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Executives

Kelly Whitley - Manager, IR

Mike Watford - Chairman, President and CEO

Mark Smith - CFO

Bill Picquet - VP of Operations

Sally Zinke - Director of Exploration

Analysts

Nicholas Pope - Dahlman Rose

David Tameron - Wachovia

Noel Parks - Ladenburg Thalmann

Leo Mariani - RBC

Ron Mills - Johnson Rice

Ultra Petroleum Corp. (UPL) Q1 2009 Earnings Call May 6, 2009 11:00 AM ET

Operator

Welcome to the first quarter 2009 Ultra Petroleum Corp. earnings conference call. (Operator Instructions).

I would now like to turn the call over to your host for today's call, Ms. Kelly Whitley, Manager, Investor Relations. Please proceed.

Kelly Whitley

Welcome to Ultra Petroleum's first quarter 2009 earnings conference call. This conference call will contain forward-looking statements that involve risk factors and uncertainties detailed in the company's filings with the Securities and Exchange Commission. All statements other than statements of historical facts included in this call, including statements regarding our financial position, estimated quantities and net present values of reserve, business strategy and plans and objectives of the company's management for future operations are considered forward-looking statements. The company can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct nor can the company assure adequate funding will be available to execute the corporation's planned future capital program. Financial results are subject to audit by independent auditors.

This call may contain certain non-GAAP financial measures. Reconciliations and calculation schedules for 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 the host of today's call, President, Chairman and Chief Executive Officer, Mike Watford.

Mike Watford

Joining me today are the usual cast of characters. We have Mark Smith who is going to update us on the financial issues, Bill Picquet on the operating items, and Sally Zinke will share the exploration results with us. Let's start this morning's conversation. I'll make a few opening comments and then let the more knowledgeable folks lead the conversation.

Briefly on the quarter, we had terrific operating results with record production at lower costs, probably the lowest cost in the industry, but also lower oil and gas prices, which resulted in lower earnings and cash flow. Added to this was the unavoidable ceiling test write-off, which netted to a negative result.

More importantly, let me talk about the value creation that's underway due to the scale of our assets and more eloquently resource capture. We tend to characterize our 12 trillion cubic feet of Wyoming natural gas reserves as PUD-like, all third-party engineer, risk and economic at yearend 2008 gas prices.

When one applies the new more reasonable 2009 reserve recognition rules to our assets, this PUD-like view is confirmed with much of the 12 trillion cubic feet meeting the proved reserve definition and capable of being booked immediately, but that's the path we like to travel. So to think of Ultra as merely a 3.5 trillion cubic feet proved reserve company would not be correct. Bill will share the details.

Second, let's talk about money and financial flexibility. We enjoyed tremendous financial flexibility due to our low cost and our unused debt capacity. Our cash operating breakeven approximates $1 per MCF and we have over $2 billion of debt capacity. Our current debt level of less than $750 million is likely our peak debt for the year as our remaining 2009 cash flows and CapEx match each other. Mark has more to share on this.

We are adjusting downward our capital expenditure budget for 2009 from $720 million to $670 million, while maintaining our production forecast for 2009 of 20% growth to a record 175 Bcfe. With Bill's portfolio approach to rig contracting, we were able to decrease our operated rig count from 15 rigs in December to 5 today and we're planning to exit the year at 7.

With 2010 and 2011 Wyoming natural gas prices well above $5 Mcf in Wyoming coupled with further increases due to REX-East completion, we are starting to make plans for increased activity. With 70% of April's operated wells drilled in less than 20 days and with well costs approximating of $5 million versus $5.6 million last year, our returns will be increasing.

We are a company that believes in profitable growth not merely growth. We need to make money, and as such, saw no need to accelerate development of our legacy asset in the current pricing environment. With $5 gas prices, $5 million well costs, 5 to 6 Bcfe wells and the ability to grow production with CapEx matching cash flow, we are looking more positively at 2010 and 2011.

We had the beginnings of what may become another core area for us in Pennsylvania. Sally will update us on that activity.

Now, on to Mark for the financial story.

Mark Smith

As Mike outlined, we had a good quarter operationally despite the drop we've seen in natural gas prices. From a financial perspective, we're on solid ground.

Our total debt capacity is in excess of $2 billion. As of March 31, we had $14.4 million of cash and cash equivalents on hand and $721 million in outstanding senior debt, providing us with almost $1.3 billion in unused senior debt capacity. We believe our liquidity continues to remain more than adequate to fund our $670 million 2009 CapEx budget with the use of our cash flow from operations combined with the availability on our revolving credit facility.

For the first quarter, our Wyoming production was up 24% on a comparable year-over-year basis to a record 42.1 Bcfe. Once again, our quarterly production registered the highest quarterly production level in the company's history and was largely due to our increased year-over-year activity in Wyoming combined with our improved drilling efficiency. You'll hear more about these from Bill in a minute.

Our realized natural gas prices for the first quarter were $4.46 per Mcfe, a decline of 42% over prior year levels. Prices were raised to $28.56 per barrel for quarter as a result of our increased production levels offset by this decrease in realized commodity prices. Revenues for the quarter, including realized gains and losses on our hedges, registered $188.3 million.

The corporate lease operating expenses for the quarter decreased year-over-year to $0.91 per Mcfe largely as a result of reduced severance and production taxes due to lower commodity prices combined with reductions in our unit production costs and gathering expenses.

Our production costs have improved year-over-year as we work with our partners to bring down their expense levels largely related to water handling costs. In terms of transportation costs, our demand charges as an anchor shipper in REX amounted to $13.4 million this quarter or $0.32 per Mcfe on our total production volumes.

Our DD&A rate for the quarter registered a $1.44 per Mcfe, G&A expenses were down on a unit basis to $0.11 per Mcfe, while interest costs registered $0.17 per Mcfe. Recall that during the quarter we refinanced our senior bank debt with longer dated fixed rate debt that carries a higher coupon. The net effect of these factors was $0.37 per Mcfe year-over-year decrease in overall corporate costs from $3.32 in the first quarter of 2008 to $2.95 per Mcfe this past quarter.

Looking at our cash cost in Wyoming, excluding severance costs or our fuel level costs, they decreased 18% year-over-year on a unit basis to $0.50 per Mcfe. As a result of the decrease in realized prices I mentioned earlier offset in part by our continued focus on operational improvements and cost reductions, our cash flow decreased over the comparable 2008 quarter to $124.2 million, providing a cash flow margin of 66%.

Due to reduced quarter end Wyoming natural gas prices from $4.71 per Mcf at December 31 to $2.47 per Mcf at March 31, we reported a full cost ceiling test write-down on the carrying value of our oil and gas properties. As a result, one will see the $673 million after-tax non-cash charge reflected on our income statement as write-down of proved oil and gas properties.

There is no effect on overall cash flows for the company. Adjusted for the write-down in our unrealized gains associated with the mark-to-market position on our hedges, our pre-tax income registered $61.4 million for the quarter or a 33% margin. Net income, excluding the ceiling test write-down and mark-to-market gain, was $39.7 million for the quarter, providing a 21% adjusted net income margin or $0.26 adjusted earnings per diluted share.

In terms of returns, for the first quarter on an annualized basis, adjusted return on equity was 21% and adjusted return on average capital employed was 11%.

Cash provided by operating activities during the quarter amounted to $131.9 million, with cash used and investment activities totaling $281.4 million. These investment activities were largely comprised of $221.9 million in oil and gas related CapEx together with $58.6 million decrease in payables related to prior period CapEx.

Over the quarter, net cash provided from financing activities totaled $149.7 million, consisting primarily of $235 million in proceeds from our senior note offering that I referred to, offset by $84 million in net repayments on our senior bank facility over the quarter.

Considering our price outlook for the remainder of 2009, through October we have 360,000 MMbtu per day hedged through financial swaps at a price of roughly $5.84 per Mcf. For November, this drops back to 150,000 MMbtu per day hedge at roughly $5.27. For December, this reduces further to 100,000 MMbtu per day at roughly $6.02. For calendar 2010 we have 210,000 MMbtu per day hedged at a price of roughly $5.32 per Mcf. For calendar 2011, we have 160,000 MMbtu per day, hedging price of roughly $5.33.

Additionally, we have 200 million per day of firm transportation capacity on REX. This serves to provide us with additional hedging on our basis for these volumes. We're currently moving to the Midwest where we'll receive Mid-Continent base pricing. In November, we expect REX to be operational to the Northeast where we expect to begin receive pricing at levels close to the Dominion South.

To put this in perspective, we've begun to hedge at the far end of REX-East with additional swaps for 2010 and 2011 at levels in excess of $6.75 per Mcf. This nets back to Opal in level of over $5.40 per Mcf, more than offsetting our transportation costs. This further compares to current spot pricing at Opal of $2.74 per Mcf and spot pricing at Dominion South of $3.98. So we're beginning to lock-in an expected uplift from REX.

In terms of guidance, we continue to confirm our full year 2009 production guidance of 172 to 177 Bcfe. For the second quarter 2009, we're establishing guidance in the range of 42 to 44 Bcfe. For the fourth quarter of 2009, production levels are expected to exceed fourth quarter 2008 levels by roughly 10%.

In Wyoming, lease operating expenses are expected to run $0.25 per Mcfe, gathering $0.27 per MCFE. As a result of the ceiling test write-down in the first quarter and with all other factors constant, we currently expect our Wyoming DD&A rate to run $0.98 per Mcfe. We see G&A cost of approximately $0.14 per Mcfe for the year. As a result, we expect our all-in cost to continue trending downward in a range of 255 to 260 for the second quarter.

We continue to move through the year and REX-East ramps up into the Northeast. We'll incur additional REX demand charges related to our firm capacity as an anchor shipper. These costs will ramp up beginning roughly May through the interim service period to roughly $1.07 per Mcfe plus fuel at full capacity on REX-East. Again, this is on our share, which is 200 million per day.

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

Bill Picquet

Wyoming in the first quarter of 2009, Ultra brought on screen 51 gross, 30 net new producing wells. Average initial 24-hour sales rate producers in Q1 were 7.9 million per day. Ultra's operated Pinedale wells averaged 9 million cubic feet per day, while the non-operated wells averaged 5.8 cubic feet per day. The high for the quarter was from the Ultra-operated riverside 4A1-11D, which floated 13.7 million cubic feet per day.

At the end of the first quarter, there were five Ultra-operated rigs drilling in Pinedale and a total 10 non-operated rigs also active for interest lands. Operating efficiency continues to improve. First quarter operational highlights include an average of 22.7 days spud to TD for Ultra-operated pad wells, 8% improvement over the average for Q1 2008.

Ultra drilled and cased 36 wells during the first quarter of 2009, 20% increase compared to the 30 wells drilled and cased in the first quarter of 2008. This is an even more impressive improvement when considering we operated the same number of rigs in both quarters. Ultra drilled 78% of our operated wells in less than 30 days spud to TD in Q1 2009. 33% are under 20 days.

Our overall drilling performance continues to improve. Our pad well averages improving as we place increasing focus on the key elements that are generating reductions in time to drill. Early Q2 performance on drill times has been even more impressive. During April, 70% of our wells were drilled in less than 20 days, further reducing drill times on our development wells.

Keys to our success include under balanced drilling, leading-edge bit technology rotary steerable tools for directional control and aggressive pursuit of other emerging technology. I'm confident that through these efforts we'll continue to see reductions in both time and costs. Year round access is adding to our efficiency with fewer rig moves, reduced location costs and benefits of continuous drilling operations on single pad locations.

Cost in the first quarter for development wells were essentially flat with our full year 2008 average per well of $5.6 million. We're beginning to see the benefits of new service arrangements, lower pipe cost and reduced drilling times mentioned earlier. We expect that in the second half of 2009 we will consistently drill and complete wells in the $5 million range or better.

Although cost of services increased during 2008, our ability to drill faster and more efficient more than offset those increases. In 2009, we are continuing to improve operating efficiency. We are also seeing reductions in the cost of services and materials. We expect this trend to continue as many of our service providers have aggressively reduced their prices, reductions ranging from 10% to almost 40% depending on the service. Our higher priced inventory will be fully used in late Q2 and we'll begin to see the full benefit of lower steel cost at that time.

Regarding well results, during 2008 Ultra's average initial rate for operated wells was 8.5 million cubic per day. By comparison, early in 2009, it increased to over 9 million cubic feet per day. Our average EUR on Ultra-operated wells in 2008 was approximately 5 Bcfe. For our 2009 Ultra-operated drilling program, we expect to average approximately 6 Bcfe per well.

Overall, the mix of wells will vary from year-to-year as we drill in different areas of the field. During all of 2008 and early 2009, most of our producers limited to the (inaudible) where wells are less prolific due to restricted access drill on other areas. As a result of year round access with new record decision, we were drilling primarily in the more prolific Riverside and Mesa areas of the field.

Recently Ultra analyzed the number of wells required to convert our probable and possible reserves to the category. We undertook this exercise to demonstrate further demonstrate the low risk quality of our significant scale of assets in Wyoming. Ultra's resource in Pinedale is a very low risk reserve base. This recent analysis further emphasizes these facts.

At yearend 2008, our third-party reserve firm estimated our approved reserves to be at 3.5 Tcfe and our overall 3P reserves to be 11.7 Tcfe. The new expected SEC rules by yearend 2009, Ultra could essentially double our proved reserves without drilling a well for almost 7 Tcfe. Ultra could further increase our proved reserves to nearly 8 Tcfe by drilling less than 100 additional wells.

We could effectively convert the remaining 10 acre wells to proved category using our self-imposed cutoff of 0.5 Bcf per well on the edges. These are majority of our interior five-acre wells in 3P category. Of this remaining, almost 4 Tcfe or half should be converted to proved on down spacing and with limited additional drilling. This would leave only a small number of five-acre edge wells in 3P category and a total of 11.7 Tcfe at yearend 2008 reserve base.

There is still substantial upside to the 11.7 Tcfe number evidenced by results, normal pressure pay, LQ pay initiatives, and also by the fact that the Jonah field recovery factor estimated by third-party engineering is higher than the Pinedale recovery factor. We believe that as the Pinedale asset matures, they would likely be reserve upside in an improved recovery factor estimate. Also through the continued success in our delineation program, we expect to expand the size of the resource.

Sally, will update those activities.

Sally Zinke

I'll begin by reviewing the delineation drilling for the first quarter of 2009. A total of 13 delineation wells were completed in 2009 and additional 3 delineation wells currently waiting on completion. These three wells are expected to be completed later in May and early June. Production history from the 13 completed wells indicates that reserves can be expected to exceed the Netherland, Sewell pre-drill estimates for those locations by 47%.

Q1 2009 delineation wells had an average post-drill EUR estimate of over 5.5 Bcf and an average IP rate of over 8.2 million cubic feet per day. Through this delineation program, we continue to add to the estimated recoverable reserves net to Ultra, increase our production, expand the defined areas of field and further confirm the estimates of original gas in place for Pinedale.

Now, moving to increase density drilling. We are continuing our ongoing assessment of well density in six new Ultra-operated five-acre density pilot areas in Southern Mesa and Northern Riverside areas of the field. The low quality pay or LQ portion of the land pool is part of our ongoing reserves and production additions program. This is a program to frac near well bore sand Lances that are beyond wireline log depths of investigations below Netherland, Sewell conventional pay cutoff continues with a total of 133 wells completed in more than 350 LQ intervals to-date.

In the first quarter of 2009 Ultra completed a total of 52 LQ stages 30 wells representing 77% of all wells completed in the quarter. On average, Ultra is completing one to two LQ stages per well north of the river, two to three LQ stages for wells south of the river and three to four LQ stages per well in the Warbonnet area.

With reserve additions of 100 million to 150 million cubic feet gas per stage, frac stage costs dropping to less then $76,000 per stage based on increased efficiency, F&D costs for these reserves is less than $0.65 an Mcf. We mentioned last time that we commenced another reserve addition program at frac stages above the conventional over pressured Lance interval.

In Q1 2009, Ultra completed normally pressured shallower stages in a series of 35 wells for a total of 71 stages. Production log data from this portion of the section and the total of 130 wells in the Pinedale field indicates an average production contribution of about 100 Mcf per day per stage, again, at a completion cost of $76,000 per stage, resulting in an expected F&D cost of less than $0.80 per Mcf. This non-over pressured section is available for completion in all new wells and as a re-completion opportunity in all existing Ultra-operated wells on the Pinedale Anticline.

Now, looking at Ultra's Pennsylvania exploration. Two new vertical of Oriskany sandstone tests operated by East Resources with Ultra as a 50% working interest partner were drilled in the Texas Creek area during Q1 2009 with a total average completed well cost of $1.3 million. These two wells are waiting on completion in pipeline connection.

In addition, Eastern Ultra have six Oriskany sandstone wells drilled in 2008 waiting for pipeline connection. Two of these Oriskany wells drilled in the Texas Creek area were flow tested for extended periods stabilized rates ranging 3 million to 8 million cubic feet per day. We currently have an interest in a total of eight Oriskany wells.

In 2008 Ultra drilled or participated in a total of 11 vertical Marcellus tests on operated and non-operated acreage as part of our assessment of Marcellus potential. In Q1 2009, Eastern Ultra have jointly drilled two horizontal Marcellus wells in Tioga County which are currently being fraced. Additional pair of horizontal Marcellus wells is also currently drilling. We anticipate having all four of these wells completed and online within the next two month.

Four wells are close to pipeline test only in conjunction with partners. Gathering systems wells are currently under construction. Drilled and completed horizontal wells with an average 4,000 foot lateral section have an average cost of $0.1 million. These resources Ultra anticipate drilling at least nine additional horizontal Marcellus wells in 2009, bringing the total of non-operated horizontal Marcellus wells for the year to 13. Previously drilled vertical Marcellus wells will be connected as the 2009 horizontal activity moves in those paths.

Over yearend 2008, Ultra acquired 30 square miles of 3D seismic in the Marshlands area. They are evaluating that data in conjunction with our assessment of the Marcellus, risking in other potential in the Marshlands area. We currently have over 100 square miles of 3D seismic on our PA leasehold covering about 20% of our acreage. Our leasehold in Pennsylvania is approximately 322,000 gross and 172,000 net acres at a cost to-date of less than $350 an acre.

Looking at the Ultra-operated portion of this acreage, we currently have Tuscarora and Utica (inaudible) production in the Marshlands area as well as three vertical Marcellus wells that are waiting on pipeline connections. With encouragement from our current horizontal Marcellus program to the East, we anticipate drilling eight horizontal Marcellus wells in Q3 and Q4 of 2009 on our 100% acreage in the Marshlands area. Estimated completed well cost is $3.1 million for 3,500 foot lateral. True to our conservative approach, there is nothing in current production growth guidance to reflect our Pennsylvania activity.

Back to you, Mike.

Mike Watford

It sounds like we have continued resource growth both in our Wyoming asset and possibly on the verge of creating value in Pennsylvania as well.

As for 2009 proved reserve volumes, it is clear we can easily double our yearend 2008 volumes of 3.5 trillion cubic feet, and with a few wisely placed wells, reach 8 trillion cubic feet of proved reserves. Based on 2008's record production of 145 Bcfe and most E&P companies goal of 100% annual reserve replacement ratio, we can achieve that 100% replacement target with our unbooked proved reserves of 4.5 trillion cubic feet for more than 30 years. Now, that's a sustainable asset.

As for value, our calculated net asset value at January 1, 2009 for our Wyoming assets using Netherland, Sewell yearend 2008 reserves of 11.7 trillion cubic feet developed over 20 years at $6 per Mcfe long-term asset gas prices and 5.6 million per pad well cost discounted at 10% is $11.1 billion.

When we change the natural gas price to $4 per Mcf escalated at $0.25 per Mcfe per year, the value increases to $11.3 billion, not intuitive, but basically the same net asset value. Now, when we utilize the new lower well cost of $5 million, our net asset value increases to $14 million, a $3 billion increase or $20 a share.

In 2009, we are forecasting consecutive quarterly production growth with each quarter establishing a new record and with fourth quarter 2009 production 10% above fourth quarter 2008. For 2010 and 2011, we are comfortable with suggesting 10% annual production growth while under spending cash flow.

Thank you. Now, we'd like to open up the call for questions.

Question-and-Answer Session

Operator

(Operator Instruction). Your first question comes from the line of Nicholas Pope from Dahlman Rose. Please proceed.

Nicholas Pope - Dahlman Rose

I had a quick question just in terms of the cash spend for the first quarter. Could you help breakout what you all are spending in terms of drilling and acreage acquisitions, et cetera, for the quarter?

Mike Watford

No. We spent $220 million of capital in the first quarter and our cash flow was $120 million or so. There are roughly some $20 million of additional acreage expense in Pennsylvania. That's the only acreage cost. There's a little seismic and rest of it is for drilling wells.

Nicholas Pope - Dahlman Rose

You all discussed a lot of the reserve potential, before we all get to see it, with a little bit of incremental drilling. How do you all view some of the restrictions on like the timing that it would take to drill up some undeveloped reserves? Do you all think about putting some limitation on length of time to develop?

Mike Watford

In our current proved undeveloped bookings, we limit approximately three years. We're probably the most conservative company out there. That's the only way we've been able to hold back through reserves in terms of bookings at this point in time.

The net asset value calculation that we go through and will still go through assumes just flat capital for the 23 years to drill up the existing asset base at yearend '08. So to the extent we accelerate that flat capital, hen obviously we'll bring present value forward. I don't know if that answered your question.

Operator

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

David Tameron - Wachovia

Mark, I hate to do this to you, but can you repeat that cost guidance. I missed part of it for the second quarter.

Mike Watford

I think what he says we're the lowest cost operator out there and we're going to have lower cost in the second quarter. He is looking up the details.

David Tameron - Wachovia

While he is looking out, let me ask you a question. You just said it in the call 10% production growth 2010, 2011 while under spending cash flow?

Mike Watford

Yes, that's correct.

David Tameron - Wachovia

Can you give us a price that you are assuming?

Mike Watford

Yes, the $5 Mcf price in Wyoming. It's just assuming that we sold all the gas what we already hedged, a good portion for in 2010, 2011 just assuming that we're very comfortable with the ability to achieve 10% per annum growth while under spending cash flow.

Mark Smith

LOE is $0.25 per Mcfe. Gathering is $0.25 per Mcfe. Ceiling test write-downs affects our DD&A rate. We expect that to run in a range of $0.98 per Mcfe. G&A cost is $0.14 per Mcfe. As REX ramps up and we begin to sell for the latter portion of the year, I'm just trying to make sure everybody is clear that the REX transportation charge steps up over the year. It will exit the year at $1.07 per Mcfe plus fuel. That's for 200 million a day that we transport.

David Tameron - Wachovia

If it doesn't come on until late June, or you guys are targeting late May, that's the latest, you just pay charges for the one month of June.

Mark Smith

This is for the first quarter. We only get that full $1.07 when we sell all the way into the Northeast.

David Tameron - Wachovia

So there shouldn't be an impact in the second quarter. It should still be $0.77 for the second quarter?

Mark Smith

No, it will step up a little bit as we begin interim service.

David Tameron - Wachovia

Assuming it starts end of May, beginning of June.

Mark Smith

It's in the range of $0.90 since we begin that interim service.

Operator

Your next question comes from the line of Noel Parks from Ladenburg Thalmann. Please proceed.

Noel Parks - Ladenburg Thalmann

I dropped off for a bit, so I hope these weren't addressed already. The new acreage you bought in the Marcellus play, I was just curious was it extensional to where you already have acreage, a big block or several blocks?

Sally Zinke

Most of that acreage is contiguous with leases that we were already holding in conjunction with our Partner East. So it's within our AMI with them. Some of it was renewal. A lot of it was picking up small portions of leases that will soon be drilling units we hope.

Noel Parks - Ladenburg Thalmann

What sort of acreage costs are you seeing out there in general these days?

Sally Zinke

Our average has been running under $350 an acre.

Noel Parks - Ladenburg Thalmann

What did it peak out at sort of the heat of the play last year?

Sally Zinke

There are some parts of the area where it was up to $3,500 an acre. We did not expect that. I think our high end average was in the thousands.

Noel Parks - Ladenburg Thalmann

The acreage there as far as the timing of it, would you say it was more sort of encouraging results specifically that made you sort of pull the trigger with the acreage now or you saw a good price, it was in general in areas you were already interested in. So, I guess, was it driven particularly by the recent results or just more general desire to extend the position?

Sally Zinke

I think a portion of it was kind of already on the drawing board to finish out our solidifying our position in the AMI. Then certainly some of it was to extend the leases. Most of our exploration in AMI now is out 2011, 2013 or beyond. So it was to basically solidify our position and make sure that we have explorations that are far enough to allow us to go through acreage block.

Noel Parks - Ladenburg Thalmann

If I understood right, it sounded like most of the new well activity you are talking about, was that all Oriskany except aside from the Marshlands area drilling?

Sally Zinke

No. Our current activity is horizontal Marcellus. A lot of those wells were I think that we drilled last year and we had a couple of those remaining on the schedule. I think going forward, you'll see most of this year's activity if not all of it on horizontal Marcellus drilling.

Noel Parks - Ladenburg Thalmann

About the Marshlands area, I heard you comment that the Tuscarora was the type you've been talking about for some time out there and I thought I also heard you mention the Utica and another formation out there?

Sally Zinke

We have some production from the Anticline for those are other shale and Tuscarora is our main production right now.

Noel Parks - Ladenburg Thalmann

Are those prevalent across the acreage?

Sally Zinke

They are present everywhere. We just had a couple of wells. They are deeper than the Marcellus. So right now our targets would be drilling holes, a lot of acreage with Marcellus production.

Noel Parks - Ladenburg Thalmann

There is a lot of talk about possibility of more properties in general coming on the market in various regions of the country. I guess with Ultra's focus traditionally having been improving out new plays.

I was wondering if any of the acreage or plays that are maybe in the Rockies that are a little further along maybe on their way to development mode. Would any of those be of interest to the company assuming that a good price for the current environment could be reached or you're pretty much interested in just sticking with the exploration driven program right now?

Mike Watford

First let me sort of restate what we have already said before is that our balance sheet is in great shape. Mark Smith has done a wonderful job in positioning us. With $7million of debt and $2 million of debt capacity means we've got lots of dry powder.

Our ability to continue to drill this year and achieve a 20% production growth while the last nine months of the year or cash flow and CapEx match each other in our ability to go forward 2010, 2011 and plus or minus 10% per year production growth at cash flow equal CapEx which is just unique. I can't imagine any other company that could make this claim.

So that's positions us to possibly take advantage of other opportunities as you are suggesting. I think it's not likely that we step out and do that, especially in the Rockies. The best returning asset in the Rockies natural gas asset is Pinedale. To the extent there were other opportunities in Pinedale, certainly would be all over that.

I think the plan we have now that if what the other folks who are active in the Appalachia, say, it's true about the Marcellus and we are about to find out ourselves here with all of the success people are suggesting. That if that works out, that we'll have two core properties; Marcellus and Pinedale, at probably the lowest cost and best return of any assets in the lower 48. So I think we are well positioned to take advantage what we have right now.

Noel Parks - Ladenburg Thalmann

Just give an update on what's going on with infrastructure in your areas in Appalachia and maybe a sense of how difficult the sort of local and state government issues are in your particular areas. They have been parts of the play that are not really accustomed to gas development.

Bill Picquet

This is Bill. I'll field that one. As far as infrastructure is concerned obviously is activity up in the area. There are more and more service area coming available. From our perspective, it's improving. As far as regulatory environment is concerned, we are much more receptive than I typically expect. Our experience so far is for active in Pennsylvania (inaudible) regulatory agencies there are working very well with us. So I don't see that as a significant issue.(Technical Difficulty).

Operator

Your next question comes from the line of Leo Mariani from RBC. Please proceed.

Leo Mariani - RBC

I guess, I missed the first part of the call, so forgive me if you guys have already addressed this. Just looking at your production guidance for the remaining quarters of 2009. It looks like your third quarter and your fourth quarter production guidance is kind of come in a little bit, just kind of curious as to what was causing that?

Mike Watford

No. I don't think that's the case. I think we just soften third and moved it into the fourth quarter. So I think fourth quarter is up and third is down a little bit. So they both didn't come down.

Leo Mariani - RBC

I guess then, why is third quarter down such as timing on drilling?

Mike Watford

Because it makes more sense to complete the wells with the fourth quarter prices (inaudible) than third quarter prices with economics.

Leo Mariani - RBC

You guys also talked about increasing the size of your program a little bit in the Marcellus that you're adding a couple of wells out there. Just curious kind of what's caused that or has been some strong industry results in the area where you guys have that acreage or I guess little more color there.

Sally Zinke

Well, I think we spent a chunk of time in 2008, sort of testing the water with vertical wells and we are now ready to expand into a horizontal drilling program.

Mike Watford

I think we are encouraged by comments from others on the south and west of us.

Leo Mariani - RBC

I think if I heard you correctly you made a comment about doing some operated Marcellus activity in the second half of 2009. I think you guys were talking about trying to drill an area called Marshlands. Just curious as to kind where that is, I'm not super familiar with that area.

Sally Zinke

That's on the west boundary of Tioga County. We have a large 100% acreage block there, that already has some other production on it.

Leo Mariani - RBC

Is that Marcellus production or Oriskany or Tuscarora or something else.

Sally Zinke

Tuscarora and Utica right now. We have three vertical Marcellus wells. There is part of our testing program and we are ready to go horizontal.

Leo Mariani - RBC

As soon as in that area that you think you'd be able to expand infrastructure and if you have success with your operated drilling program pretty quickly out there?

Sally Zinke

I think as Bill mentioned we do have a tap on the Dominion line. We do have some gathering for our existing production. We have some right way access, et cetera, and will be able to build out as we start drilling there later this year.

Operator

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

Ron Mills - Johnson Rice

Just a question on the hedging, if you don't mind. I think you had mentioned, Mike, that the current Wyoming price as you look out to 2010 and 2011 is above $5. I'm just trying to reconcile that with where the strip is and the future on CIG, where it looks like it's a kind of $1 to $25 differential. So I'm trying to see how you all came up with in '10 and '11 with 545 to 550 realized prices on your hedges. Does that include some delivery points along the REX-East sections?

Mike Watford

Not at all. Mark tried to talk about it in his prepared comments there that the hedges that are Opal-based or Wyoming-based versus those that are off of REX-East. Now, we did two year hedges, 2010, 2011, because you are exactly right. If you look at 2010 alone, they are lower on average, but 2011 are higher. So we did two year hedges.

That's why you see the volumes for both years increased here in the latest announcements and that's how we're able to achieve the north of $5 per MMbtu, and then when you gross it up for the liquids content of the gas, you have to gross up by 6%. So we're up by 530, 540 per Mcf.

I think Mark talked about the hedges that we've done did for 2010, 2011 off of REX-East into Dominion South where we already sell gas at prices of 6.75 per Mcf. So you take 6.75 and subtract the transport cost of $1.7 plus some fuel at $1.25, $1.30 in total, you get Opal prices of whatever $6.75 plus $1.40 is.

Ron Mills - Johnson Rice

Those hedges off the REXs, are you hedging virtually all of that 200 million a day that you have from transport?

Mike Watford

No, we're hedging hardly of it because we don't think the market truly reflects the prices. We're hedging some of it just to show that we can hedge at prices, that 100% cover our transport costs and give us a little uplift in pricing. It's there just to help guide the investment community that even a forward curve for REX-East delivery in 2010, 2011 gives us the ability to offset all our transportation cost and have some minor amount of pricing uplift to this point it.

We're not able to deliver there yet, so we think it's going to improve when we can deliver. That's in comparison to where we're redelivering of where REX-West is now to that Mid-Continent supply area where we didn't want to be for long, but unfortunately ended up for a extra year where we're not covering our transport cost. That's the big difference we want to make here too.

The $0.70 somewhat of transport costs that we are eating quarterly now or daily, we only can offset part of that and some days none of it, whereas right now it appears that we can fully offset the REX transport cost once we get access to the better markets and get some uplift in pricing. That's the message.

Ron Mills - Johnson Rice

Going forward, it sounds like on your Pinedale wells alone, you expect another 10% plus type cost improvements. From a drilling efficiency standpoint, you are now drilling a lot of your wells less than 20 days. Are you starting to get pretty close to the limits in terms of increased drilling efficiencies from a spud to spud timeframe?

Mike Watford

As far as what we foresee, our records right now is (inaudible). Our drilling folks would say that perfect well could go about 12, their overall engine thing and operations process. We are drilling them routinely below 20. (Technical Difficulty).

Bill Picquet

Not only are we drilling them fast, but actually we're drilling them deeper.

Ron Mills - Johnson Rice

Any real changes in terms of the number of completion stages or the way you are completing the wells as you are going through the process, not including some of the low quality or the under pressured stages?

Mike Watford

(Technical Difficulty)

Ron Mills - Johnson Rice

Mike, I know you spent some time both in your release and the call talking about the new reserve rules and the ability to more than double your proved reserves with drilling few wells. If you think about your outlook the way you've conservatively been booking reserves historically, how do you think you will approach applying the new reserve rules because it would result in quite large increase?

I'm trying to get a sense as to how you are thinking about the new SEC rules versus how Ultra book reserves given that your format has been a little bit different than a lot of the rest of the industry.

Mike Watford

We're a little more conservative. Maybe we're too conservative for our own good sometimes. I don't think we're going to materially change unless they force us to change. There is some rhetoric out there, so they may suggest five years for the press booking. If they force us to do this, I guess we have to go that path.

Our preference is to match the expenditure development capital with their reserve additions and our proved reserve bookings, so that we have F&D cost which is sort of just representative of what we think our future development cost is. I can go through in detail what our future development cost by category is, probable and possible to yearend reserve imports at last year's well cost, which are coming down as our numbers are coming down.

The bottom line is, at the end of the day I think that at last year's well costs, at the time we developed all 5,600 undrilled locations, we're at like $1.67 of development costs and we know that's going to come down. So I would think that overtime that we're going to try and book reserves so that we target $1.30 per Mcfe F&D cost for 2009. I think you'll see us book reserves to cause that to happen with our 200% reserve replacement numbers. So I don't think you're going to see us get ahead of it.

It's important to note that from the incentives that we have at Ultra that we don't have any incentives that are tied to F&D costs or maximizing our bookings, because we're very much aware of the resource we have and it wouldn't be a big challenge for us. The points we want to make are that, folks, I personally will tire of people suggesting that our 12 Ts of 3P reserves match some other company's 3P reserves because they don't at all. They are all PUD-like, they are all within the fairway, they are all engineered, economic, by third-party, all risked. Then we have an arbitrated 2.5 [B] cutoff, which means we get economic wells of 200 Ts that we don't include. We do have those.

We're very conservative and we just want to get the message across that with the most reasonable 2009 reserve recognition rules that we we're 7, 8 Ts easily. That puts us in a class where OG and Marathon and Talisman and all those folks in terms of proved reserves. We've got a lot of work to do to get that into developed category and have cash flow and create value. So that's it's interesting when we talk about our net asset value of PB-10 calculation where we line up all the wells and drill them over 20 plus years at flat capital.

We look at a $6 long-term gas price or $4 gas price escalated 25% at $0.25 per year, and we get the same PB-10 number, which you scratch your head, and say, how can that be? The only way it can be is because we have more production, more cash flow coming our way here in the next five to seven years. That is very valuable. So you have the time for that escalated gas price to basically balance with the $6 long-term gas price.

I now I ran through that quickly. We're just on the cusp of having lots of good things happen to us. Unfortunately, we have a recession that lower gas prices, but we're well positioned for 2010, 2011. If we can grow cash, we can grow production at 10% per annum per year in spending less than cash flow, then just imagine what we can do if we push on the accelerator.

Ron Mills - Johnson Rice

The CapEx going to $670 million, is part of that driven by the overall lowering of drilling costs in the industry and how does that $670 million breakout the Wyoming versus Pennsylvania?

Mike Watford

We took it all out of Wyoming because we dropped rigs and it has nothing to do with anticipated lower costs. So it could go lower and that won't affect our production targets for 2009.

Ron Mills - Johnson Rice

What is the spending look like over the remainder of the year? I think you ended up spending quite a bit, maybe even close to a third of your total budget in the first quarter.

Mike Watford

If my budget is $670 million and I spent $220 million in the first quarter, then I'll get $450 million to spend the rest of the year.

Ron Mills - Johnson Rice

I guess that's my point. It's pretty evenly split over the remainder of the year.

Mike Watford

Is it pretty evenly split, Bill?

Bill Picquet

As Mike said earlier, we plan to have five operating rigs running at Pinedale right now (Technical Difficulty).

Operator

You have a follow-up question from the line of David Tameron from Wachovia. Please proceed.

David Tameron - Wachovia

Obviously, there was a short call on your stock and people were pressuring shares and talked about well segregation and a variety of other things. Do you care to address that? Can you tell me how you respond to that?

Mike Watford

I think Bill tried to do it, but let's do it directly. I think there were some folks suggesting that 2008 well results were less than 2006, in particular, maybe a little less in 2007. They are right. There were because we increased our capital program in 2008 to our largest-ever in our history, $950 million.

Because of limited access in the field, because the ROD wasn't finished, we hoped the ROD would have only taken two years, unfortunately it took three years, we had rigs coming and plans to spend money before we had more access. We spent more the year drilling wells in the less interesting Warbonnet area. I think its 93, 95 out of the 220 wells that we operated and drilled in 2008. We're going to work on it.

That's just averaging of smaller wells with the whole mix, then the average IPs and average reserves of wells we drilled in 2008 were less. That's just right. Just the opposite is about to happen now in 2009, because the ROD is behind us. We're going to be able to hit on pads in the better parts of the field and drill better wells and bigger wells.

The smaller wells in the field and all the Pinedale are in the Warbonnet area that Shell and ourselves operate, and we both got stuck there last year. Up in the north area, Questar operate those. Those are the smallest by far in the whole field. You'll see their results are always less than Shell's and ours. That's just the way it is.

I just want to make the point too, our average reserve size of our PDP well is 5.5 Bs. Our average reserves of our PUD wells at yearend 2008 was 6 Bs. Overtime, if you look at all of the wells we're going to drill, look at Netherland, Sewell's reserve report, all the way down to the five acre wells, when we get through with the 5,600 undrilled location, we're down about 4.4, 4.5 Bs per well. We think that will trend up overtime as they renew some of their conservativeness with that, five acre drilling as well as some of the things that Sally talked about with low quality pay and the normally pressured stuff that we think will trend up to maybe 4.75, close to 5 Bs.

At the end of the day, we're going to be drilling 4.5 B wells. If drilled successfully, taking us $5 million well cost or even down some more, 4.5 B wells, plus or minus $5 million, we're happy with that.

Operator

At this time, there are no further questions in queue. I would now like to turn the call back over to Mr. Watford for closing remarks.

Mike Watford

Thank you very much for your time and attention. If you have additional questions, don't hesitate to contact us. Bye-bye.

Operator

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Good day.

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Source: Ultra Petroleum Corp. Q1 2009 Earnings Call Transcript
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