron – Wachovia Securities

Early September? All right, that is all I have got. Thanks.

Operator

(Operator instructions) And your next question is from the line of Jeff Davis with Waterstone Capital. Please proceed.

Jeff Davis – Waterstone Capital

Great results. I'm curious if you can maybe mention the revolver balance is at the end of the quarter or perhaps even today?

Mark Smith

We had $300 million outstanding debt at the end of the quarter, which put us to zero under our revolver.

Jeff Davis – Waterstone Capital

Okay. You just mentioned timing on these SEIS decision. How would you characterize your confidence level on a choice that is going to be leaping [ph] around drilling?

Bill Picquet

Well, obviously we're pretty close to the process (technical difficulty) – had exhaustive conversations (technical difficulty) – the agents involved in fighting the record of decision. (technical difficulty) – pretty confident at this point in time that content of that will be something that provides us access – (technical difficulty).

Jeff Davis – Waterstone Capital

Okay. Mike, you mentioned 665 I think for Opal for calendar 2010. Is that today? I mean what – has it been about $7.00 prior to the big drop we have seen in natural gas, or has it kind of been consistently under $7.00?

Mike Watford

It was that number was as of yesterday. If I go back a week, the number was over $7.00. So it has been above $7.00 or (technical difficulty) – and bouncing around.

Jeff Davis – Waterstone Capital

Okay.

Mike Watford

Since the first part of July, so we have lost ground here of late, so we're hoping to recoup that.

Jeff Davis – Waterstone Capital

Okay. And then obviously I applaud the buybacks. Obviously you guys bought some back at 86, bought some back in 77, and you've got a lot of the stock here at sub-70. What stops you from getting just a little bit more aggressive with the untapped revolver on the buyback front?

Mike Watford

Well, we had to have our board meeting and get the board to approve our ability to go beyond $500 million, and they did that on Monday. So now we can go up to $750 million of total buyback, I think at the end of July we were what, 43, Mark, something like that? So with that new authorization, I think you will see us continue to buy back stock. Yes, so I think we will go spend the extra $250 million.

Jeff Davis – Waterstone Capital

Okay, thanks. Great results.

Operator

As there are no further questions in queue at this time, I would like to turn the call back over to management for closing remarks.

Mike Watford

Well, thank you very much for your time. If you have any other questions, please don't hesitate to contact us, and again, thanks. Bye.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. If you would like to access the replay, it is going to be available for 13 days at the following numbers – 888-286-8010 or 617-801-6888 and please use the access code 31294358. Again, thank you for your participation in today's conference. You may now disconnect. Have a great day.

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Source: Ultra Petroleum Corp. Q2 2008 Earnings Call Transcript
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