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Ultra Petroleum Corp. (NYSE:UPL)

Q4 2008 Earnings Call Transcript

February 18, 2009 11:00 am ET

Executives

Kelly Whitley – Manager, IR

Mike Watford – Chairman, President & CEO

Brad Johnson [ph]

Mark Smith – CFO

Bill Picquet – VP, Operations Rocky Mountains

Sally Zinke – Director, Exploration

Analysts

David Heikkinen – Tudor Pickering Holt

David Tameron – Wachovia

Subash Chandra – Jefferies

Brian Singer – Goldman Sachs

Noel Parks – Ladenburg Thalmann

Leo Mariani – RBC

Mike Scialla – Thomas Weisel

Ray Deacon – Pritchard Capital

Ron Mills – Johnson Rice

Andrew Gundlach – ASB

Robert Christensen – Buckingham Research

Operator

Good day, ladies and gentlemen, and welcome to the fourth quarter 2008 Ultra Petroleum Corporation earnings conference call. My name is Heather and I will be your coordinator for today. At this time, all participants are in listen-only mode. We will be facilitating a question-and-answer session towards the end of today's conference. (Operator instructions). As a reminder, this conference is being recorded for replay purposes.

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

Kelly Whitley

Thank you, Heather. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's 2008 year-end earnings conference call. This 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 reserves, business strategy, plans and objectives of the Company's management for future operations, are 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 financial program. Financial results are subject to audit by independent auditors.

This call may contain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our Web site at www.ultrapetroleum.com. The SEC permits oil and gas companies in their filings with the SEC to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producing under existing economic and operating conditions. We use certain terms in this conference call, such as probable and possible that the SEC's guidelines strictly prohibit us from including with the SEC filings. Investors are urged to consider closely the disclosure in our Form 10-K and other filings with the SEC available on our Web site.

At this time, I would like to turn the call over to today's host of the call, Ultra Petroleum's Chairman, President and Chief Executive Officer, Mike Watford.

Mike Watford

Thank you, Kelly. Good morning and welcome. Joining with me today are Mark Smith to provide some financial comments; a new voice, Brad Johnson [ph] to update us on our reserves; Bill Picquet on our operations; Sally Zinke on the exploration side of our business.

After ten years of running Ultra Petroleum through good times and less good times, 2008 started with a boom and ended with a thud. But from an operational and financial perspective, it was an exceptional year filled with accomplishments that we should savor and proudly take credit for. For example, we produced more natural gas, earned more net income, and generated more cash flow than at any time in the Company's history.

Our decisions made several years ago to seek more access for drilling wells in our core Wyoming properties and a contract for firm transportation capacity on a new interstate pipeline targeting Northeast markets with Rockies Gas both came to fruition with the Pinedale record decision finalized later in the year and with Rockies Express pipeline commencing limited operation early in the year. Neither contributed to our success in 2008 but will create significant value in time.

Our finding and development costs and our depletion rate are both less than $1.40 per Mcfe. And we plan to keep both there. We took no ceiling test write-off or impairment charge and have one of the cleanest balance sheets in the business. In fact, we have only $55 million on the balance sheet that is not being depleted or depreciated.

We significantly increased the productivity of our rig fleet by using technology and experience to reduce our drilling days per well, which reduced our well costs 11% in a period characterized by increasing material and service costs.

We maintain our focus on total costs and again are the low cost producer. This is a competitive advantage that allows us to make money throughout the price cycle. We borrowed long-term money seven and ten year early in the year at essentially investment grade rates. Our third party, engineered and economic resource base at approximately 12 trillion cubic feet equivalent is staggering in its enormity for a company our size. If resource capture is the name of the game, then we have a winning hand. Many of the companies significantly larger in market value than Ultra lack the low-risk, low-cost, consistent, repeatable domestic legacy asset that grows in size and value each year.

Let me stop now and introduce Brad Johnson, who will share some comments on Ultra's reserves.

Brad Johnson

Thanks Mike. Oil and gas reserves are the most important asset of an E&P company. Ultra's reserve estimates were prepared by Netherland, Sewell and Associates, a third-party independent reserve consulting firm. This year marks the tenth consecutive year that Netherland Sewell estimated reserves from Ultra's domestic asset. The professionals at Netherland Sewell estimates reserves in Pinedale and Jonah Fields and doing so since 1996.

In the same manner as previous years, 2008 year-end reserve determinations, all wells and potential locations, both the Jonah and Pinedale fields. Also in the same manner as previous years, Ultra continues to limit its proved undeveloped reserves to only those direct offsets producing wells that can be drilled and completed within Ultra's three-year budget planning cycle. Direct offsets beyond the three-year cycle are booked as probable or possible.

Now for the results. Ultra's year-end 2008 proved reserves are 3.518 trillion cubic feet equivalent. This represents an 18% increase over year-end 2007. Proved developed reserves are 1.481 Tcfe, represent 42% of total proved reserves. Proved undeveloped reserves are 2.034 Tcfe. Corresponding future development costs of $2.271 billion, the development cost for these PUDs, $1.12 per Mcfe.

In 2008, Ultra posted another year of outstanding reserve growth. Reserve replacement was all organic growth and totaled 470%. Finding and development costs were $1.39 per Mcfe. Since 1999, Ultra's proved reserves have grown by 4700%

Year-end proved reserves for 2008 were determined with year-end pricing of $4.71 per Mcf of gas and $30.10 per barrel of oil, about a 23% decrease in year-end gas price from 2007, Ultra's proved reserves increased 18% year-over-year. The absence of a significant downward price revision at year-end 2008, another indicator of the high quality of Ultra's proved reserves. The year-end gas price of $4.71 per Mcf, pre-tax PV-10 value of Ultra's proved reserves $4.44 billion.

Now, let's discuss Ultra's economic 3P reserves, proved, plus probable, plus possible, also determined by its third-party engineering consulting firm, Netherland Sewell. Ultra's 3P reserves are 11.66 Tcf equivalent at year-end 2008. Additional 1 Tcfe was added to 3P reserves this year, representing a 9% increase from 2007. At a $6 gas price, pretax PV-10 value for 3P reserves $11.1 billion, a discount rate of 8%, this value is $13.5 billion.

An additional price sensitivity run was made on Ultra's 3P reserves at $7 gas. In this run, the pretax PV-10 totals $14.4 billion, at a discount rate of 8%, this value increases to $17.5 billion.

It is important to note the distinction of Ultra's probable and possible reserves. In addition to the fact that they are determined by Netherland Sewell, as mentioned earlier, all of these locations are within a seismically defined fairway of the field and are economic at a $6 gas price. Probable reserves totaled 5.9 Tcfe. Adding these probable reserves to the proved reserves yields a current 2P reserve total of 9.42 Tcf equivalent.

Of the nearly 6 Tcf equivalent reserves currently classified as probable, approximately 1.4 Tcf equivalent are considered technical PUDs. Technical PUDs are defined by Ultra as locations that meet all criteria for PUD designation with the exception that they are scheduled beyond Ultra's three-year planning and budgeting cycle. As a result, they are reported as probable.

The remaining 4.5 Tcf equivalent probable reserves include over 3,300 locations. Many of these probable locations are near PUD with an average EUR greater than 3.5 Bcf equivalent. New SEC rules expected to be in effect at year-end 2009 will allow many of these reserves to compete with Ultra's PUD pool capital, the capital level that Ultra currently limits three-year budget plan.

Possible reserves total 2.24 Tcf equivalent. In 2008, 570 future locations were added to the possible reserve category, primarily due to the successful delineation program in 2008 on the east.

It's important to note that the possible reserves do not include any deep potential in Pinedale nor do they extend beyond the estimated limits of the field. Adding these possible reserves to the 2P reserves yields a current 3P reserve total of 11.6. At year-end 2007, Ultra had a total of 5,300 future wells in Pinedale and Jonah. In 2008, Ultra participated in 307 wells, added an additional 570 locations, ended the year with (inaudible) well inventory of 5,570. The new inventory added in 2008 represents an 11% growth in 2007 total.

Pinedale's petrophysical model and original gas in place volumes have been updated with 2008 data. At year-end 2008, the original gas in place totals 58.7 Tcf, representing an 11% increase from 2007. Much of this increase is attributable to the successful delineation drilling on the eastern side of the field. 3P reserves totaling 11.66 Tcf equivalent. Ultra's 3P reserves equates to a field wide recovery of 65%.

In summary, Ultra delivered another outstanding year of reserve growth with proved reserves increasing 18%. All organic reserve replacement of 470%, an industry superior, all in F&D cost of $1.39 per Mcf equivalent. Vessel delineation continued to extend the field.

Reduced well and operating costs at year-end enhance the value of all reserves as well as further reducing the risk profile among the probable and possible reserves. Ultra's third-party engineered economic 3P reserve base currently exceeds 11.6 Tcf equivalent. With continued delineation and development activity, coupled with continuous improvement to an already low-cost structure, we expect 3P reserves to increase in.

Now, I would like to pass the mike to Mark for a financial update.

Mark Smith

Thanks, Brad. Looking at full year 2008, we registered record production volumes of 145.3 Bcfe, revenues increasing to a record $1.1 billion. Operating cash flow increased to a record $825.3 million, up 85% year-over-year for an operating cash flow margin of 75%. Adjusting for non-cash gain on unrealized mark-to-market change on our commodity derivatives, net income for the year was a record $405 million or an adjusted $2.59 per diluted share, registering an adjusted net income margin of 37%.

In terms of returns for the year, our return on equity was 42% and return on average capital employed was 29%. 2008 net cash provided by operating activities amounted to $840.8 million. Cash used in investing activities totaling $915.3 million as these investment activities were largely comprised of $949.6 million in oil and gas related capital expenditures, offset by $32.1 million in increased payables associated with prior period CapEx.

Over the year, net cash provided by financing activities was $78 million, primarily consisting of $300 million in proceeds from the issuance of notes, together with $78.8 million of tax benefits associated with stock-based compensation and $19.1 million in proceeds from stock option exercises, offset by $298.3 million related to our share repurchase.

Looking at our balance sheet as of year end 2008, it remains strong with $16.9 million of cash and cash equivalents on hand and $570 million in long-term debt, providing $230 million in unused availability on our senior bank facility. To further enhance our financial flexibility, we've recently circled a $235 million private placement of seven and ten year notes with institutional investors, seven year notes carry a coupon of 7.31%; the ten year notes are priced at a coupon of 7.77%.

The offering is subject only to satisfactory legal due diligence and documentation. Closing is scheduled for early March with proceeds to repay our senior bank facility. We believe our liquidity remains more than adequate to fund our $720 million of proved 2009 capital budget use of our cash from operations, coupled with our senior credit facility.

Moving to the fourth quarter, production volumes increased 21% year-over-year to 40.6 Bcfe. Realized natural gas prices, including realized gains and losses on our commodity derivatives, registered $5.39 per Mcf. This amounts to a 22% increase over prior-year levels. The increase in realized price, combined with increased production levels, lead to revenues registering $207.4 million for the period, a 28% year-over-year increase.

As Brad stated, we remain focused on our cost structure. By cost pressures through 2008, our corporate lease operating expenses for the quarter were flat to prior year levels at $1.00 per Mcfe. Transportation expense associated with REX amounted to $0.32 per Mcfe on total produced volumes and our corporate DD&A rate for the quarter increased slightly year-over-year to $1.33.

General and administrative expenses registered $0.10 per Mcfe for the quarter. Interest costs were essentially flat on a unit basis at $0.15 per Mcfe. The net effect of these factors was an increase in year-over-year overall corporate costs of $2.91 per Mcfe, largely REX transportation costs I cited. Our field level cash costs were relatively flat at $0.48 per Mcf.

Our operating cash flow registered $159.4 million for the quarter, providing us 71% of operating cash flow margin. Adjusted net income for the quarter was $66.1 million or $0.43 per diluted share, an average gas price of $5.39 per Mcf for the quarter registered in an adjusted net income margin of 30%.

Looking at pricing, natural gas prices around much of the country weakened in January and remain soft. First of the month index prices Opal were $4.43 per MMBtu in January, moved into February Opal 16:46 pricing is roughly $3.03 per MMBtu.

In terms of basis, fourth quarter basis differential average roughly $3.42. Move through February, basis is running roughly $1.32 Opal to Henry Hub. Given the current supply situation, these differentials aren't isolated. Now for currently midcontinent sale points are running roughly $1.27 off of Henry Hub, $1.08 at Waha and roughly $0.85 at Carthage. One moves to eastern sale points, Chicago is running roughly flat to Henry Hub with Dominion South at roughly a $0.30 premium.

Looking at our hedge position for calendar 2009, generally we have full-year positions in place, 95 MMcf per day at $6.06 per Mcf. In addition, for the months of April through October 2009, we have an incremental layer of 248 million per day hedge that $5.91 per Mcf. On an aggregate basis, we have positions on 93 Bcf at a weighted average price of $5.81 per Mcf. I would refer you to our press release for the details hedge positions by quarter. For calendar 2010, we have $46 million per day hedged at $5.31 Mcf.

In terms of guidance, we currently expect our total production for 2009 to be approximately 172 Bcfe to 177 Bcfe. The first quarter of 2009, we are establishing guidance in the range of 40 Bcfe to 41 Bcfe. In Wyoming, lease operating expenses are expected to run $0.25 per Mcfe and gathering at $0.27.

We currently expect our DD&A rate to run roughly $1.36 per Mcfe. Corporately, we see G&A costs at approximately $0.15 per Mcfe for the year. As we move through 2009 and REX East becomes fully operational, we will begin incurring additional REX demand charges related to our firm capacity as anchor shipper. These will ramp up beginning roughly in May through the interim service period to roughly $1.07 per Mcfe with full capacity on REX East. Again, this is on our share, which amounts to 200 million cubic feet.

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

Bill Picquet

Thanks, Mark. In Wyoming in the fourth quarter of 2008, Ultra brought on stream 64 gross, 30.5 net new producing wells. The average initial 24-hour sales rate for these (inaudible) was 8.1 million cubic feet per day. Ultra's operated Pinedale wells averaged 11.2 million cubic feet per day, while the non-operated wells averaged 5.3 million cubic feet per day.

For the full year 2008, Ultra initiated production from 245 gross, 122.4 net new wells. The average initial 24-hour sales rate for the full year for all new producers was 7.7 million cubic feet per day. Ultra's operated Pinedale wells averaged 8.5 million cubic feet per day while the non-operated wells averaged 6.8 million cubic feet per day. The high for the year was from the Ultra operated Riverside 3B-13D, which flowed at 17.6 million cubic feet per day. At year end 2008, there were 14 Ultra operated rigs drilling in Pinedale and a total of 11 non-operated rigs also active on Ultra interest lands.

Our drilling and completion operations continued to improve significantly during 2008. Our full-year statistics once again demonstrate substantial reductions in both time to drill and cost to drill and complete. Operational highlights include an average of 24 days spud to TD for Ultra operated wells for the full year, a 36% improvement compared to our 2007 average of 35 days.

Ultra drilled and cased 41 wells during the fourth quarter of 2008 in a total of 156 for the full year, an 81% increase compared year-to-year versus the 86 drilled full-year in 2007. Ultra drilled 84% of our operated wells in under 30 days, spud to TD during 2008.

Our overall drilling performance continues to improve. Our skid rigs drilling on pads continue to set the pace for drill times and cost. For example, in December, our pad wells averaged 20 days spud to TD. For the full year, our pad rigs averaged $3.5 million to drill and case and our total cost to drill, complete and equip a Pinedale pad well averaged $5.5 million during 2008.

We are continuing to improve our performance throughout our operations as we build on our experience applying the key elements of our success under balanced drilling, leading edge bit technology, rotary steerable tools for directional control, and aggressive pursuit of other emerging technologies that are providing the future potential for continued efficiency gains. As a result, we are confident that we will continue to see reductions in drill times and costs.

Year round access will add to our efficiency with fewer rig moves, reduced location cost, the benefits of continuous drilling operations on a single pad location with the same rig and the same crews and additional operational synergies that will be derived from closer proximity of operations in concentrated development areas.

Although cost of services increased during 2008, our ability to drill faster more efficiently more than offset these increases. We are now seeing reductions in the cost of services and materials. We expect this trend to continue as many of our service providers are aggressively reducing their prices. We are seeing reductions ranging from 10% to almost 40% depending upon the service. Our completion costs also decreased significantly during 2008, averaging less than $1.8 million per well for the full year versus our 2007 average of $2.1 million per well.

In 2008, we averaged a little over 23 frac stages per well. Overall, our completion efficiency and associated cost performance for the full year 2008 improved to an average of less than $77,000 per frac stage versus just over $100,000 per stage during 2007.

We pumped almost 3,000 stages in 2008 versus almost 1,800 stages in 2007. Our efficiency gains and completions are even more impressive when considering that they were achieved in an environment where cost of services was increasing throughout 2008. In 2009, we are continuing this relentless pursuit of efficiencies and cost reductions throughout our operations.

With that, let me hand things over to Sally.

Sally Zinke

Thanks, Bill. Reviewing our delineation drilling for 2008 with a total of 31 delineation wells drilled during the year, our 2008 program provided field expansion and reserve increases within the existing field boundaries. At the end of 2008, 18 of these wells had sufficient production increase for Netherland Sewell and Associates, our third-party reserve consultants, to provide year-end reserve estimates. For 2008 delineation wells, there was a 42% increase in reserves for these wells compared to pre-drilled Netherland Sewell reserve estimates for those locations.

But more importantly, many of these locations are at the edge of the defined field boundary and provided significant expansion of the field itself. 2008 delineation wells had an average post-drill EUR estimate of over 7.3 Bcf and an average IP rate of over 11.7 million cubic feet of gas per day. Delineation drilling remains important to our confirmation of the true size of the Pinedale field with our current estimates of original gas in place for Pinedale now at 58.7 Tcf and the increase in the estimate of recoverable natural gas reserves and production net to Ultra increasing each year. Thus far in 2009, we have completed six delineation wells with post drill results at 100% increase over pre-drill estimates. We plan to complete a total of at least 16 delineation wells in Pinedale in 2009.

Now, moving to increased density drilling. As a reminder, in the fall of 2008, Ultra received approval from the Wyoming Oil and Gas Conservation Commission for five acre well density in four Ultra operated 160-acre pilot areas in the Southern Mesa and Northern Riverside areas of field to facilitate our ongoing assessment of the well density needed to fully best develop the Pinedale field.

Earlier this month, we applied for and received approval for two additional 160-acre pilot areas in the same portion of the field to allow drilling pad areas to be occupied through this winter drilling season in compliance with the year round drilling program under the SCIS [ph].

The low-quality pay or LQ portion of the land pool is one of our ongoing reserve and production addition programs, in this case from portions of the lands considered to be below current Netherland Sewell's pay cut off. In the fourth quarter of 2008, Ultra completed LQ stages in 80% of all wells completed. By the end of 2008, a total of 103 wells had been completed with over 300 added stages.

With reserve additions of 100 million cubic feet of gas to 115 million cubic feet of gas per stage and frac stage costs dropping to an average of $76,000 per stage based on increased efficiency, the F&D costs of these reserves is less than $0.65 an Mcf. We mentioned last time that we were commencing another reserve addition program to add frac stages above the conventional over-pressured Lance interval. By year end 2008, Ultra had completed 79 stages in 40 wells in normally pressured Lance sands.

Production log data from a total of 129 non-operated wells in this portion of the section indicates an average production contribution of almost 100 million cubic feet of gas per day, per stage, again at completion costs 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 recompletion opportunity in all existing Ultra-operated wells on the Pinedale Anticline. The estimated addition is an average 200 million cubic feet of reserves per well from the normally pressured section.

Now, looking at Ultra's 2008 activities in Pennsylvania. In Pennsylvania, Ultra drilled or participated in a total of 12 vertical exploratory Marcellus tests at an average total completed well cost of $1.3 million. We've had very encouraging results from these vertical wells and are waiting on pipeline connection for them.

The results have prompted us to move forward to drill a series of four horizontal Marcellus tests beginning in late first quarter. These tests are proximal to pipeline taps owned in conjunction with partners. And we expect to put these four wells on production at the time of completion. Typical horizontal Marcellus wells in the surrounding area are reported to be producing at a range of 1.3 million cubic feet of gas to 4.5 million cubic feet of gas per day. That is 5 times to 10 times the production of vertical wells at approximately 2.5 times the total well cost. These early 2009 horizontal assessments of the Marcellus shale will set the stage for additional horizontal development projects in the area.

Additionally, a total of six Oriskany sandstone tests operated by East Resources with Ultra 50% working interest were drilled in 2008 with total average completed well costs of $1.3 million. Two of the 2008 Oriskany tests are waiting on completion, and one has been duly completed in the Oriskany and Marcellus that is waiting on pipeline connection. Three other Oriskany wells are in the Texas Creek 3-D seismic area where we have identified a series of Oriskany structural prospects. Based on pressure testing, these wells appear to be capable of making over 5 million cubic feet of gas per day despite a significant skin damage.

Additional pressure test analysis is ongoing to determine the size of this Oriskany field. Typical reserves for Oriskany wells of this type are at least 4 Bcf per well We have just TD-ed a fourth Oriskany well in 2009 to help test the fields limits We currently have one Oriskany exploratory test drilling and two additional Oriskany exploratory wells scheduled for the first half of 2009.

Over year-end 2008, Ultra acquired 30 square miles of 3-D seismic in the Marshlands area of Pennsylvania. We expect to have final process data in-house around the end of the first quarter to continue our assessment of Marcellus, Oriskany and other potential in that area. Our total leasehold in Pennsylvania is approximately 327,000 gross, 172,000 net acres. Back to you, Mike.

Mike Watford

Thanks, Sally. So, on every measure except stock price, 2008 was an exceptional year for Ultra. Now for 2009. In 2009, we are pursuing a conservative and disciplined capital program that is in keeping with our long-term strategy of balancing growth and profitability. As telegraphed over the last few months, we are reducing our capital budget 24% while maintaining a 20% production growth target in 2009. It's probably the first time this combination of events has happened in our industry, where a significant budget cut is met with a production growth target well above the industry average.

Ultra's legacy Wyoming assets warrant growth and reinvestment throughout the cycle. We own long-term assets with long-term commodity price assumptions – and long-term commodity price assumptions drive value, not near-term commodity price moves. At this time, over 50% of our forecast 2009 production is hedged at a realized price of $5.81 per Mcf, which provides comfort that we can execute our 2009 plan without stressing our balance sheet.

To that end, we are adding additional liquidity, as Mark mentioned. Another $235 million of long-term debt priced at levels well beneath many of our peer companies' recent experiences. This is another indication of the lower-risk, greater certainty that market participants place on Ultra. We operate more cheaply, our F&D costs are lower, and we borrow at lower rates so our low-cost advantage continues.

One area that admittedly has not worked for us yet is improved natural gas pricing through REX. Since we are stuck delivering gas to a handful of midcontinent field interconnects with REX West, as opposed to the 20 market area pipeline interconnects with REX East, we are not receiving any uplift in gas prices. But that is about to change as early as April. Even with price convergence due to new supplies entering the market, we believe that the price uplift we will enjoy on our REX volumes will more than offset the transportation fee, thereby enhancing our cash flows. The Company's foundation, our economic resource, our reserves continue to grow almost 12 Tcfe worth $11 billion with development over 20 years. The scale of our resource exceeds all but a handful of the large independent E&P companies.

Lastly, a personal note indicating my confidence in the Company's ability to create value going forward. I own more Ultra Petroleum stock at year end 2008, not less. So if it's possible, my interests are even more aligned with shareholders'. Now I would like to take some questions.

Question-and-Answer Session

Operator

(Operator instructions) And your first question is from the line of David Heikkinen with Tudor Pickering Holt. Please proceed.

David Heikkinen – Tudor Pickering Holt

Good morning. Just first question, after tax PV-10, is that each of the sensitivities provided?

Mike Watford

Not currently, but it will be in our 10-K for the proved reserve case.

David Heikkinen – Tudor Pickering Holt

We won't count that as a question then. Extensions and revisions, will you give that as well or will that come with 10-K?

Mike Watford

It will come with 10-K, but Brad could provide it to you now, if you'd like.

David Heikkinen – Tudor Pickering Holt

Okay.

Brad Johnson

Yes, we had price revisions of 0.5% at year-end 2008. I might add that those all impacted the tail-end reserves and that had no PV impact. Additionally, none of those price revisions impacted our PUD reserves. Additionally, we had about 1% revisions on existing PDP wells, again associated primarily with tail-end reserves. The remaining balance of those revisions are attributable to transfers of locations within the proved category and also associated with the redistribution of reserves associated with assigning reserves to an increasing resource base and an increased density program.

Mike Watford

So we are just swapping out probables for PUDs.

David Heikkinen – Tudor Pickering Holt

And as you think about 2009, kind of looking at what you're doing in Pennsylvania, what you're doing in Wyoming, what are your thoughts about any productivity out of Pennsylvania in the guidance, or is it mainly driven by Wyoming?

Mike Watford

We tend to be – our spots are the same each and every day. We are very conservative. So we are confident we can hit the 20% production growth target with the Wyoming property alone in fact. Our style is to under promise and over deliver, so that's baked into the 2009 numbers as well. We have no production in those numbers from Pennsylvania. We know we have successful Oriskany wells. We think we are on the verge of having successful horizontal Marcellus wells. We know there's some infrastructure issues we have to get past We are uncertain of the timing. So we have nothing in there for Pennsylvania, which is, again, very, very conservative.

David Heikkinen – Tudor Pickering Holt

Okay, that was my two questions. Thanks.

Mike Watford

Thank you.

Operator

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

David Tameron – Wachovia

Hi, good morning. Congrats on a great year.

Mike Watford

Thank you.

David Tameron – Wachovia

One of my competitors put out a note this morning I will just get right to it that talked about your 2010 growth and that given your guidance that you put out for '09 and the decline in the fourth quarter of '09 versus third quarter, that you could be looking at flat production growth for 2010. Do you care to comment on that?

Mike Watford

Sure, yes, David, perhaps we made a mistake by not masking the third quarter to fourth quarter production forecast. We certainly had that conversation internally as to whether we should – it's easy enough to move a B from third quarter to fourth quarter, that's not a problem, and then they would be flat, but we said no, this is the way the profile looks currently. Our capital program is front-end loaded in Wyoming; there's no doubt about that. I think Bill said – he may not have said but we are about 12 operated rigs up there now and our partners have, I guess Questar nine and Shell, six, in those roughly numbers. He will correct me in a second, hopefully. But we are bringing our rig count down over the course of the year to seven. And that's our plans currently. We have no plans in 2010 other than to have those seven rigs going in 2010 on an operated basis. We don't know what our partners are going to do, so we haven't provided any 2010 guidance yet.

But as we say, we are not going to assume any production increase for Pennsylvania activity and we're going to limit it to the deep declining rig count and CapEx in Wyoming, then it make sense that you're going to bring down production profile over the course of the year. Whether we have one B a day, I mean one B or more for the quarter in third quarter or fourth quarter, we will just see what happens with scheduling and completion. But I think it fits with what's going on. I'm surprised that most other companies don't have similar profiles or perhaps they are just not providing quarterly data that make it apparent. But if you're going to slow CapEx and if you are front-end loaded in the year, it makes sense that, as you go through the year, that your quarterly production is going to decrease. We are not making any comments about 2010. I mean, we've done preliminary estimates at minimal capital well below $700 million a year that provide us with flat production.

So it's just a question of what we plan to do in 2010 and that's going to be predicated on gas prices. We have a hard time selling a lot of gas for $3.00. We are probably the only company out there that actually makes money at $3.00. I mean, we have our net income of $3.00, positive cash flow at $3.00. We have return on our investment in our PUD wells we are going to drill at $3.00. Again, I don't think anyone else can do that. It defies logic to me that you go out and borrow $600 million at 12%, 13% interest rate, invest it in a shale play where you are selling your gas at $3.50, making no money this year at all. Clearly, you are trying to prove up acreage longer term, net asset value, but you make not a cent and you still got that debt of 12%, 13% going forward. We're just not going to play that game. We are only going to invest where we can make money. If that means we slow down for a bit, we slow down for a bit. But I don't think anyone should be alarmed at what 2010 production levels will be.

David Tameron – Wachovia

Okay. And follow-up, just talking about rigs, you had – I think I went back to last quarter you guys talked about you had 16 rigs. Of those, nine were up for renegotiation. You are now saying you're at 12. I believe all of those rigs are up for renegotiation in the first quarter. Can you talk about – and maybe you mentioned this and I just missed it, but can you talk about what rates you're seeing and of those 12 rigs, how many can be renegotiated?

Bill Picquet

This is Bill. We are at 12 rigs currently. We are going to be at seven by the end of Q1, so all of – at this point in time, all of our rig contracts for the future are set. And as far as future prices are concerned, all of those rigs that we will have at the end of Q1 will be on longer-term contracts. Some of those were negotiated well back in 2008 and those are for new builds that will be arriving in the field later in the year that we will be swapping out. So we won't be renegotiating any future contracts during 2009.

David Tameron – Wachovia

Alright, thanks.

Operator

Your next question is from the line of Subash Chandra with Jefferies. Please proceed.

Subash Chandra – Jefferies

Yes, let me start with a statement. I find it hard to believe that you guys would be penalized for possibly flat or lower 2010 volumes when the vast majority of companies have not been penalized for it. So if today's action is based on that, that would be incredibly shocking to me. Along that vein, where does your stock share buyback program stand? And what can you do and is there any plans to amend that program?

Mike Watford

Mark is thumbing through his notebook right now to get you the answers, Subash.

Subash Chandra – Jefferies

Okay. I guess while he is looking, the other question is that these efficiencies, but now I guess with most of your contract on your rigs not up for renegotiation, but maybe some of the other service costs and costs coming down, what's a reasonable expectation for per well costs heading through the year?

Bill Picquet

Subash, this is Bill again. We mentioned our average cost in 2008 was about $5.5 million for development wells, and we've seen that come down a little bit since that point in time. Today, they are around the $5.3 million plus or minus number. And we expect that to continue to go down as the year goes on, just primarily based upon efficiencies, but also based upon some of the service costs dropping. We are expecting our costs to get down to somewhere in the $5 million plus range by year end.

Subash Chandra – Jefferies

Okay.

Mark Smith

Subash, relative to your share repurchase question, in session to-date, we have repurchased 10.2 million shares at an aggregate cost of $592.9 million. As you recall, our initial authorization from the Board was for an aggregate share repurchase in the amount of $1 billion. We are going back in $250 million tranches. We received approval under our third $250 million tranche, and we've currently got approval in place up to $750 million if we chose to do so under an aggregate $1 billion approval.

Subash Chandra – Jefferies

Thank you.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you. Good morning. Can you talk about decline rates in the Pinedale Anticline from the initial production rates that you've given and as you've seen better initial production rates, has the declining profile changed at all in the Pinedale?

Mike Watford

We are trying to decide who is going to answer. I don't think they want me to.

Brad Johnson

I will be happy to answer. This is Brad. We are not seeing any material change to the decline rates as we are getting stronger IPs and stronger parts of the field, activities in better parts of the field, so we are not really seeing any material degradation, if you will, on decline curves.

Brian Singer – Goldman Sachs

Okay. And then secondly I guess, I appreciate all the color on the individual wells and the I guess year-end 2007 versus post-drill 2008 EUR. A question on them, if you look at their ratios, the initial production rates relative to the EUR, there's not that much consistency. I just wondered if there was a little bit more color on what's driving a 12.7 Bcf well out of 17, they are 15 million a day EUR versus a 3.3 Bcf well at an 11 million a day EUR – I'm sorry, 11 million a day IP.

Mike Watford

Isn't it nice that we provide all that data so that you can pick at us on that, Brian? It's wonderful, isn't it?

Brian Singer – Goldman Sachs

I'm just looking for the color. I'm sure there's a good answer.

Mike Watford

That's good. That's good question, good pickup.

Brad Johnson

I can answer that as well. Certainly, you can cross about those and develop a correlation, you will see some spread or scattered. And obviously, it's important to understand that IP rates are a good early indicator but ultimately it's how that well falls off in time. So we have a lot of data in Pinedale and confident in our IP EUR correlations. And moving forward, we will continue to monitor. But again, I would expect some scatter in that data, just working with tight gas in IP and EUR relationships.

Brian Singer – Goldman Sachs

And what are you assuming is your first tier decline right now or I guess the decline rate off of the 24-hour IP?

Mike Watford

I think it's still about the 65% range.

Sally Zinke

That's a good point.

Mike Watford

Was that first year decline rate, was that the question?

Brian Singer – Goldman Sachs

Yes.

Brad Johnson

These hyperbolic wells, they have instantaneous decline, very high in the hyperbolic forecast. But if you look at a field wide curve, our field wide first year decline is in the 20% to 25% range and then that falls off to a base asset decline of 7% over time.

Brian Singer – Goldman Sachs

Great, thank you.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning. Couple of questions, talking about the 5-acre spacing at Pinedale, just wanted to make sure. Have you guys actually drilled any yet of those first four you were planning – those first 468 acre sections that you were planning?

Sally Zinke

Yes, we are drilling those five-acre pilot areas as a course of our continuing development in what is VA2 under our SCIS, so we currently have rigs on several of those pad areas that are drilling the five acres as they are drilling (inaudible) the 160.

Noel Parks – Ladenburg Thalmann

Okay. And as far as being able to look at the production that you've gotten from those so far, what's maybe the oldest or the first of those wells, like the longest timeframe you can look at so far?

Sally Zinke

Most of those are fairly recent. We do have five-acre pilots down in the southern part of the field that we have pressure data and that kind of information on, but this is kind of our first stab at the northern end. So it's early to have an understanding of the success of those five-acre pilots.

Noel Parks – Ladenburg Thalmann

Okay. And just if you could talk a little bit more about the Marcellus, and I just had two questions. Maybe you could get a little bit more into the specifics as you look out over the next couple of years in terms of the infrastructure needs in your particular area. And also, maybe just a little bit more about the Oriskany wells and also whether any of those first few had been completed yet.

Sally Zinke

We have completed the three new wells in the Texas Creek area as well as the dual completion I mentioned at the Marcellus Oriskany combination that's not in the Texas Creek area. Those wells are not currently connected to pipelines. There is not a pipeline connection close to Texas Creek. Relative to the rest of our Marcellus, I think we have a dozen vertical wells that are scattered across our lease holding. We've used that to kind of confirm what we think of the quality of the shale potential in the area. Now, as we move into horizontal, those locations are close to pipeline taps so that we can start producing and then (inaudible) from there with development as success indicates.

Noel Parks – Ladenburg Thalmann

Okay, great. Just my last question is a general one about the reserve booking. As you guys stick to the three year timeframe as far as allocation of capital in determining what you're going to book as PUD, I was just curious. As we move forward this year, looking into 2009, '10 and '11 compared to last year, just give us a sense of how the pricing and the activity levels might have affected it. Does the 2010 capital allocation look very different now from how it did a year ago when that was year three in the timeframe?

Mike Watford

Well, last year when we get the reserves, we assumed a flat CapEx for each of the year for the proved reserves category and I guess for the 3P as well. This year, in the analysis, it shows lower CapEx in 2009 and increase in '10, '11, slightly. It's just the way it's put together.

Noel Parks – Ladenburg Thalmann

Okay. And by how much roughly in 2010 and '11?

Mike Watford

I think it's about $100 million a year difference in the capital in 2010 and '11 versus 2009.

Noel Parks – Ladenburg Thalmann

Okay, great. Thanks.

Operator

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

Leo Mariani – RBC

Good morning. Looking for a little bit more color on your 2009 program on Appalachia. You guys were referencing roughly $60 million in CapEx on the drilling side in your press release here. You talked about four horizontal wells in the Marcellus in the short-term. What's your total Marcellus program for 2009?

Sally Zinke

I think that will vary a little bit depending on how much of it is operated and nonoperated in that $60 million. We currently are looking at least 13 horizontal Marcellus wells as part of that program.

Leo Mariani – RBC

Okay. What's your average interest in those? Are you like 50% wells here or –?

Sally Zinke

Well, it will depend. We still need to assess our 3-D in the Marshlands area, which would be 100% Ultra area, so there will be a mix of wells that are operated at 100% and wells that we participate in as a nonoperator at 50%.

Leo Mariani – RBC

Okay. I guess is the balance going to be some additional Oriskany drilling for '09 there in Appalachia?

Mike Watford

The whole $60 million isn't drilling. It says exploration and drilling. It's a little bit of a misnomer there. Part of that is for additional acreage there as well. So it's more about $32 million or $33 million worth of drilling in the remainder acreage. There's going to be Oriskany Wells as well as Marcellus wells. But go ahead, Sally. Sorry.

Sally Zinke

I think I've outlined for Oriskany wells early in the year and certainly if some of those additional structures in the Texas Creek are successful, you will see some follow up with those.

Leo Mariani – RBC

Okay. With respect to those 12 vertical wells that you talked about in the Marcellus, is it right that none of those are yet on production at this point or you have some of those producing? I guess have you tested the ones that you haven't produced?

Sally Zinke

I think we've had some 20 day and 30 day tests on a number of those wells, so we are pretty comfortable with some of our estimates, but currently none of them are connected to pipeline.

Leo Mariani – RBC

Okay. I just kind of wanted to clarify your comments, Mike, on fourth quarter production, just make sure I kind of understood everything in 2009. I know, in the past, in 2008, you guys had some pipeline downtime for some maintenance on REX. Obviously, you get some maintenance with some of the other takeaway outlets out there in the Rockies. Is that at all showing up in your 2009 guidance in terms of looking at third quarter and fourth quarter numbers?

Mike Watford

It would show up in the difference between what we think we can produce and what we put on this piece of paper, yes.

Leo Mariani – RBC

Could you guys quantify at all in terms of magnitude?

Mike Watford

No. It doesn’t help me to quantify that. Last year, we shut in 3Bs I think over the course of the year, a little over half a B in the fourth quarter, the remainder in the third quarter. I think, in 2007, we did much the same for different reasons, no pipeline issues, just pricing. I think you should assume that we have sufficient volume here, excess in our ability to produce to affect a shut into if we are unhappy with gas prices.

Leo Mariani – RBC

Right. Just to kind of clarify, you have some of that baked into the guidance, or no?

Mike Watford

I have more room with actual production capabilities beyond what this guidance presents so that I can shut in gas and still meet these numbers if that's what you're asking.

Leo Mariani – RBC

Okay. I think that does it for me. Thanks.

Operator

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

Mike Scialla – Thomas Weisel

Hi, guys. Want to know on 11.7 Tcf that Netherland Sewell has given now, what's the major difference between that and the 14 Tcf number? What do you need to do or prove to them to get them up to the 14 Ts?

Sally Zinke

I think a lot of that is in our low quality and our normally pressured Lance sands. We are not getting any credit currently for any of that. That's very achievable, put it that way.

Mike Scialla – Thomas Weisel

Okay, so that's not really in there, okay. And then Mike, on the last call, you said, in a tough environment, you either bury or buy your competitors. I guess, with the pullback in drilling, does that suggest you are looking at this opportunistically? Would you be maybe looking to buy more acreage in the Marcellus or how do you view that now?

Mike Watford

Well, I think Mr. Smith does a good job of maintaining our liquidity so that if we elect to try and do some sort of an acquisition that makes sense to us with our cost structure and our style, that we have the flexibility to do that whether that's a tight gas reservoir or a Marcellus shale reservoir; we will see. I don't know of the acreage of more likely companies, but I mean we want to maintain flexibility. Again, I just don't think it makes a lot of sense to plough extra funds into the development of the resource right now at these commodity prices. We control, in the primary asset, the 12 Tcfe asset in Wyoming, we control all of the acreage; not an issue. So we can take our time if we need to, slow down. We don't have to be in a hurry. We are not trying to save something that we've spent exorbitant sums for. (inaudible) different issue but it's just not significant to our role. (inaudible) anything but, but we are trying to position ourselves to be opportunistic if opportunity present themselves.

Mike Scialla – Thomas Weisel

One more if I could? Are you shutting in any production at this point?

Mike Watford

No, not that I know of, but sometimes these guys hide stuff from me.

Mike Scialla – Thomas Weisel

Thank you.

Mike Watford

Thank you.

Operator

Your next question is from the line of Ray Deacon with Pritchard Capital. Please proceed.

Ray Deacon – Pritchard Capital

Hey, Mike, I was wondering if – do you have a breakdown of what the average PUD was in the reserves at year-end? My recollection was it was 7B. Is that still about the case or –?

Mike Watford

I think Brad – it's closer to 6B this year.

Brad Johnson

That's correct. Average PUD is 6 Bcf similar to last year.

Ray Deacon – Pritchard Capital

Okay, it's similar to last year's, okay. I was just wondering. Do you think that trend in the fourth quarter of averaging 20 days – do you see the momentum with the rigs this year moving below that or are you going to try to maintain that or –?

Bill Picquet

This is Bill again. One stat that we didn't mentioned was during 2008, we had almost 30% of our wells that were below 20 days. If you looked at 2007, the number would've been about the same as far as 30 day wells are concerned. So, it's moving in the direction that more and more 20 days is viewed as a normal target for a well and we expect to go below that. As far as what's achievable, we mentioned a record well at 14.7. We do a process on every well that we drill called “drill the well on paper” that involves all the folks in our drilling team. If we looked at the today's technology in the optimum well, we think that an 11 day or a 12 day well is achievable. Are they all going to be perfect? Obviously, it takes a while to chip away at these hour by hour improvements. Our expectations are that our average is going to be at or below the 20 days.

Ray Deacon – Pritchard Capital

Got it, got it. I guess, Mike, if you could elaborate just a little on the point you made regarding the nature of the asset and sort of CapEx profile, I guess many people are thinking of the shale plays where you get a huge chunk of the reserves in the first 18 months, to say. I guess have you ever run sensitivities on the first couple of years if you get a low gas price, how big of an impact is that going to have on your returns relative to something like the Barnett or another kind of asset?

Mike Watford

Well, I'm not going to put Brad on the spot, his first conference call here. We have historically run, looked at over 18 months, what sort of percentage of total estimated production – estimated reserves in the well we're going to produce is that 18 months is 20% or 25% of the well. So you need to get most of your investment back, if not all of it, in the first 18 months in order to have strong economics. If you don't, you're not going to get payback. You're certainly not going to return. I think that's – so our view would be, right now, that it would be – it would not be the right answer for us to go out in an environment where current prices in Wyoming or whatever they are, $3.20, $3.30, wouldn't make sense, although we make money even I think four B Wells, that's 11% return, in 5Bs, it's more.

Going on up in our average costs certainly is about $5 of hedged volumes, which gives us 48%, 50% returns. But on an incremental basis, we wouldn't want to invest a lot of money in the $3.20 and $3.30 gas price environment right now just to do it. We would back away from it. So I don't understand why other people are. Well, I know why they are, because they have to – but if this low price environment continues for a little bit longer, then I don't know what they will do in 2010. But no, certainly, we get 20%, 25% of our estimated ultimate recoveries in the first 18 months, so it's key to have gas prices that give you positive returns early in the life of these wells or you might well wait to drill them.

Ray Deacon – Pritchard Capital

Got it, got it. What is the market telling you on a forward basis happens in April? I mean, are you able to lock in better than that 3? I guess what kind of prices if you were looking out a couple of years, could you lock in on REX or –?

Mark Smith

Looked at that last week and we were – you could lock in, I guess REX to (inaudible) when I looked at it last week, we're running a couple of bucks.

Mike Watford

Let me – this was the forward CALO 10 indications at February 11, 2009. So it's a week and a half or two ago. Where the Opal basis or the Opal price in it was $4.50, and a Chicago price was $6.36 and Michigan price of $6.54, and an Ohio price, which is where we are going to go with REX, was $6.70. So that's Mark's $2.00 difference, $6.70 or $4.50. That quite frankly is part of our problem in 2008, is that we committed for this REX capacity early. Their schedule three years ago had them completing themselves into the Ohio, eastern Ohio market by this time and they're delayed. Unfortunately for us it means we end up – we are stopped at a – the bus broke down on our trip and we are waylaid some place where we are having to sell gas for an extra year where we didn't really want to and we are facing the onslaught of additional shale gas too, which is driving it all down. But we are very confident that when we finally get REX completed, that we are going to more than cover the cost of our transport and then we will be cash flow positive on that and we will actually create value. And that will help lift the prices in the Rockies as well.

Ray Deacon – Pritchard Capital

Got it, great. Do you – Questar sounded like on their call, they weren't kind of totally dismissing this ozone issue as something that was addressed in the EIS. I guess are you concerned that it could slow things down at all from current levels or have additional costs or – ?

Bill Picquet

The ozone issues -– this is Bill, was a factor as far as the emissions requirements included in the record of decision on the SCIS. So we have actual targets for reducing NOX missions from rigs that transpire over the first 42 months after the record of decision. And those are very clearly spelled out. So the rules of the game are pretty well defined and we are well on our way toward achieving those as far as the first year is concerned and have a game plan in place that we will continue to meet those requirements as we go forward.

Ray Deacon – Pritchard Capital

Got it, great. Thanks.

Operator

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

Ron Mills – Johnson Rice

Good morning. Just a question on the low-quality pay, the normally pressured pay and the delineation. Obviously, that's been – particularly the delineation I think has been the driver in terms of an increase in original gas in place. As you look at your field, where are you in that delineation program? Do you think you're starting to find the limits of the field, or should I read into your comments that some of the stronger wells are still at what you thought were some of the field limits?

Sally Zinke

I think we still have some running room. I'm not so sure that there's a lot of delineation wells out on the eastern edge that are going to compare to the core of the field. But I think that we still have a fair amount of area on the eastern side that's currently undrilled.

Ron Mills – Johnson Rice

Okay. In the recovery factor I think you all mentioned earlier of 65%, do you all think that there are ways that that can continue to increase? I think, in Jonah, it approached 75% or 80% in particular areas. I'm just trying to get a sense as to where you think the recovery factor can go and what steps would be required to do that.

Brad Johnson

This is Brad. Every time we drill another well, we are increasing the recovery factor as we increase density down-space. We think that number, 65%, is a good number where we stand today. Obviously, as we continue to grow the resource, step out, we will be watching that and see how it changes. Every time we drill a well, we are increasing the recovery factor in Pinedale.

Ron Mills – Johnson Rice

Is the plan to go back into some of your older wells eventually and maybe try to frac into the low-quality or the normally pressured formations?

Bill Picquet

We could go into the older wells and do the normally-pressured. We can't go back to low-quality pay.

Ron Mills – Johnson Rice

Okay, and then two just housekeeping – one, on the note's offerings, it sounds like the $235 million in notes is an aggregate number, which will be broken up somehow between seven and ten-year notes. Is that correct?

Mark Smith

Yes, that's correct.

Ron Mills – Johnson Rice

Then the CapEx obviously is front-end loaded, Mike, as you mentioned. Do you all have a sense as to what your CapEx breaks down as you look at it on a quarterly basis?

Mike Watford

What we have – we just haven't put that out yet, Ron. I mean sort of the first half of the year is 60% of the CapEx, and the second half is 40%. Probably more important than that is that, in the first half of the year, more of the CapEx is Wyoming development drilling. The second half of the year is more of the Pennsylvania activity, and our liquids gathering system we're going to build in Wyoming and whatever pipelines gathering system we end up building in Pennsylvania.

Ron Mills – Johnson Rice

Which is obviously not just the absolute CapEx numbers, but that development versus infrastructure is also part of the impact for the fourth quarter, correct?

Mike Watford

That is correct, yes.

Ron Mills – Johnson Rice

Alright. Guys, thank you very much.

Mark Smith

Ron, in terms of helping you through your modeling, $62 million is the tranche of seven-year and $173 million is the tranche of ten-year.

Ron Mills – Johnson Rice

Great. Thank you very much.

Operator

Your next question is from the line of Andrew Gundlach, ASB. Please proceed.

Andrew Gundlach – ASB

Two follow-ons from earlier questions, you had mentioned that you had done a scenario planning where what the minimal capital would be to maintain flat conduction alluding to 2010. I'm just curious what that minimal capital number or range might look like, if you're willing to share that.

Mike Watford

No, I don't think I want to share that yet, but what I will say, if we stop spending money at year-end '09 and all we do is just spend enough money to finish drilling the wells we started in '09 and complete them in 2010, but we don't spend any money in 2010 and 2011, that over the two-year period of time we have, what, over 300 Bs of production? So for about $90 million of CapEx in 2010, we have 300 Bs of production in 2010/2011. So that gives you a sense that – I mean, it doesn't take a lot of capital to keep it flat, and it takes some capital to grow it, but we are well positioned. But we are not ready to give out and provide details to 2010 yet because we don't know what gas prices are.

Andrew Gundlach – ASB

I understand. I just want to get a sense of the capital declines, cash flow, etc., which leads in a way to the second question, also a follow-on from an earlier question about your share repurchase. I'm just kind of curious how you set the 720 for '09 versus share repurchase, and how in fact you think about share repurchase going into this with your long-lived asset and your long-term view and stewardship of the company.

Mike Watford

Well, I'd love to go buy it all right now at these prices, but Mr. Smith says he can't borrow that much money. So I'm looking for a new CFO if you've got some recommendations.

Andrew Gundlach – ASB

No, but seriously, how do you think – I mean, why 720 and not 600 and 124 for share repurchase, for example? Let's say you get into the 2010 scenario that you're talking about and that plan becomes reality. Obviously, there will be a lot of cash but there. I am just curious how you are thinking about it today, as best as you can tell.

Mike Watford

Well, we are trying to walk down from the $950 million in 2008, and not do it too abruptly. We also have some contractual obligations with rig companies and service companies that we are trying to honor and not walk away from, like others. We have an activity in Pennsylvania and an asset that we think could grow, grow nicely, that we need to put some cede capital in and see if we can't get it out of the ground and hopefully blossoming someday. So it's a mix of the two. We have some requirements to build a liquids gathering system for condensate and water handling in Wyoming as part of this additional access issue. So we have some items we have to take care of. So all of that kind of got rolled into the $700 million plus or minus CapEx, down 24% or so from 2008. We are just looking at liquidity and what's happening in the future with gas prices, and so it's hard for us to continue to borrow money to buy back stock. It's just reality. The debt we had at year-end 2008 is $570 million or thereabouts. If you look back over four years or five years, our cash flow and CapEx has, over time, been about equal and the difference is share repurchases over time. Right now, we are a little hesitant to borrow heavily to buy back debt, but I think your point is are we going to be smarter here over time to decrease CapEx and use cash flow to buy back equity? I think that's what I should be saying, not buy back debt, but buy back our stock. And that's something we are giving serious consideration to.

Andrew Gundlach – ASB

I understand. Just the last question on the point, how much flexibility is there in the $720 million if you would need to bring it back lower or if the stock would get to a price which you found irresistible?

Mike Watford

Well, all but maybe $20 million of the expenditure in Pennsylvania is all discretionary but then $20 million isn't because we've already spent it, but that's – and in Wyoming, there – I mean we can do a little bit less – can't do a whole lot less. So there's not – like I said, maybe there's $60 million, $70 million, $80 million in total but still somewhat discretionary at this point in time.

Andrew Gundlach – ASB

I understand. Thanks for the comments.

Operator

Our next question is from the line of Robert Christensen with Buckingham Research.

Robert Christensen – Buckingham Research

Yes, just a quick question, guys – how many wells were drilled in the Pinedale at the end of the year that are still awaiting completion?

Mike Watford

Well, Questar has a style where they spud all kind of wells early in the winter period and don't complete them to April or thereabouts, or May start. So, they alone annually have – gosh, I don't remember the number. I hate to give a number off the top of my head, but I don't know. Bill, is it –?

Bill Picquet

It's typically in the mid-30s to high 30s for Questar alone.

Mike Watford

Right. Those wouldn't be drilled all the way to TD yet, but they would have just been spud. That's the way they do their business, and go ahead, Bill.

Bill Picquet

I was just going to say Ultra has about 30 that we carried into 2009 that were drilled and waiting on completion. So a combination of the two would be 60-plus.

Robert Christensen – Buckingham Research

Okay, great.

Bill Picquet

Shell has a few as well.

Robert Christensen – Buckingham Research

That's it. Thanks a lot, guys.

Operator

(Operator instructions). Your next question is from the line of David Tameron with Wachovia.

David Tameron – Wachovia

A quick follow-up, you mentioned it don't have any production shut in, but are you dragging your feet and all in completions in the current pricing?

Mike Watford

Yes. I mean, we originally were going to add a second frac spread in the fourth quarter, and Questar kept it longer completing some of their wells. When it came to us, we decided not to keep it very long at all. There is just no reason to hurry to complete the wells. We are more efficient with one frac spread than we are with two, so we will just use the one and optimize our savings in terms of frac costs and just take another 60 days to 90 to get all of the wells completed.

David Tameron – Wachovia

Okay, yes. What has to trigger for you to bring that frac spread? Are you just waiting for better pricing? What's the trigger bringing the additional –?

Mike Watford

I mean, you could say that the better pricing would be the trigger. But I mean, we are going to be caught up by I think Bill says April or May anyway (inaudible) one frac spread. So I don't really think we have a trigger at this time, David.

David Tameron – Wachovia

Okay. Then one more question for you, Mark. What's the timing you said? You said they're going to be completed by when for the notes? Private placement?

Mark Smith

We are currently scheduled to close at the first part of March.

David Tameron – Wachovia

Okay. Alright. Thank you.

Operator

There are no further questions in queue at this time.

Mike Watford

Well, thanks. If anyone has follow-up questions or comments, I think everyone knows Kelly's e-mail or phone number. Thank you very much.

Operator

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the presentation. You may now disconnect. Have a great day.

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Source: Ultra Petroleum Corp. Q4 2008 Earnings Call Transcript
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