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Ultra Petroleum Corp. (NYSE:UPL)

Q3 2009 Earnings Call Transcript

October 30, 2009 11:00 am ET

Executives

Kelly Whitley – Manager, IR

Mike Watford – Chairman, President and CEO

Mark Smith – CFO

Bill Picquet – VP Operations, Rocky Mountains

Sally Zinke – Director, Exploration

Analysts

Brian Singer – Goldman Sachs

Joe Allman – J.P. Morgan

Noel Parks – Ladenburg Thalmann

David Heikkinen – Tudor, Pickering, Holt

David Timmon – Wachovia

Leo Mariani – RBC

Dan Guffey – Thomas Weisel Partners

Ron Mills – Johnson Rice

Operator

Good day, ladies and gentlemen, and welcome to the third quarter 2009 Ultra Petroleum Corp. earnings call. My name is Karisa and I will be your operator for today.

At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session. (Operator instructions)

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

Kelly Whitley

Thank you Karisa. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's third quarter 2009 earnings conference call.

On the call with me this morning to discuss our third quarter results and our continued strategy of profitable growth are Mike Watford, Chairman, President and Chief Executive Officer, Mark Smith, Chief Financial Officer, Bill Picquet, Vice President Operations and Sally Zinke, Director, Exploration.

Before turning the call over to Mike, I would like to cover a few administrative items. First, earlier this morning, we filed our 10-Q with the SEC. It will be available on the home page of our website or you can access it using the SEC's Edgar system.

In addition, this call will contain forward-looking statements that involve risk factors and uncertainties detailed in our SEC filings. Please refer to our 10-Q, regarding the selected financial information provided in this call.

Also this call may contain certain non-GAAP financial measures. Reconciliation to calculation schedules for the non-GAAP financial measures can be found on our website. Second, Ultra will be participating in several conferences over the next few week.

We will be at the Thomas Weisel Energy Conference in New York on November 10th, the Jefferies Energy Conference in New York on December 3rd, the Capital One Energy Conference in New Orleans on December 9th, and the Wells Fargo Energy Conference in New York also on December 9th. Please visit our website to view updated presentation.

Now let me turn over the call to Mike.

Mike Watford

Good morning and thanks for joining us for a discussion of Ultra Petroleum's third quarter 2009 results. First let me say that we are very pleased with today's results. In particular, given the environment.

We established a new quarterly production record of 45.9 Bcfe up 27% from a year-ago while at the same time decreasing our all-in cost by 22%, to $2.48 in Mcfe and our cash cost of $1.46 per Mcfe all remarkable.

Just a reminder, Ultra could practically double it’s per unit costs and the result would place the company at about the midpoint of any E&P analyst for Peer Group comparison. Being low cost is a competitive advantage that allows us to deliver exceptional financial returns throughout the business cycle. Due to that, we delivered a return on equity of 59%, a return on capital of 26%, along with a cash flow margin for the quarter of 71%, the net income margin of 35%.

We are profitably growing, not merely growing, which we think will differentiate us over time. Additionally on the financial side, our cash flow for the quarter exceeded our capital expenditures. Decreasing debt a bit, meeting our ample liquidity only improved.

Operationally, we've again noted in the release the initial production rates for Ultra operated wells placed on production in the Pinedale field in Wyoming during the third quarter. The average is approximately 10.4 million cubic feet per day, with an early reserve estimate of 6.4 Bcfe per well. And we achieved these exceptional results for about $5 million per well, land costs included. Other areas of the country I think they achieved several results for about twice that cost.

Our spud at TD is averaging 18 days with the best less than 14 days. Our Marcellus program is picking up the pace with 20 wells drilled and eight on production.

Another issue that we again want to highlight in the release is the changes in Rockies basis and how that impacts relative natural gas prices going forward. An easier way to say it is that the historical discount associated with Rockies natural gas prices is decreasing significantly. A simple Rockies only example, we’re at a $6 Henry Hub natural gas price and a 70% basis in the Rockies, we would receive a $4.20 realized price.

But at a 90% basis, we receive $5.40. An increase of $1.20, or almost 30% with no increase in Henry Hub pricing. With our cost structure almost all of that flows to the bottom line, improving our industry-leading returns and margins.

Now let me ask Mark to share his comments.

Mark Smith

Thanks Mike. And good morning. As you see from our press release, we had a very good quarter operationally, despite the continued reduction we've experienced in natural gas prices. We continue to see strong performance in the field with ongoing improvement in efficiencies, record production levels, and reduced costs. With REX-East, increasing takeaway capacity of the Rockies and reduced overall Rockies production, we're seeing improved pricing relative to Henry Hub.

Most importantly we continue to exhibit strong margins. Up sequentially from the second quarter. For the third quarter, our Wyoming production was up 27% on an annual basis and up 3% sequentially to a record 45.9 Bcfe.

Once again, our quarterly production registered the highest in the company's history and was due to our activity level in Wyoming, and our improved drilling efficiencies. And Bill will address this in detail.

Natural gas prices were down significantly over last year. However, they’re strengthened over the second quarter. More importantly, we've seen strengthening in the forward curve through 2011, and we're seeing the favorable effects of our hedging strategy.

Our average realized gas price for the third quarter was $5.13 per Mcf, 38% lower than our price a year-ago, but up sequentially from second quarter levels of $5.04. As a result of our increased production levels, offset by the decrease in realized commodity prices, revenues, including effects of our hedges, for the quarter registered $244.8 million.

Corporate lease operating expenses for the quarter decreased to $0.79 per Mcfe, compared to $1.34 for the same period in 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 our partners have worked to reduce their operating expense levels and our mix of operated wells has increase. This higher mix of operated production provides us with a larger proportion of increased production at our lower unit costs.

Transportation costs amounted to $16.3 million this quarter, or $0.35 per Mcfe, on our total production volumes, compared to $0.32 per Mcfe last year, as our transportation costs increased as REX began service in the 11 on Ohio on July 1st. Our DD&A rate registered a $1 per Mcfe in the quarter. General and administrative expenses on a unit basis were down compared to last year at $0.11 per Mcfe, while interest costs registered $0.21 per Mcfe.

The net effect of all of these factors was a $0.70 per Mcfe, or 22% year-over-year decrease in overall corporate costs, to $2.48 per Mcfe. But our continued focus on operational improvements and cost reductions, our cash field level costs decreased 2% on a unit basis over last year, to $0.46 per Mcfe.

Operating cash flow registered a $172.6 million for the quarter, providing a 71% cash flow margin. Adjusted for the non-cash unrealized losses associated with the mark-to-market position on our hedges, we recorded adjusted earnings of $85.8 million for the quarter, providing a 35% net income margin and $0.57 adjusted earnings per diluted share.

In terms of returns for the third quarter, on an annualized basis, our return on equity was 59%, and our return on average capital employed was 26%. Cash provided by operating activities during the quarter amounted to $180.4 million, investment activities for the quarter were largely comprised of $154.6 million in oil and gas property investments.

Over the quarter, net cash used in financing activities totaled $31.4 million. And consisted largely of $34 million in net repayments on our senior bank facility.

We ended the third quarter with approximately $13 million in cash on hand and $730 million in debt. We call our senior debt capacities just over $2 billion. We believe our liquidity allows us to fund far more than our $735 million in 2009 planned investment program, for the use of our cash flow from operations, combined with our revolving credit facility.

Considering our price outlook for the remainder of 2009, I want to draw your attention to the summary table of historical and forward basis differentials to Henry Hub that we provided on page four of this morning's press release. I addressed this last quarter. And given the significance, I want to review this once again.

Seen basis differentials improve from a low of 57% of Henry Hub in 2007, to currently roughly 97%. We currently are selling gas in Wyoming on a spot basis at $4.07, or 97% of Henry Hub at $4.20. This narrowing in Rockies basis has occurred while the Dominion South basis has improved from a low of 104% of Henry Hub to year-to-date levels of 107%.

Currently Dominion South is running just over a 104% of Henry Hub. We've seen increased capacity out of Rockies on first REX-East and ultimately Ruby, and we've also seen reduced drilling activity in the Rockies resulting in declining production levels in the region, while gas has become congested in other regions of the country.

As a result, we've seen a tightening in the market's view of basis going forward. When we take all of this into consideration, and focus on our overall corporate mix of production, we see our corporate basis going forward improving to approximately 94 to 96% of Henry Hub.

I want to address this in more detail for 2010, and build on Mike's commentary on Rockies discount. Given our firm transportation on REX and increased levels of production in Pennsylvania, we expect to be selling about half of our produced volumes in the northeast referenced to Dominion South.

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. It compares to a 2008 Rockies discount of 32%. This is a reduction of some 30% in corporate discount to Henry Hub. So what does this mean to Ultra? Assuming a $6. Henry Hub gas prices amounts to another $1.80 per Mcf, after severance taxes of $1.58.

On 175 Bcfe, that's our 2009 forecast volumes, not applying any growth assumptions for 2010, this amounts to an additional $277 million in cash flow. Very meaningful.

Again, this change in corporate discounts driven by one, the effects of REX on Rockies prices, two, our increasing production in the Northeast, and three, our firm transportation capacity on REX.

Now moving to hedging. As detailed on page four of our press release we currently have approximately 44% of our remaining 2009 forecast natural gas production hedged through fixed price swaps at a weighted average price of roughly $5.73 per Mcf. For calendar 2010, we have approximately 98 Bcf hedged and price of roughly $5.49 per Mcf. For calendar 2011, we have about 73 Bcf hedged and price of roughly $5.51 per Mcf.

I will wrap up my comments by pointing out that on page 5 of our press release; we provide detail on our outlook and guidance.

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

Bill Picquet

Thanks, Mark. In Wyoming, in the third quarter, Ultra brought on stream 67 gross, 30 net new producing wells. Year-to-date through the first nine months of 2009, Ultra has brought online 180 [ph] gross, 87 net new wells.

Average initial 24-hour sales rate for these new producers was 8.5 million cubic feet per day. Ultra's operated Pinedale wells averaged 10. 4 million cubic feet per day, while the non-operated wells averaged 6.9 million cubic feet per day.

The high for the quarter was from the Ultra operated riverside 161-3D [ph], floated 14.6 million cubic feet per day. At the end of the third quarter, there were seven Ultra operated rigs drilling in Pinedale, five non-operated rigs also working on Ultra interest land, for a total of 12 rigs active in Wyoming. Ultra operated wells drilled during the third quarter averaged 6.4 billion cubic feet equivalent.

Our average reserve size per well continues to be significantly better during 2009, as compared to 2008, due to year-round access allowing us to focus our activities in better parts of the field. During Q3, essentially all of our operated drilling and completion activity in Pinedale has been in the more prolific Riverside and Mesa areas of the field. Going forward, for the next decade, most wells in our Wyoming program will be drilled in those areas.

Our operating efficiency in Pinedale continues to improve. In the third quarter, we averaged 18 days, spud to TD, for Ultra operated wells, a 25% improvement over the average for Q3, 2008. During the third quarter, our average rig release to rig release was 23.3 days, down over 28% from our Q3, 2008 average of 32.6 days. 84% of Q3 wells were drilled in less than 20 days, spud to TD. Our average cost was $5 million per well.

We continue to improve our performance as we enjoy the benefits of year-round access, allowing us to drill a very high percentage of pad wells using skid-capable rigs, resulting in significantly fewer rig moves. Our state of the industry rig fleet and continuity of rig personnel is producing ongoing efficiency gains that exceed expectations. We're continuing to find new ways to trim time and cost.

During Q3, our average cost was $5 million, reaching our year-end 2009 goal, earlier than expected. Our costs continued to improve. Currently, we're averaging less than $5 million per well in early Q4. For anyone who may think we have no more room for efficiency gains, we will share some additional more recent news. In our earlier calls, we have discussed the fact that our target for the perfect Pinedale well was 12 days spud to TD. Late last week, we redefined perfect when we drilled a new record well in 11 days. Yes, that was 11 days.

This clearly demonstrates the limits of technology, rig performance and personnel performance as being redefined for the project. In the future, we certainly expect technology to continue to improve. We will have to see where we can go with the definition of perfect, but we're excited about the challenge and the potential for further advances. I got a page stuck together here.

Ultra's completion activity also continues to benefit from efficiency gains, and service cost reductions. Year-to-date through Q3 we have pumped a total of 2195 frac stages, averaging almost 25 stages per well, compared to just over 2900 total stages and 22.7 stages per well during the full year in 2008. We averaged $73,000 per stage for 2009 year-to-date, compared to $78,000 per stage in 2008. We expect to continue improvements in our completion performance, our current costs per stage is averaging $65,000. We're benefiting from the continuity of equipment and personnel in our frac operations.

Overall, in Wyoming, we are drilling deeper, increasing the number of frac stages per well, and still reducing our costs. Our improving operating performance is primarily the product of efficiency gains, and the ability to effectively assess and apply new technologies.

With that, I will turn things over to Sally.

Sally Zinke

Thanks, Bill. We ended last quarter with a total of 16 delineation wells drilled for the year in Pinedale. With longer well performance history, this group of wells has now exceeded pre-drill reserve estimates from Netherland Sewell by 33% as compared to 25% reported at the end of Q2. East side of War Bonnet continues to be an expansion area with an example in the War Bonnet 5D-113 delineation well which IP-ed for over 12.4 million cubic feet per day and has an estimated EUR of 13.4 Bcf, versus the pre-drill estimate from Netherland Sewell zero.

So our estimate of recoverable reserves net to Ultra in Pinedale continues to grow with expansion of the defined areas of the field and reserve growth within the field.

Let's now look at Ultra's Pennsylvania exploration, where based on encouraging horizontal well successes earlier this year, our activity level has escalated. There are currently three rigs running on Ultra interest lands in Pennsylvania. One operated and two non-operated. In the third quarter, we drilled a total of 12 horizontal wells in our five county focus area in north central Pennsylvania. Those are Potter, Tioga, Bradford, Lycoming, and Sullivan counties.

This brings our count of horizontal wells for 2009 year-to-date to 20. 12 of these wells have been completed and eight are currently online. We indicated last quarter that previously drilled vertical Marcellus wells would be connected as the 2009 horizontal program moved to those pad areas. We have put two of those vertical Marcellus wells on production for a total of 10 Marcellus wells currently producing. The seven horizontal wells brought online during Q3 2009 at IPs averaging 6.4 million cubic feet per day with the best well IPing at 10.46 million cubic feet per day.

The average calculated 30-day production rate for these wells is in excess of 4 million cubic feet of gas per day, with the highest average 30-day rate at 7.86 million cubic feet per day. Currently, net production in Pennsylvania as of October 29, 2009, is 1.72 Bcf, and we anticipate a year-end exit rate of 30 million cubic feet per day, net to Ultra, in Pennsylvania.

We are using a type curve for our Marcellus model that uses an expected EUR per well of 3.75 Bcfe. Early performance, even with some surface constraints, has definitely exceeded this. Our leasehold in Pennsylvania is approximately 172,000 net acres. And I would like to remind you that we began our horizontal Marcellus exploration program earlier this year with our first horizontal well PD in May of 2009. As we discussed last quarter, our acreage covers an area 40 miles wide, and 30 miles north to south, and it is primarily contiguous leases, which will allow us to form producing units and execute on a horizontal development program.

Our horizontal exploration drilling to date has successfully assessed nearly this entire area, with a few vertical tests providing confirmation beyond the area of horizontal drilling. We believe that our activity to date has broadly evaluated our acreage position and derisked our holdings. In addition, our four pipeline taps will allow us to put in place the ability to deliver on a development program.

In assessing the resource potential of our approximately 170,000 net acres as we conservatively estimate that 70% of the acreage will fall into drilling units, we have roughly 1200 net locations at 100-acre space. If we also conservatively estimate potential EUR per well at 3.75 Bcf, the reserve potential is at least 4.5 TCF, net to Ultra.

Now moving to some operational factors. Our horizontal Marcellus wells typically range from 9400 to 10,500 feet, total drill depth, with lateral lengths typically ranging from 3800 to 4400 feet. Typical cost to drill and complete an average 4,000-foot lateral section ranges from $3 million to $3.5 million, depending on lateral length, number of frac stages, and technology applied.

Focusing on the portion of this Marcellus program on our operated 100% Marshlands acreage, Ultra has drilled a total of three horizontal Marcellus wells beginning in the third quarter, with the fourth well currently drilling near landing point to commence the horizontal Marcellus section.

The vertical segments of these wells are drilled with a small air rig to approximately the Tully Limestone and a larger rig is moved in to directionally drill the latter portion. Our average lateral length for these wells has been 4285 feet.

We are leveraging our Pinedale experience and have reduced our days to drill from 16 days, spud to TD on the first well to 12 days Spud to TD on the third while increasing our lateral reach by almost 10%. Our partner East -- Resources, I'm sorry, is currently averaging 10 days, spud to TD, demonstrating as we drill more wells we will continue to improve our drilling efficiency. The first Ultra operated horizontal well to be completed is the P Pierson 801-5H [ph] with a lateral length of 4,097 feet.

Completion of this well included 13 stages with first production on the well scheduled to begin today or tomorrow. Our completions are typically 12 to 13 stages with 200 to 300-foot stage bands and pumping at 100 barrels per minute, 8,000-psi, and over £0.5 million of profit. We're designing four to five additional frac stages per well beyond what some operators are doing, which is providing higher initial production rates.

We have plans for acquiring micro seismic data during the completion of a pair of lateral wells later this year to help us to fine tune our completion and wellbore placement design, and help define drainage area.

The capacity of our Dominion taps in the Marshlands area is 25 million cubic feet per day, with expansion to 80 million cubic feet per day scheduled for early December.

In addition to the Dominion pipeline access, we currently have three other pipeline taps on Tennessee gas, with a total capacity on these three taps of 285 million cubic feet per day. The plans for expansion in 2010 as our drilling program increases.

We expect to drill an additional five operated and 11 non-operated horizontal Marcellus wells before year-end, for a total of 36 horizontal Marcellus wells in 2009. Our 2010 Marcellus drilling program is expected to include at least 100 horizontal wells. Back to you, Mike.

Mike Watford

Thanks Sally. In summary, we are very pleased with our third quarter results and now find ourselves well into the fourth quarter. Year-end 2009 results will meet or exceed all of our 2009 targets.

Looking forward on our preliminary basis for 2010, since our capital budget for 2010 isn't approved until early February, here is what we see. First, our 15% to 20% annual production growth target will have more financial bang in it than most due to our low cost structure, coupled with the significant uplift we expect to receive in natural gas prices on a company wide basis, due to the changing mix of our production and the reduced discount associated with the sales location. In other words, on a per share earnings and cash flow basis, our production growth should be more accretive.

Secondly, looking out over a two-year period, using a $6.25 Henry Hub gas price, results in approximately 2011 production of 250 Bcfe, or 40% above 2009's target of 175 Bcfe, with the expenditure of $2 billion in capital, while generating free cash over the two-year period.

Thirdly, we continue to derisk and increase the quality and quantity of the hydrocarbon resource our shareholders own without selling assets or issuing stocks or otherwise diluting our owners.

Lastly, we note that we talk more than most about corporate margins and returns, but making money and partnering it with growth and production and resources is what it’s all about. Thanks.

Now, we would like to open the call for questions.

Question-and-Answer Session

Operator

(Operator instructions). Your first question comes from the line of Brian Singer of Goldman Sachs. Please proceed.

Brian Singer – Goldman Sachs

Thanks. Good morning.

Mike Watford

Good morning.

Brian Singer – Goldman Sachs

When you look at the $0.5 million dollars per well reduction in Pinedale and completed well costs, you highlighted the sharp reduction in drilling days. But do you have some sense of what the split is of that in terms of the efficiency gains versus lower service costs?

Bill Picquet

Brian, this is Bill. Most of that is in fact a very high percentage of it is due to efficiency gains, Brian. We're actually seeing service cost reductions start to level out in areas such as pipe, and the new rigs that we're bringing in that are new builds, are actually higher on day rates at this point in time due to the commitment timing being made back when we did the new builds. In fact, what we're doing is we're continuing to reduce costs primarily through efficiency and applications of new technology.

Brian Singer – Goldman Sachs

Great, thanks. And then secondly, on, Mike, on your comments at the end in terms of your CapEx over the next two years, should we take the $2 billion as roughly even, IE $1 billion in 2009, $1 billion in 2010, and $1 billion in 2011?

And how should we think about the extent of the Marcellus in terms of the contribution to overall production?

Mike Watford

I think it is fine to us split the $2 billion in half, and when we announce final CapEx for 2010, we will see where we are in that. And as to the Marcellus component of our production, over the next two years, we have very conservative estimates in 2010 currently.

We are not ready to share those yet but we are pretty comfortable when we do share them, we will have a great opportunity to under promise and over deliver. And as we have more wells on and more months of production, again, we only have eight wells on as Sally said, and the earliest one in terms of production history is mid July. So we just don't have a large sample size.

But from what we've seen, we're probably pretty confident right now that our production estimates, preliminary production estimates for Marcellus in 2010 and '11 are probably less than what they will be so I'm walking around the question without answering it, I realize that.

Let's just say that if we go out to 2012, I will take you out an extra year, the contribution of the company from Marcellus, we think somewhere between 35% to 40%.

Brian Singer – Goldman Sachs

Great. Thank you.

Operator

Your next question comes from the line of Joe Allman of J.P. Morgan. Please proceed.

Joe Allman – J.P. Morgan

Thank you. Good morning, everybody.

Mike Watford

Good morning.

Joe Allman – J.P. Morgan

Question, Sally, you mentioned that, I think if I heard you correctly, that you basically have tested in a way the four corners of your acreage, and I guess that would be with both the horizontal drilling and the vertical. Could you give us some more color on that?

So like on the horizontal, how much of your acreage have you tested versus the verticals and what do you think -- what are you seeing in the verticals that gives you the confidence that all of the acreage is perspective?

Sally Zinke

I think if I had to characterize, we probably tested at least 80% of our area with horizontal wells. And we have some verticals outside of that. We're seeing that the verticals are getting us a pretty good indication of what the horizontals are going to do in that area both in terms of thickness, the amount of organic content in the Shale, those sorts of things.

Joe Allman – J.P. Morgan

That's helpful. And could you give us a breakout of your acreage by county?

Sally Zinke

No, I'm not prepared to do that.

Joe Allman – J.P. Morgan

Okay. Great. Thank you.

Operator

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

Noel Parks – Ladenburg Thalmann

Good morning.

Mike Watford

Good morning.

Sally Zinke

Good morning, Noel.

Noel Parks – Ladenburg Thalmann

In the Marcellus, can you talk a little bit more about what you see as the reasons for the vulnerability? You've got some terrific, terrific wells, others that are just very good. Can you comment on that?

Sally Zinke

I think that there is a little bit of difference in variation in lateral lengths on those wells. Where if you look at the last group of well, the last four wells that have been drilled, the average IP's there are in excess of 8 million a day, so we're getting better at it. We're doing more robust fracs. We're doing more frac stages per well. We're on the learning curve, but it’s getting better. So I think you're going to see some variability until we get it down pat.

Noel Parks – Ladenburg Thalmann

And in addition, you said the east resources wells, their days to drill were down to just 10 days, it sounds like they're a little further on the learning curve. What’s the nature of that? Is that just entirely, I don't know, rig mobilization issues or things like that or --?

Sally Zinke

No, they started about where we started, and they have just been at it a little longer so they have a little more practice at it. I think we will get there. We're only on well number three.

Mike Watford

Yes, they are on well number 17. So we applaud their efforts. And we will catch up and we are confident we will equal or exceed them.

Sally Zinke

I think there is an advantage here with having a partner that’s also operating. We can look at best practices on both sides and share some of that synergy.

Noel Parks – Ladenburg Thalmann

Okay and wondering about acreage acquisition in the area, just what sort of prices you're seeing, and of course, you did say you wanted to keep it confidential as far as exactly how much acreage you had where. Are you seeing a lot of competition? And do you have an idea of either a total ultimate acreage count you would like to get to or sort of the ceiling for what you feel you are willing to pay for acreage as it gets bid up?

Sally Zinke

I'm certainly not going to go there. I think certainly the market has heated up a little bit more in the last few months, particularly as people are starting to report good results. But I don't think that’s something we care to share right now.

Noel Parks – Ladenburg Thalmann

But is it fit to say that are you still interested in reasonably priced acreage?

Sally Zinke

Sure, I would like to buy as much acreage as I can really cheap.

Noel Parks – Ladenburg Thalmann

That's fair enough. I think that's it for me. Thanks a lot.

Mike Watford

Thank you.

Operator

Your next question comes from the line of David Heikkinen of Tudor, Pickering, Holt. Please proceed.

David Heikkinen – Tudor, Pickering, Holt

Good morning. I had a question on the Pinedale as you think about Questar has talked about gas processing and kind of moving that forward, into 2010. What type of uplift, or what type of opportunity do you see for processing Pinedale gas on I think it was the ethane side?

Mike Watford

I don't know what you're talking about, David. Most of our gas is not processed by Questar, just the little bit that we have in the wells that they operate. Most of our gas is processed by enterprise --.

David Heikkinen – Tudor, Pickering, Holt

No, I mean, is there more opportunity or is it all liquids are taken out and there isn't anything from an expansion side or cryo side that you can do.

Mike Watford

There is no benefit to us. Our gathering agreements, we don't share any liquids upside.

David Heikkinen – Tudor, Pickering, Holt

Okay. And then as you think about the Pinedale drilling times that you talked about the perfect well being 11 days, can you talk about the perfect vertical well and the perfect directional well as you go from a pad as far as number of days those wells take to drill?

Bill Picquet

This is Bill again. Virtually all of the wells that we're drilling are directional. Typically what you do is you drill your vertical well which is only one per pad as a delineation well, well before you get on there with the pad rig. So all of the wells that we're talking about in our discussion today are essentially directional.

David Heikkinen – Tudor, Pickering, Holt

Very good. So then as you think about a go forward plan, as you move across areas, just trying to get into details of how you think about the development, there really isn't a difference, drilling Riverside, Mesa, or Warbonnet, as far as days to drill, significantly.

Bill Picquet

Well there are some differences as far as depth are concerned and so there are some differences. Actually we're drilling deeper right now in Riverside and Mesa. So we're actually reducing our days in the face of drilling deeper.

David Heikkinen – Tudor, Pickering, Holt

Okay. And then on the Marcellus side, can you talk about net well, and kind of time for 2010 of out the 100 growth?

Mike Watford

I don’t think we are ready to share that yet David. I mean, I think Marcellus has got the net wells 2009, what are they?

Sally Zinke

Yes, they’re 36 for '09 and that net to 22.

Mike Watford

Let me tell you why we're being little defense with that 2010 is because we're suggesting 100 wells, we think the likely answer is going to be in excess of that but until we have more time to work our way through some of these issues, we're just not ready to share. But we are very comfortable with a 100 plus wells for 2010. I will be glad to give you a net number here in early February.

David Heikkinen – Tudor Pickering Holt

And then I guess, given your drillings days details, how many rigs is that?

Mike Watford

Again it’s -- our view is that what may have 30 -- 90 days ago we may have bough 16 to 20 days per well. Now we are pretty comfortable with that 10 to 12 days per well. So, that means fewer rigs -- we are working through all that, and I think in the future we really are going to talk about wells. We are going to drill not so much rig count, because rig count is less of a metric as we increase our productivity.

David Heikkinen – Tudor Pickering Holt

So then -- fair enough. As you think about 2011 and the same type of capital budget with a 50:50 split, does that imply that you basically assuming the same well count in 2011 or is that an incorrect assumption?

Mike Watford

In Marcellus or…?

David Heikkinen – Tudor Pickering Holt

Marcellus, yes.

Mike Watford

We are probably assuming more than 100 wells in 2010 and 2011 in Marcellus well. Let’s say that our assumptions in 2011, what we are just, I don’t think there is any (inaudible) to suggest anything yet, we will just wait a little longer.

David Heikkinen – Tudor Pickering Holt

And then as you think about your capacity for the Marcellus, the 300 million a day in tab, can you talk about accessibility, maybe days for non-production and kind of how you fill that up?

Mike Watford

Let’s see, right now, we have 20 wells drilled and only eight are on production and (inaudible) in terms of getting them on production. And we are trying to get the infrastructure build ahead and part of its built ahead, not as much as we want. So, there is going to be lag and that’s part of the issues we are working in terms of trying to come up with our production forecast -- production forecast for 2010, 2011 for Marcellus are not very ultraconservative ones. We have included in our internal documents now.

David Heikkinen – Tudor Pickering Holt

And is there any winter drilling as you think about drilling in completion schedules in Appalachia that we ought to start thinking about as we are going into winter?

Bill Picquet

David, the main issue is only during spring time. We have short breakup period where it is very difficult to move rigs due to just road conditions. But that’s a relatively short-time period on average year-over-year in Appalachia. I would say, winter time, really significantly impacts our operations as well.

David Heikkinen – Tudor Pickering Holt

Okay. Very good. Thanks for all of the answers to the question.

Mike Watford

Thanks.

Operator

Your next question comes from the line of David Timmon [ph] of Wachovia. Please proceed.

David Timmon – Wachovia

Most of the questions have been answered, but if I look at 2010 in Pinedale, how many rigs? Should we stay at that 7, 7.5, (inaudible)?

Mike Watford

I think we are going to try to move away from rig count data.

David Timmon – Wachovia

All right. Let me try something else then. I think I know the answer to, but to use the numbers you just threw out to David Heikkinen, if I plug in the same assumptions as far as the 22 over 36 and get to a 100 wells in 2010, in the Marcellus, my 2010 exit rate is in the 140 range?

Mike Watford

I don't think we would necessarily argue with you.

David Timmon – Wachovia

Okay. All right. Everything else has been answered. And congrats on a good quarter.

Mike Watford

Thank you.

David Timmon – Wachovia

Thanks.

Operator

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

Leo Mariani – RBC

Good morning here, folks. Question, your REX pipeline, what’s your current firm capacity out there, and do you expect that to increase in 2010 and 2011, and what type of levels can we expect it to increase?

Mark Smith

Our capacity is 200 million cubic feet a day and we expect that to hold steady.

Leo Mariani – RBC

Okay. In terms of your Marcellus production, you guys talked about 30 million a day, year end '09, exit rate. It seems like there is a lot of infrastructure that is starting to come in as we get to year end and kind of early 2010. Do you guys expect to see -- step up pretty quickly in productions as we get into the first quarter of 2010 results of that infrastructure coming on, will you be able to sort of catch up on the wells there?

Mark Smith

Well, I think when that happens is maybe a little later than early 2010. We are going to be building out a gathering system infrastructure, both by our east operated acreage, as well as our ultra operated acreage. So, over the course of the year you will see that continue to ramp up. We are basically building out infrastructure ahead of a drilling program rather than focusing on drilling pad wells.

Mike Watford

But I think the other point I want to make sure we are on the same page is, we don’t foresee the 100 wells drilled and 50 are production. We don’t see where we are today with 8 on and 20 drilled. In fact --

Mark Smith

And your cycle time will continue to improve, as we go forward. And so I am a little hesitant to say early in the year, it is going to improve dramatically, but I think over the course of the year, you will see it improve as we go.

Mike Watford

And we are trying to be candid as we always are here, is that we have a well-orchestrated, finely-tuned organization and effort in Wyoming, in Pinedale, built up over a decade, with the infrastructure and processing, gathering, interstate pipeline capacity, et cetera. We lack that in Pennsylvania.

So, we are going to be more conservative and more iffy about suggesting what we can do and when wells come on production, and if they -- if a more probable case would have production and wells on. Earlier, we will probably risk that, and push it back, just to make sure that we are very comfortable in what we are suggesting to you. So, again, we are going to take advantage of our old adage of underpromising and over-delivering.

Leo Mariani – RBC

Okay. And you guys are owning all your gathered lines out there and that’s going to -- how you do -- going forward as well?

Mike Watford

We are building our own lines, yes.

Leo Mariani – RBC

Last question here for you guys, obviously it sounds like you are making a prediction that Rockies’ differentials, you know, really improved versus a couple years ago, and hopefully will stay there for the next couple of years. I guess just talking to some other operator, some of the other competitors of yours out there, some of the other folks kind of seem to think that differential may start to widen out as we get into 2010 and 2011. Do you guys have any sort of comments on that at all?

Mike Watford

Sure. It is not us who’s predicting that. You go out to the forward curve, that’s what the forward curve says. That’s first thing. So, and number two, where is the production that those other companies are suggesting something different than what the forward curve says?

Leo Mariani – RBC

Okay.

Mike Watford

We are just going with what’s out there and that’s all we are doing. We are just taking the numbers that are there. You go ahead and change. If you look at excess capacity, there is over (inaudible) a day of excess capacity in the Rockies today, and that’s only going to get greater.

Leo Mariani – RBC

All right. Thanks a lot, guys.

Operator

And your next question comes from the line of Dan Guffey [ph] of Thomas Weisel Partners. Please proceed.

Dan Guffey – Thomas Weisel Partners

Hi, guys. I was just wondering if all of your horizontal wells in Pennsylvania have been drilled using seismic and if so, do you feel this is a necessity going forward?

Sally Zinke

We do have a fairly large grid of 2D seismic throughout our entire area. We also have about 40% of our acreage covered by 3D seismic at this point. We are finding that 3D seismic is a definite advantage in designing and laterally drilling.

Dan Guffey – Thomas Weisel Partners

Okay. But not a necessity?

Sally Zinke

Well, I would say definite advantage puts it, I don't know that you would say necessity, but I think we are looking at an area that has a lot of structural release and a fair amount of faulting, and I think it is well worth the dollars spent to have that 3D advantage.

Dan Guffey – Thomas Weisel Partners

Okay. Great. And then what percentage of your acreage right now is HPP, and where do you expect that to be at year-end 2010? And then, also, do you see fulfilling any of the remaining lease commitments as a problem?

Sally Zinke

I will start with the back end, first. I don’t see our lease commitments as being a problem. I don’t think we want to postulate right now what will have HPP by year end, and definitely not what’s held right now.

Dan Guffey – Thomas Weisel Partners

Okay. Great. Thank you. Great quarter.

Mike Watford

Thank you.

Operator

(Operator instructions). And your next question comes from the line of Ron Mills of Johnson Rice. Please proceed.

Ron Mills – Johnson Rice

Question just on the Marcellus CapEx. It was only 135 million this year. It is obviously going to increase. But if you look out over the $2 billion over ‘10 and ‘11, any bracket around how much of that would be directed towards Wyoming versus Marcellus?

Mike Watford

Just simple math, it’s 35 horizontal wells in 2009, for $135 million, it is not all going to wells. It is infrastructure (inaudible), but if we go to 100 wells, then you multiply that by times 3, you get to $400 million. So let’s just use $400 million in Marcellus for 2010-2011, as a simple analogy.

Ron Mills – Johnson Rice

Okay. And just from a pricing standpoint, when you run your pricing differentials, in the Rockies, the futures being 90%, does that account for your BTU content being 1060 or 1070 or do we still have to make that adjustment.

Mark Smith

No, it doesn’t. You still have to make that adjustment.

Ron Mills – Johnson Rice

Okay. That’s it. Everything else has been asked. Thank you.

Mike Watford

Thanks, Ron.

Operator

And have you no further questions at this time.

Mike Watford

Thank you very much. If you have additional questions, please don’t hesitate to give us a call. Thank you.

Operator

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

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Source: Ultra Petroleum Corp. Q3 2009 Earnings Call Transcript

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