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Ultra Petroleum Corp. (NYSE:UPL)

Q4 2009 Earnings Call

February 12, 2010 11:00 am ET

Executives

Kelly Whitley – Manager, IR

Mike Watford – Chairman, President and CEO

Mark Smith – CFO

Brad Johnson – Director, Reservoir Engineering and Planning

Bill Picquet – VP Operations, Rocky Mountains

Sally Zinke – Director, Exploration

Analysts

Brian Singer – Goldman Sachs

David Timmon – Wells Fargo

Brian Corales – Howard Weil

Brad [Padarozi] – Tudor, Pickering Holt

Mike Scialla – Thomas Weisel Partners

Ron Mills – Johnson Rice

Noel Parks – Ladenburg Thalmann

Ray Deacon – Pritchard Capital Partners

Joe Allman – J.P. Morgan

Operator

Welcome to the fourth quarter 2009 Ultra Petroleum Corp. earnings call. (Operator instructions) I would now like to turn the conference over to Kelly Whitley, Manager Investor Relations. Please proceed.

Kelly Whitley

Thank you, Operator. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's 2009 earnings conference call. On the call with me this morning to discuss our 2009 results, reserves and 2010 guidance are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Chief Financial Officer; Bill Picquet, Vice President Operations; Brad Johnson, Director Reservoir Engineering and Planning and Sally Zinke, Director, Exploration.

Before turning the call over to Mike, I would like to cover a few administrative items. First, this call will contain forward-looking statements that involve risk factors and uncertainties detailed in our SEC filings. All statements other than statements of historical facts included in this call are forward-looking statements. Also, this call may contain certain non-GAAP financial measures. Reconciliation to calculation schedules for the non-GAAP financial measures can be found in our 10-K and other filings with the SEC available on our website.

Beginning with year-end reserves for 2009 the SEC permits oil and gas companies in their SEC filings to disclose pre-reserve, probable reserve and possible reserve. References in this call to 3P reserves include estimates from each of these categories of reserves are also considered forward-looking statements. Once a again you can find disclosure in our 10-K and other filings with the SEC on our website.

Second, Ultra will be participating in several conferences over the next few weeks. To name a few, we will be at the Raymond James Institutional Investor Conference in Orlando on March 8th and the Howard Real Energy Conference in New Orleans on March 24th. Please visit our website to view updated presentations and listen to webcasts.

Now let me turn over the call to Mike.

Mike Watford

Thanks Kelly. Good morning and welcome. We have a full house assembled today to discuss our year-end results so let me make a few short comments and let the team share the details.

Recently I read a report where the author stated simply that “the best exploration and production companies are those that add oil and gas reserves cheaply and produce them at low costs.” Well, Ultra Petroleum has to be in that mix because once again in 2009 we added oil and natural gas reserves at a very attractive cost, we increased our production to a new record level and our all in costs are probably the lowest in the industry.

As a result we generated returns that will likely lead the industry. We avoided the trap of profitless growth and we removed the resource uncertainties surrounding our Marcellus position. We maintained our balance sheet flexibility so we could bid constructively for additional Marcellus resource and fund it with attractively priced, long-term debt. Let’s ask Mark to share the financial details.

Mark Smith

Thanks Mike. Good morning. As you can see from our press release we had a very good year operationally despite little overall gas prices during the year. We saw strong performance in the field with ongoing improvement in drilling efficiency, record production levels and reduced costs. Our commodity hedge position significantly increased our average gas price which helped us to offset some of the effects of lower spot prices during the year.

We have previously discussed the completion of the Rockies Express, REX East pipeline, increasing take away capacity out of the Rockies. Combined this with the decline we began to see in our peer’s overall Rockies production over the fourth quarter and we saw improved pricing relative to Henry hub as we exited the year.

I believe most importantly we demonstrated our ability to deflect organizationally and defend our margins in the face of dramatically lower commodity prices. This in turn led to strong returns for the year.

For 2009 our production was up 24% to a record 180.1 BCFE. Again this was an all-time high for the company. This increase was largely due to our improved drilling efficiencies in Wyoming as we reduced our investments in oil and gas properties by 29% year-over-year. Bill will address our operations in detail.

Natural gas prices were down significantly on average through calendar 2009. Our average un-hedged gas price was $3.49 compared to prior year levels of $7.12. However, a commodity hedge position improved our average realized gas price by $1.39 per MCF. Our average realized gas price for 2009 was $4.88 per MCF, 33% lower than our average price during the prior year.

As a result of our increased production levels offset by the decrease in realized commodity prices, revenues including the effects of our hedges registered $906.1 million for the year. Corporate lease operating expenses for 2009 decreased to $0.89 per MCFE compared to $1.33 during 2008. This decrease was a result of reduced severance and production taxes due to lower commodity prices combined with reductions in our unit production costs. Our production costs have improved over last year as our partners have worked to reduce their operating expense levels and our mix of operated wells has continued to increase.

Transportation costs amounted to $58 million during the year or $0.32 per MCFE on our total production volumes and were flat with prior-year unit levels. Our DD&A rate raised to $1.12 per MCFE for the year. General and administrative expenses on a unit basis were down compared to the prior year at $0.11 per MCFE while interest costs registered $0.21 per MCFE. The net effect of all of these factors was a $0.58 per MCFE or 18% year-over-year decrease in overall corporate costs to $2.61 per MCFE.

With our continued focus on operational improvements and cost reductions, our cash fuel level cost decreased 6% on a unit basis over prior-year levels to $0.48 per MCFE. Operating cash flow registered $637.6 million for the year, providing a 70% cash flow margin. Adjusting for the non-cash unrealized losses associated with the mark to market position on our hedges, we recorded adjusted earnings of $282.2 million for the year, providing a 31% net income margin and $1.85 adjusted earnings per diluted share.

In terms of returns for the year our return on average capital deployed was 18% and our return on equity was 32%. Cash provided by operating activities during the year amounted to $592.6 million. Investment activities for the year were largely comprised of $673.5 million in oil and gas property investments and $67.8 million of investment associated with gathering systems. For the year net cash provided by financing activities totaled $228.1 million consisting largely of $235 million from our senior note offering in March offset by net repayments on our senior bank facility.

We ended the year with approximately $44.2 million of cash on hand and $795 million in debt. Recall that our senior debt capacity is just over $2 billion of the $44.2 million of cash on hand $25 million represented funds held in escrow for the Marcellus leasehold acquisition. We continue with our due diligence activities and expect to close around February 22nd. In support of the acquisition we have executed a $500 million private placement of senior, unsecured notes. We expect to fund the remaining $230 million of the offering on February 16th providing for a series of 7, 10, 12 and 15-year maturities with a weighted average term of 10.6 years and a weighted average price of 5.46%.

As we move through 2010 we believe our liquidity allows us to fund far more than the remaining $1.5 billion and our planned 2010 investment program through the use of both our cash flow from operations combined with our revolving credit facility.

I want to spend just a couple of minutes on our price outlook for 2010. Prices are up meaningfully and differentially. Last year March through December first of month index prices at [Opow] averaged $2.96. This year, the balance of 2010 pricing is currently trading at around $5.37. This reflects an increase of over 80% over prior year levels. Compared to 2009, Henry hub March through December prices of $3.73, the balance of 2010 pricing of Henry hub of $5.71. This is up approximately 50% over last year’s level.

This differential change in Rockies basis is very important. I want to focus on this improvement by directing to you the summary table of historical and forward basis differentials to Henry hub we have provided on page four of this morning’s operational press release. We have addressed this a number of times and given its significance I want to review this once again.

We have seen basis differentials for Rockies gas improve significantly. That is, it has become much tighter. Prices range from a low of 58% of Henry hub average in calendar year 2007 to a level now which is roughly 98% of Henry Hub. We are currently selling gas in Wyoming at a spot basis of $5.21. This improvement in Rockies basis has occurred while Dominion South basis has come from a low of 104% of Henry Hub average in calendar 2006 to year-to-date levels of 106%.

We have seen increased takeaway capacity out of the Rockies on first Rex East and ultimately Ruby. We are also seeing production in Rockies beginning to decline due to reduced drilling activity while gas has become congested in other areas of the country. As a result we have seen a tightening in the markets due to basis differentials going forward. When we take all of this into consideration and focus on our firm transportation on Rex combined with our overall corporate mix of production we see our corporate basis going forward improving to approximately 94-96% of Henry hub.

I want to amplify this point. Recall our firm transportation on Rex allows us to move 200 million per day into the Northeast where we sell the bulk of this gas at prices referenced to Dominion South. Combine these volumes with the increased levels of production in Pennsylvania and we expect to be selling about half of our produced volumes in the northeast reference to Dominion South or similar pricing.

So when one looks at this in detail against the forward market for 2010, this translates to a corporate discount of roughly 3% off Henry Hub and compares to a 2008 Rockies discount of 31%. Again this is an improvement of some 30% in corporate discount to Henry hub. So what does this mean to Ultra? Assuming a $5.50 gas price, a level where we have hedged roughly 46% of our forecast 2010 production, this amounts to another $1.65 per MCF. After severance taxes, $1.45. A 215 BCFE, our 2010 forecast volume, this amounts to an additional $312 million in cash flow. Very meaningful.

Again, this change in corporate discount is driven by; One, the effects of Rex on regional takeaway capacity and as a result Rockies prices. Two, our increasing production in the Northeast. Three, our firm transportation capacity on Rex. We expect this improvement in basis differential and its effects to be long-term in nature and the forward markets support our view on this again as we show in our press release. The outlook for Rockies prices are supported with the completion of the Ruby and Bison pipelines, as well as the Kern River expansion, together adding some incremental 2 BCF per day of takeaway capacity from the Rockies as we move through 2010 and 2011.

Moving to hedging, as detailed on page four of our press release we currently have approximately 46% of 2010 forecast natural gas production hedged through fixed price swaps at a weighted average price of roughly $5.49 per MCF. For calendar 2011 we have about 73 BCF hedged at a price of roughly $5.61 per MCF.

I will wrap up my comments by pointing out that on page two of our capital budget guidance press release we are establishing production guidance at 215 BCFE and a capital investment program of just over $1 billion in addition to our Marcellus property acquisition. We will provide additional detail on our outlook and guidance in our press release.

Now I will pass it off to Brad for an update on our reserves.

Brad Johnson

Thanks Mark. Oil and gas reserves are the most important aspect of an E&P company. Ultra’s reserve estimates were prepared by Netherland, Sewell and Associates, a third-party and independent reserve consulting firm.

For 11 years straight Netherland Sewell has estimated reserves for Ultra’s assets including a team of professionals that have been evaluating the Pinedale and Jonas fields since 1996. In the same manner as previous years, the 2009 year-end reserve determinations include the review of every single producing well and every potential location in our assets.

Ultra’s year-end reserves have been prepared in accordance with the new requirements that are effective this year as set forth by the SEC. While a number of guidelines in the new rules may provide some companies the ability to disclose additional reserves, Ultra has elected to determine its pre-reserves in the same manner as before. We continue to limit our proved, undeveloped reserves to those hub locations that can be drilled within our three-year budget and planning cycle. While the company certainly utilizes reliable technology such as seismic wire line formation testing, geophysical logs and core data to assess and optimize the value of its resources, none of these technologies were used to affect a material change to reserve additions. The reserve additions I am about to report are all organic with no real change adds.

Now for the results. Ultra’s year-end 2009 proved results are 3.912 trillion cubic feet equivalent. This represents an 11% increase over year-end 2008. Proved developed reserves are 1.6 BCF equivalent and represent 41% of the total proved reserves. Proved undeveloped reserves are 2.3 BCF equivalent with corresponding future development costs of $2.16, the development costs for our PUDs is $0.94 per MCF equivalent.

In 2009 Ultra posted another year of outstanding reserve growth. Reserve replacement was all organic growth and totaled 319%. All in, finding and development costs were $1.29 per MCF equivalent. As I mentioned before there are no material additions resulting from the new SEC rule changes. Year-end proved reserves for 2009 were determined with a 12-month average well head price of $3.04 per MCF of gas and $52.18 per barrel of oil. Despite a 35% decrease to the year-end gas price used in year-end 2008 reserves, Ultra’s proved reserves increased 11% year-over-year. Also please note that at $3 gas the company’s reserves did not experience a ceiling test write down.

Our [one feed] proved reserves remain Wyoming based, representing 99.4% of the total company proved reserves. For year-end 2009 the company’s ratio of PUD locations to its proved developed locations is 0.65 to 1. [if] book proved developed reserves in Pennsylvania with a handful of wells producing at year-end including a Marcellus horizontal well with an EUR of 6.8 BCFE.

Next I want to report on Ultra’s 2P economic reserves. For year-end 2009 Ultra’s 2P reserves totaled 11.036 BCFE. This is a 17% increase over last year’s total of 9.4 BCFE. This 2P growth is attributable to Pinedale where strong well performance continues to affirm the low risk and hard profitability of the Pinedale [decline] development. It is also important to note that the probable reserves of the 7 BCF equivalent includes over 1,800 technical PUD locations in Pinedale and Jona representing 2.7 BCFE net reserves. Please recall that Ultra’s technical PUDs are those bookable, economic PUD locations that are scheduled beyond our three-year planning and budgeting cycle. These wells are not poor wells. They have an average EUR of 4.7 BCFE.

If we chose to include all of our bookable PUDs our proved reserves would approach 7 BCFE but at a [PV]10 value of over $10 billion and the resulting ratio of PUD locations to proved developed locations would be less than 2.2 to 1.

Now onto our economic 3P reserves. Ultra’s 3P reserves are 14.5 BCFE at year-end 2009, a 25% increase from a year ago. This increase of approximately 3 BCFE to our 3P reserves comes from our Marcellus assets. We added 1,638 gross Marcellus horizontal locations to our 3P database this year. Each of these locations have a planned drilling unit that are incorporated into our development plans. Using a 100 acre spacing per well, our 3P reserves in Pennsylvania correspond to 164,000 gross acres or only ½ of our Marcellus acreage at year-end 2009.

We expect to add additional 3P reserves in 2010 as well as begin elevating Pennsylvania possible to probable and proved reserves as appropriate. Ultra’s 3P reserves are reported using a $6 gas price and a $60 oil price. At these prices the pre-tax [PV]10 value for the 1P reserves is $7.9 billion. For the 2P reserves this value is $12.1 billion. For the 3P reserves the pre-tax [PV]10 value is $16.5 billion.

In summary, Ultra delivered another outstanding year of reserve growth with proved reserves increasing 11% and all organic reserve replacement of 319% and an all-in F&D cost of $1.29 per MCFE. Ultra’s third-party engineered economic 3P reserve base currently exceeds 14.5 BCFE. Looking forward, Ultra’s reserve pipeline is full. Over 1,800 technical PUDs in Wyoming are primed and ready for movement from probable to proved. In Pennsylvania half of the Marcellus acreage is currently in contingent reserves and is poised to move first into possible reserves and then onto higher, probable and proved reserve categories.

Now I would like to pass the mic over to Bill for an operational update.

Bill Picquet

Thanks Brad. In Wyoming in the fourth quarter Ultra brought on stream 47 gross, 21 net new producing wells. For the full year 2009 Ultra brought online 228 gross, 107 net new wells in Wyoming. The average initial 24 hour sales rate for these new Pinedale producers was 8.4 MCF per day. Ultra’s operated Pinedale wells averaged 10.4 MCF per day while the non-operated wells averaged 6.7 MCF per day.

The high for the quarter was from the Ultra operated Riverside 2C1 [10D] which floated 16.5 MCF per day. At the end of the fourth quarter there were nine Ultra operated rigs drilling in Pinedale and four non-operated rigs also working on Ultra interest lands for a total of 13 active rigs in Wyoming. Ultra operated wells during the fourth quarter averaged 6.4 BCFE EUR. Our average reserve size per well was significantly better during 2009 as compared to 2008 due to year around access in better parts of the field.

During Q4 all of our operated activity in Pinedale has been in the more prolific Riverside and Mesa areas of the field. Going forward for the majority of the next decade essentially all of our development wells in our Wyoming program will be drilled in these areas.

Our operating efficiency in Pinedale continues to improve. In the fourth quarter we averaged less than 16 days spud to TD for Ultra operated wells, a 31% improvement over the average for Q4 2008. For the full year 2009 we averaged 20 days spud to TD for Ultra operated wells. During the fourth quarter our average rig release to rig release was 19 days, down 39% from our Q4 2008 average at 31 days. For the full year 2009 we averaged 24 days rig release to rig release. 97% of Q4 wells were drilled in less than 20 days spud to TD. For the full year 73% of our wells were drilled in less than 20 days spud to TD.

Our average cost for the full year 2009 was $5 million per well. As impressive as these statistics are for 2009 our early 2010 performance continues to improve as we drill a very high percentage of pad wells using skid capable rigs. Continuity of rig personnel, a fit for purpose rig fleet and an ongoing focus on drilling efficiency and technology advancements is producing excellent drilling results. Our costs continue to improve. We are averaging $4.8 million per well in early 2010. We expect to establish more new standards for drilling in Pinedale as we redefine the limits of technology, rig performance and personnel performance for the project.

Our completion operations results have also been outstanding. For the full year 2009 we have pumped a total of 2,687 frac stages averaging almost 25 stages per well compared to just over 2,900 total stages and 22.7 stages per well during the full year in 2008. We averaged $73,000 per stage during 2009 compared to $78,000 per stage in 2008. The increased average in frac stages per well during 2009 and going forward is due to the fact we are drilling and completing wells in the best areas of the field where there is more net sand pay per well. This requires more stages to effectively access the larger reserves per well.

Unfortunately, contrary to some theories, reserves per well are not added by simply increasing frac stages. Our completions are individually designed for each well in order to cost effectively provide access to the reserves available in each well. During 2010 we expect continued improvements in our completion performance. We are currently averaging $65,000 per stage in Pinedale. We are benefitting from the continuity of equipment and personnel in our frac operations in a similar fashion to our drilling efficiency gains.

Overall, in Wyoming we are drilling deeper and increasing the number of frac stages per well as we drill in the more prolific Riverside and Mesa areas of the field while still reducing our costs. We are improving our operating performance primarily through efficiency gains and the ability to effectively assess and apply new technologies.

In Pennsylvania we are also seeing early benefits of our operating approach as we drill longer laterals and drill more cost effectively in our early Marcellus project activities. Learning’s from our Pinedale project are being applied to accelerate our efficiency gains in Pennsylvania. We have the experience gained in Pinedale giving us the knowledge to very effectively approach a significant scale of operations in Pennsylvania. We currently have three horizontal rigs drilling at our Pennsylvania Marcellus activities, one operated and two non-operated. Our costs are averaging $3.5 million per well with an average lateral link exceeding 3,800 feet per well. We expect the cost performance to improve and we expect our lateral links to grow as we drill further and faster.

We are very excited about how quickly our drilling and completions teams are improving our operations in this project. Currently we are averaging 14 stages per well in our completion operations in Pennsylvania and in our Marcellus shale completion design we divide the lateral into the number of stages that optimizes access to this homogenous shale resource. Unlike Pinedale where the number of frac stages is dependent upon net stand pay in the well and the most effective grouping of these stages, in Pennsylvania the number of stages is based upon the length of horizontal lateral, the amount of lateral in zone and the optimum size of the overall stimulation program for each well.

With that I will turn things over to Sally to continue our Pennsylvania update.

Sally Zinke

Thanks Bill. Our Pennsylvania exploration efforts have focused on horizontal drilling in the Marcellus shale. Since encouraging success early in the year, Ultra has expanded activity and together with partners built a total of 35 horizontal Marcellus tests with two vertical Oriskany wells in 2009.

This activity was in our five county focus area in north central Pennsylvania which includes Potter, Tioga, Bradford, Lycoming, and Sullivan counties. 18 horizontal Marcellus wells have been completed and 13 are producing as gathering line connections are made. The 13 horizontal wells brought online during 2009 had IPs averaging 7.5 million cubic feet per day with the best well IP at 10.46 million cubic feet per day. Average calculated 30 day production rates for these wells was in excess of 4.8 million cubic feet per day with the highest average 30 day rate at 7.86 million cubic feet per day.

A preliminary ultimate recovery estimate for these wells was the type curve used in our Marcellus models which yields an expected EUR per well of 3.75 BCFE with early performance of some wells indicating EURs in excess of 6 BCFE. This type curve is available on the Ultra website on the homepage.

Focusing in on the portion of the Marcellus program on our operated 100% marshlands acreage, Ultra drilled a total of 8 horizontal Marcellus wells by year-end 2009 and have drilled 10 to date. First Ultra operated T-Pierson 801 5-H with a lateral ink of 4,097 feet. Completion of this well included 13 stages with an IP rate of 10.4 million cubic feet per day and an average calculated 30 day production rate of 7.7 million cubic feet per day. We expect to drill an additional 110 horizontal Marcellus wells in 2010. We continue to utilize seismic data for optimal well placement and anticipate acquiring about 80 square miles of additional data in 2010 bringing coverage of our acreage to about 2/3.

Our leasehold in Pennsylvania is approximately 170,000 net acres. We began our horizontal Marcellus exploration program earlier this year with our first horizontal well TD’ing in May of 2009. As we discussed last quarter, As we discussed last quarter, our acreage covers an area 40 miles wide, and 30 miles north to south. Our 2009 horizontal exploratory drilling program has successfully assessed this entire area and removed resource uncertainty of our holdings.

Our four pipeline task with expansion in mid 2010 to a capacity in excess of 560 million cubic feet per day will facilitate our development program. A geologic evaluation has expanded beyond our five county area. We have identified a [age] trend in some localized areas as being optimal including Clinton and Centre counties directly southwest of our holdings. We have continued to look for opportunities to allow us to expand and hydrate our positions and the potential we perceive in this play. With that framework we have been reviewing opportunities and options to maximize Ultra’s position and provide greater resource potential.

Critical geologic factor which have been identified include; [inaudible] of the Marcellus shale section, high organic content in the lower Marcellus which we consider to be the optimal interval, thermal maturation, depth and pressure components with a preference for over-pressured areas. Confirmation of geologic parameters in core and log data has been an important part of our analysis. [Substantial contiguous lease locks] can provide increased ability to form drilling units and consolidate gathering and pipeline connections. Areas with key critical factors and contiguous lease [locks] have been assessed for opportunities to enhance Ultra’s position.

Of particular interest have been those areas where well results have further de-risked the acreage. We have identified and executed on several such opportunities to high grade our leaseholds based on geologically defined resource potential and other operational considerations. Brad will elaborate on both our Marcellus type curve and this enhancement of our acreage position.

Brad Johnson

Thank you Sally. We have recently posted on our website an updated type curve for our Marcellus wells. This plot shows the results from our first 13 wells that were producing by year-end 2009. I want to point out a few things regarding this plot.

First, the results of our wells in 2009 affirm our 3.75 BCF type curve for our current Marcellus acreage. The 13 well average actually exceeding our type curve as shown on the plot. Also on this curve we show the results of the first six wells in the program as compared to the results of the last seven wells. For the first six wells brought online the 30 day average production was 3 million cubic feet per day. For the last seven wells brought online the 30 day average production was 5.7 million cubic feet per day indicating a nearly twofold increase in this early stage of our learning curve in the Marcellus.

In 2009 we expanded our acreage position in our focus area of North Central Pennsylvania. Ultra began the year with approximately 288,000 gross, 152,000 net acres in Pennsylvania. By year-end 2009 our acreage position expanded to approximately 326,000 gross, 169,000 net acres. Early well results have already significantly reduced the risk and uncertainty of our Marcellus resources.

In December of 2009 Ultra announced a strategic acquisition of approximately 79,000 net acres within the company’s focus area of North Central Pennsylvania. Ultra is excited about this acquisition and expects to close on it later this month. This acquisition is located in a highly perspective area of the Marcellus shale where our regional models and sufficient well control confirm very favorable geologic characteristics for commercial shale gas development.

For example, the acquisition area has almost twice the shale thickness and 60% higher pressure than our current Marcellus assets. While this area may potentially be 1.5-2 times more prolific we have accounted for this additional resource potential by using a 5 BCF type curve that is only 33% higher than our 3.75 BCF type curve for our existing Marcellus acreage. This acquisition has already been de-risked from a resource and an execution standpoint. We are not starting from scratch with this acreage. Instead this acquisition includes wells that have been drilled, wells that have been tested and wells that are producing.

Logs, core and micro seismic data have been analyzed and interpreted. High pressure gradient and dry gas reservoir is confirmed and the flow test rates and pressures affirm at least a 5 BCF type curve is appropriate. We are also excited about the execution of developing this resource. The acreage is very concentrated and contiguous, a large portion is held by production and a significant amount of access and infrastructure is in place. Many permits are in hand and right of ways secured. Three interstate pipelines crisscross the acreage and 7 taps are expected to have a takeaway capacity of 500 million cubic feet per day by year-end 2010.

Drill costs are falling faster than what we had built into our acquisition economics and water management plans in place are very similar to the designs of our operations in the marshlands area. The acreage is governed by a joint exploration agreement that covers nearly 740,000 gross acres providing for an opportunity for more growth in the future. In summary, this acquisition is extremely compelling.

Now I would like to turn things back over to Mike.

Mike Watford

Thanks Brad. Just a couple of summarizing comments and then questions. We believe in growth and making money. In 2009 we grew production, we grew reserves and we delivered strong returns. Even in the commodity price meltdown in 2009 Ultra returned an equity of 32% and a return on capital of 18%. For the 2009 cash flow breakeven of $1.20 per MCFE and net income breakeven of $2.54 per MCFE Ultra’s profitability is resilient in the down cycle.

In 2010 we will again deliver top tier growth with low cost and with a significant increase in Rockies natural gas prices currently up 80% year-over-year we expect to see expanding margins. Our shareholders should receive more bang with our growth.

Regarding capital allocation, in 2009 we withdrew or reduced capital to our business due to deteriorating returns and in 2010 we will be adding and reallocating capital due to improving returns. We continue to be ultra conservative in recognizing our proved reserves. We have not included any material reserve additions attributable to the new SEC rules and have not included any proved undeveloped locations in our proved reserves from our growing Marcellus position.

In Wyoming we recognized less than one PUD per producing location. The actual ratio is 0.65 to 1. A more comparative proved reserve estimate from Wyoming only is 6.8 trillion cubic feet equivalent with a [PV]10 value of $10.4 billion or $68 per share, proved reserves only and 10 trillion cubic feet of proved reserves is only a few years away. We continue to make material gains in operating efficiency. We have a solid history of gains in Wyoming and now we are transferring these skills to our Marcellus program. Our efficiencies in the Marcellus will improve.

We are forecasting visible production growth at the 20% per year level for the next three years while generating free cash over the time period. We are establishing a second growth platform and providing diversification to the expanding resource base while enhancing returns. It is difficult to think of a better combination of assets than the Pinedale anticline and the Marcellus shale. The consistency and sustainability of our growth returns is a differentiating factor.

Now operator I would like to open it for questions.

Question and Answer Session

Operator

(Operator Instructions) The first question comes from the line of Brian Singer – Goldman Sachs.

Brian Singer – Goldman Sachs

Can you talk to what you believe drove the increase in Marcellus production rates from those first seven wells to the recent 6-7 and provide some geographic color of where the recent ones were drilled versus the first few?

Sally Zinke

I think the primary differences would be both lateral length and identification of what portion of the Marcellus is the optimal portion and which to drill and complete. As we get up the learning curve we [got] a few things and we think we are honing in on what best practices are.

Mike Watford

Was there much geographic diversification in the results?

Sally Zinke

Pretty much widespread. Those latter wells represent pretty much a cross section across all of our acreage.

Mike Watford

So it is more about our drilling techniques and how we are fracing away.

Sally Zinke

Right.

Brian Singer – Goldman Sachs

Separately, on the central PA wells can you talk a little bit more to some of the recent data points that is giving you confidence that Central PA has been de-risked at the 5 BCF or more type curve?

Brad Johnson

An update on that area, close to 20 modern wells have been drilled in the area and currently three wells are producing at a constrained environment operationally. We believe they have been under stimulated. Those results are very encouraging and they are actually better than our average type curve up north.

Sally Zinke

I think I can elaborate on that a little bit more. We do have core data from central portions of that acreage. We had that prior to assessing this valuation but as Brad mentioned earlier with twice the thickness of Marcellus we have at least 50% more high organic content in the lower Marcellus which is where we are targeting our efforts. The maturation level is higher so you have more material and it is cooked a little bit better then the over pressure gives you higher recovery factor. So what is not to like.

Brian Singer – Goldman Sachs

How should we think about the ramp up in Pinedale this year from a production perspective? Is there any seasonality left now that the SCIS has kind of gone through?

Bill Picquet

No. seasonality is not an issue at this point in time. We are very actively completing in Pinedale and it will be a fairly evenly spread capital program as far as Pinedale is concerned.

Operator

The next question comes from the line of David Timmon – Wells Fargo.

David Timmon – Wells Fargo

One of my competitors out there was the fact that Pinedale production is declining. Can you just talk about how you think capital allocation between the two and obviously just the 2010 numbers but how you view the tradeoff between the two?

Brad Johnson

Sure. 2009 production at 180 B’s. There is diminimous production from Marcellus and Pennsylvania so that is all Wyoming potentially. We are only forecasting at this time less than 20 B’s of production from Marcellus in our 2010 numbers so you see most of the growth in 2010 is coming from Pinedale. We are essentially at this time for our three year planning purposes, we can always change that but for our three year planning purposes, we are sort of flat lining capital allocated to Pinedale as we ramp up what we think is going to be an equal if not better returning resource in Marcellus. So we are looking at $525-550 million per year of drilling capital in Pinedale over the next three years which gets us to that 195-200 B’s per year of production and we can sustain that.

We are looking to allocate some $350-400 million a year of capital towards the growth in Marcellus, more valuation primarily and infrastructure build out in 2010 and for increased production in 2011 and 2012. We have less than 10% of our production in 2010 will be Marcellus. Probably 25% or so in 2011 and in 2012 we are looking at 35-40%. But there is nothing wrong with Pinedale. Pinedale is wonderful. We just have an opportunity to grow scale and grow size in a second, very attractive resource area and we want to spend some money here in the next couple of years to do that.

David Timmon – Wells Fargo

I am trying to do the math but it sounds like your F&D costs are going to be plus or minus at the same level going forward?

Brad Johnson

Our historical style has been to tailor F&D to approximate depletion. Depletion is a little lower because of the four ceiling [caps] write off first quarter of 2009 when gas prices were less than $2.50 in Wyoming. Yes we’re going to be in this $1.30 range sort of flat.

Operator

The next question comes from the line of Brian Corales – Howard Weil.

Brian Corales – Howard Weil

A quick question on the Marcellus. Could you maybe give me a bit more color on the infrastructure build out and are you able to put most of these wells online right away or is there still a lot of gathering lines being built here?

Bill Picquet

Let’s just talk about where we are. As we mentioned earlier we had drilled 35 horizontals. We have 13 online right now. We are waiting on permits as far as infrastructure is concerned from a regulatory approval perspective that has slowed us down a little bit compared to what our previous projections were as far as timing goes. But we are expecting those permits to start coming in a fairly lumpy fashion and fairly soon. We are being told “any day now” type of words coming out of the regulatory agencies. Once that starts we will be ramping back up construction activities and putting in gathering lines, etc. That will be both gathering lines and water handling lines as well.

Brian Corales – Howard Weil

You mentioned three rigs running, one operated and two non-operated. Does that include any of the newly acquired acreage or is that going to add to those numbers?

Brad Johnson

It doesn’t include any of the newly acquired acreage because we haven’t quite acquired it yet.

Brian Corales – Howard Weil

Still a couple of weeks away huh?

Brad Johnson

Right. So no it doesn’t include anything there in terms of rig count.

Operator

The next question comes from the line of Brad [Padarozi] – Tudor, Pickering Holt.

Brad [Padarozi] – Tudor, Pickering Holt

A question on CapEx for Marcellus talking about $375 million for 70 net wells. I am trying to reconcile that. Does part of that include wells that were not completed last year or could you help me reconcile that a little bit?

Mike Watford

No we won’t be able to help you reconcile. We are not really trying to provide that level of transparency. I think the takeaway is we are heavy with CapEx in terms of the Marcellus activity and we are light with net wells but no, we are not going to attempt to reconcile it.

Brad [Padarozi] – Tudor, Pickering Holt

So part of it is just a bit of conservatism built in on the net wells? You probably expect to be above that?

Mike Watford

Yes I can tell you there is layer after layer of conservatism in our CapEx, meaning probably higher CapEx particularly with Marcellus, meaning lower net wells associated with Marcellus and probably lower production with Marcellus. We are so used to being able to dial in exactly what we do in Pinedale and the Marcellus is like Pinedale was 8-10 years ago where we had more challenges in terms of just timing and when wells would be drilled and come on production with infrastructure. We look forward to bringing Marcellus into the environment where we have Pinedale today so we can finely tune it. We are not there. As Bill said, things are kind of lumpy. We are probably being too cautious in some of our forecasts but again we are probably over estimating CapEx and underestimating net wells and underestimating production.

Brad [Padarozi] – Tudor, Pickering Holt

Staying on the CapEx line for a second, the $65 million for facilities in Marcellus as you grow your position would you expect that to increase? What is included in that? Pipeline hookup? What is the thought going forward from a facilities standpoint in the Marcellus?

Bill Picquet

It is heavy on gathering early on here. What we are doing is really building out gathering in front of the drilling program. As we go forward those gathering facility costs will go down. So we are kind of heavy on capital as far as pipelines or facilities in the field early on.

Brad [Padarozi] – Tudor, Pickering Holt

Switching topics for a second, you talked about the 6.8 from just the Pinedale using kind of a peer evaluation rather than the three-year development pipeline you have used historically going to 10 [Ps] by year-end 2012. How much of that comes from Marcellus versus Pinedale? Do you plan to continue using the three-year timeline in the future and foreseeable or at some point do you think you will switch to the lower peer analysis, five year longer timeline?

Brad Johnson

The first question is walking up to 10 BCF we are at four now. 1P reserves. We get to 7 very easily with our technical PUDs that are bookable and economic right now. We just choose not to. From 7 to 10 is a combination of five acre locations in Pinedale and also the reserve pipeline we see in Marcellus going forward.

Mike Watford

I think Brad would suggest we get there either way. We could probably add that 3 either solely in Wyoming or hopefully solely in Marcellus so the number in 2012 could be well in excess of the 10 P if applicable through reserves. A great quantity of that would be PUDs we have to understand.

In terms of reserve recognition we firmly believe in trying to match development capital with reserve additions. We try to have F&D costs mirror depletion rates. We see very little value in booking up the world and having essentially a zero F&D costs for a year or two and then having a rather large or infinite one for many years as you drill out the PUD. So I think you are going to see us continue to be very conservative in terms of the years and capital. A point that the outside folks wouldn’t be able to see is that in order to have our F&D costs at the $1.30 level in 2009 we actually had to decrease the amount of capital in the three –year projection compared to last year’s. We actually have $100 million of less CapEx in our three-year projection for year-end 2009 reserves to end up at the $1.30 F&D costs. I want to continue to emphasize how conservative we are. In fact we sit around the table and ask what can we do to be more conservative? The only thing we could do to be more conservative would be to book no PUDs.

So we are trying to be conservative in reserve recognition. I guess that is all I am trying to say.

Operator

The next question comes from the line of Mike Scialla – Thomas Weisel Partners.

Mike Scialla – Thomas Weisel Partners

You talked about the attractive geologic attributes of Clinton and Centre counties. I wonder if you have a good handle on the structural complexity there as well?

Sally Zinke

There is seismic data in the area and we did assess some of that as part of our valuation. It is not dissimilar from some of the areas we already hold acreage.

Mike Scialla – Thomas Weisel Partners

On the last call you mentioned you were obtaining some micro seismic results from that. Anything from that you can share at this point?

Sally Zinke

No. We have not had the opportunity to view that. The wells in which we were going to obtain that data are scheduled to be completed in the next month or so. So that is still hanging there in the expectation category.

Mike Scialla – Thomas Weisel Partners

Bill you mentioned a lot of the wells drilled last year were pad drilling. Can you give what number that is in terms of percentage or absolute and where do you see that percentage going going forward?

Bill Picquet

The component of pad drilling at Pinedale was well in excess of 90%. It is going to stay at that level.

Mike Watford

Of the plus or minus 200 wells you can subtract [inaudible] wells for pads right? [inaudible] was 16 wells?

Sally Zinke

Right.

Mike Scialla – Thomas Weisel Partners

Jumping back to Marcellus it looks like you added just five wells online during the fourth quarter. Can you talk about some of the issues you are facing there and getting wells online?

Brad Johnson

It is purely timing for permitting the gathering lines. As I said earlier we are expecting those permits to start coming out in lumpy fashion in the very near future. So our game plan as far as completion of those is to start up on the operated frac program March 1.

Mike Scialla – Thomas Weisel Partners

So you expect that backlog of wells that are waiting to be put online to decrease or is that a pretty good number we should be looking at 20 plus wells and waiting on completion going forward? Or excuse me, being put online.

Brad Johnson

It will decrease slightly. It will be dependent upon the timing as far as those permits are concerned.

Mike Watford

Part of what is going on is we are kind of messing ourselves up a bit in terms of increased productivity in drilling wells that I guess our planning was maybe 20 days per well. I think Bill talked about a little less than 10 days per well. So we need more and we are again evaluating the fields and we are not drilling multiple wells off the pad as some other folks are in terms of development effort. We are really in evaluation/exploration mode and so maybe it is one well per pad and we need more infrastructure for every pad and when we were looking at one well every 20 days and now we are at one well every 10 days and now we need twice as much infrastructure. So it is a good thing in terms of overall but we have some lumpiness in the schedule here which we will get behind us. We are going to have a reasonable backlog all year though is our forecast. We will diligently try and improve on that but our plan it continues.

Bill Picquet

Fill rates continue to come down too.

Mike Watford

That’s right. If we get down to 7-8 days it is all good, longer term answers. We are going to have more lumpiness in 2010 since it is a transitional year for us. We are allocating more capital to a new resource, new growth area and with tremendous returns and we would like to get larger in it as you can see with the acquisition we announced at year-end followed timely by low cost debt to fund it. But we are just going to be real lumpy in 2010.

Operator

The next question comes from the line of Ron Mills – Johnson Rice.

Ron Mills – Johnson Rice

A question to understand bit, I think Sally may have mentioned the exploration agreement covers 740,000 gross acres, is that with the operator of the properties you acquired? How is that exploration agreement structured?

Sally Zinke

That is basically an AMI and it is with the operator of the acreage we are buying.

Ron Mills – Johnson Rice

Is it safe to assume that AMI covers where your current acquisition acreage is located and then also I assume that is kind of what led you to your comments about Clinton and Centre counties as you move a little bit towards the south and west of where you initial acreage was?

Sally Zinke

That is correct.

Ron Mills – Johnson Rice

One last question on the Marcellus, from an infrastructure standpoint on the acquisition acreage what does the infrastructure look like and what is the expected ramp in rig count once you get those properties into the fold and you go from three rigs to what kind of rig count do you think you will go to?

Brad Johnson

To address infrastructure on the acquisition first the area has a shallow production in it. So that has provided existing roads and right of ways. Albeit limited infrastructure right now for the shallow gas it does provide for early testing and viability of the wells. There will be a build out and expansion of the infrastructure going forward. We see those plans. They are timely. I mentioned earlier that the takeaway capacity is expected to be 500 million a day on the 7 taps. We are in an area where the interstate pipelines crisscross so we are very pleased with getting the gas to market in a timely manner.

Ron Mills – Johnson Rice

The 500 million a day in that area is that in addition to the 550 million a day that was referenced earlier for your existing acreage?

Brad Johnson

Yes it is incremental takeaway.

Ron Mills – Johnson Rice

In terms of activity plans between you and the operator, once you get this acreage in hand?

Mike Watford

Let us hedge on that. We directionally…there are some tentative plans out there but I think it is just not timely for us to comment on that until we get the deal closed.

Operator

The next question comes from the line of Noel Parks – Ladenburg Thalmann.

Noel Parks – Ladenburg Thalmann

In the press release you mentioned that if you looked at your reserves unrestricted by the three-year timeframe I think the number was 6.77 BCFE?

Mike Watford

That is correct.

Noel Parks – Ladenburg Thalmann

If memory serves me that is fairly close to the 6 BCFE number you gave on the same basis as of mid year 2009. So it seems like there was relatively little change during the second half of the year. Is that due to prices?

Mike Watford

It is just a limitation. It is essentially the same. There is no negative or positive to it. Just June 30th PUD count in a five-year window is the same as the December 31 PUD count.

Noel Parks – Ladenburg Thalmann

One other item that was in the release was the mention of five acre wells. I think there were nine total this year. Again, at about the midyear point I think there had been five done at that point. The number that was given was about 9.3 million a day IP, about 4.6, what are you gaining in your most recent five acre wells out there?

Brad Johnson

Our five acre wells continue to meet or exceed our expectations. In 2009 we did conduct some five acre pilots in development area two in the Riverside area. We are drilling 40’s, 20’s and 10’s. We haven’t drilled a lot of fives in our pilot area but they continue to meet or exceed our expectations.

Noel Parks – Ladenburg Thalmann

What is the oldest five acre one that you have as far as production history?

Brad Johnson

Our oldest ones are down south and I think it is two years or it could be three years. I will have to check and we can get back to you on that. The work down south would be our oldest fives in our pilot we conducted a few years back.

Noel Parks – Ladenburg Thalmann

If you could get back to me that would be great. In general the results are meeting your expectations and consistent with what you discussed earlier about the ability to add reserves to the five acre locations?

Brad Johnson

We have no concern about our fives. In fact the results to date are encouraging with regard to five acres.

Noel Parks – Ladenburg Thalmann

In the Marcellus I was wondering if you have any thoughts about the rest of the industry’s activity out there? First on the land side, what you are seeing as far as is there a growing consensus let’s just say in Pennsylvania a growing consensus among E&P’s leasing out there about what constitutes good acreage or do you think there is still a lot of difference in opinion out there?

Mike Watford

We are not paying as much attention to others as perhaps you would be from your perspective. We rank or high grade our own acreage depending and it backs out as to what the acreage value is worth. Some acreage is worth you could have positive economics at a long-term $6 gas price from the Marcellus at lower acreage costs which are well drilling costs and things like that. Whereas other acreage allows higher acreage costs because you figure wells higher overall recovery. So it is not that black and white.

Plus we factor in the margin into it. We are all about making some money in our growth and so we want to be a low cost operator. All that fits into what your attitude is going to be on acreage, topography and access and water access. There are lots of things that go into it in terms of value of acreage. I would be happy to tell you we have looked at it in terms of a large area.

Noel Parks – Ladenburg Thalmann

I guess what I was getting at and under the heading of a quality problem, if we see natural gas prices stay where they are or even strengthen going forward and we continue to see good results and compelling results at some of yours in the Marcellus if we look ahead say towards the second half of the year or fourth quarter I am wondering if there is any risk of maybe irrationally high activity in the play? You have a lot of different folks all trying to drill aggressively to hold it and then the impact that could have on the service environment. Do you think that is a realistic concern looking out a year or is it as I said will the Marcellus play gains go back [via such] that people are still going to be out to establish their own beach heads and follow those in whatever region of the play they think is working?

Mike Watford

I am going to come at it from our perspective. The new acquisition is greater than 90% held by production so there is no need to rush into doing anything there other than what is prudent is beneficial to our shareholders. Other E&P operators up there they have a mixture of acreage that has lease expiration issues and other acreages held by production. Then you have companies that are spending their own money versus companies that are spending someone else’s money so you have a whole melting pot of different issues there that would address how fast or slow those go. I don’t really have anything to say about it.

Operator

The next question comes from the line of Ray Deacon – Pritchard Capital Partners.

Ray Deacon – Pritchard Capital Partners

I was wondering you talked about the pace of completion in the Marcellus and you have had kind of 13 wells on completion when you make the acquisition and it still looks like you are about there. Are there delays in getting frac crews up there? How many wells do you think you will complete to get to 100 million a day for the end of 2010?

Bill Picquet

Back to permit timing and installation of infrastructure as far as pace goes. Completion plans and access to frac crews are all well planned out. So we will see what pace is warranted based upon the pace of permits which as we said is going to be pretty lumpy. We plan to start completing our operated completions in March. That will be a sustained program as we are currently planning. We got to peak net production of 25 million a day in the fourth quarter. We are about 20 million a day now. We did that with far fewer wells than we anticipated. We think that will carry over to 2010 and we will be able to approximate exit rates or exceed exit rates on far fewer wells than we probably have in the plan right now.

Ray Deacon – Pritchard Capital Partners

Is there an opportunity to increase your operated acreage in the marshland area where you are? Is that a priority? Do you have enough acreage now do you think?

Bill Picquet

The priority is to continue to grow scale here. I think our internal view is in the acreage that we have put together by early December of 2009 we thought we were looking at a risks net reserves to Ultra of about 5 trillion cubic feet once it all got developed. We are thinking with the acquisition we have added 3-3.5 T’s to that. Are we interested in adding additional attractive returns resource in the area? Absolutely. Do we have a preference for operated? Yes. Because we think we are a very effective, low cost operator but that is not the primary determinant. The primary determinant is to make money for the shareholders and grow the resources. We try to not let that get in our way if we can make a good decision.

Ray Deacon – Pritchard Capital Partners

I am kind of confused about the whole transportation system up in the northeast. You hear different things. I guess with Talisman had talked about securing about 400 million of firm transportation by 2012 and it sounds like you are negotiating with all of the people who have these proposed pipelines up there. I am assuming. But do you see any particular near-term projects that are going to help? I know NSG I think added some or is in the midst of adding some at Tioga but are there any projects you are lining up behind I guess is the question.

Mike Watford

Currently we are just lining up behind our own projects. We are putting together infrastructure and perhaps building the larger trunk lines to the storage hub areas to have access to the five different interstate pipelines. As you said, there are multiple projects out there and we will just kind of work our way through that. I think the point and Brad made it, is that between the acreage we already have, the new acreage we are going to get from the acquisition there is multiple interstate pipelines servicing the area and we will develop multiple interconnects with those pipelines and have multiple markets off those.

Operator

The next question comes from the line of Joe Allman – J.P. Morgan.

Joe Allman – J.P. Morgan

In terms of your reserves you didn’t give a revision number in the release. I know it is relatively small. Could you give us that number and how much of that was proved developed?

Brad Johnson

Our revisions are going to come in around 6% downward and that is all price related. As you know our price year-end 2009 was $3.04 versus $4.71 so it is 6% down revision that will be in the K and that is price related.

Joe Allman – J.P. Morgan

What part of that is proved developed? As opposed to….

Brad Johnson

It would be across all categories that are proved. The proved developed wells would have some [tell] effect just like all the other cases. The price revision is really spread proportionately based on volumes you see among those proved categories.

Mike Watford

What he is saying is it all has to do with tail volumes.

Joe Allman – J.P. Morgan

When we try to calculate your proved developed PDF&D so we are just trying to calculate the cost at proved reserves and we are coming up as a number I guess we will have to punch in the revision number now but somewhere $1.50 upwards of $2.00 on the PDF&D for this year. Last year was about $1.60. I am trying to reconcile that with sort of I think earlier in the call you said that the cost to develop the PUD is about $0.94. So I am trying to reconcile that. For example, I think in 2009 you spent about $550 million in Wyoming just on drilling alone…

Mike Watford

Wait. When Brad is giving you a number of dollars to develop a PUD it is a samp of dollars. If we had shot additional seismic over an area or acquired an additional lease in the area or have some other workovers and other wells in the area all of that goes through our drilling budget. So that is not apples-to-apples.

Joe Allman – J.P. Morgan

So when you factor that in what would you consider your all in cost to add proved develop reserves?

Brad Johnson

We know our all in costs for 2009 was $1.29 and our PUD…

Mike Watford

He is saying PDPs is what he is saying, not PUDs.

Brad Johnson

It would be between the PUD $0.94 and the all in $1.29. So between $0.94 and $1.29 is the range there.

Mike Watford

On just direct investment and wells.

Joe Allman – J.P. Morgan

But just direct investment but when you throw in the other stuff?

Mike Watford

Then it goes up.

Brad Johnson

For 2009 we don’t expect that to be materially different going forward.

Operator

There are no further questions at this time. I will turn the call back over for closing comments. I would like to remind everyone that the replay will be available one hour after the meeting’s end for eight days. The toll free number is 888-286-8010 access code 47985173. I will now turn the call back over to Mr. Mike Watford.

Mike Watford

Thank you for your time. If you have any follow-up questions please don’t hesitate to contact us. Bye.

Operator

Thank you for your participation in today’s conference. This concludes the presentation. You may now disconnect. Have a wonderful day.

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Source: Ultra Petroleum Corp. Q4 2009 Earnings Call Transcript
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