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Ultra Petroleum (NYSE:UPL)

Q3 2010 Earnings Call

November 04, 2010 11:00 am ET

Executives

Michael Watford - Chairman, Chief Executive Officer and President

Kelly Whitley - Investor Relations Manager

William Picquet - Vice President of Operations

Douglas Selvius – Director, Exploration

Brad Johnson - Director, Reservoir Engineering & Planning

Marshall Smith - Chief Financial Officer

Analysts

David Tameron - Wells Fargo Securities, LLC

Brian Singer - Goldman Sachs Group Inc.

Marshall Carver - Capital One Southcoast, Inc.

Nicholas Pope - Dahlman Rose & Company, LLC

Subash Chandra - Jefferies & Company, Inc.

Don Crist - Johnson Rice

Noel Parks - Ladenburg Thalmann & Co. Inc.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Eugene Lipovetsky - Zimmer Lucas Partners

Presentation

Operator

Good day, ladies and gentlemen. Thank you very much for your patience, and welcome to the Third Quarter 2010 Ultra Petroleum Corporation Earnings Conference Call. My name is Bill, and I will be your conference coordinator for today. [Operator Instructions] I would like to turn the call over to our host for today's conference, Ms. Kelly Whitley, Manager of Investor Relations. Please proceed, ma'am.

Kelly Whitley

Thank you, Bill. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's Third Quarter 2010 Earnings Conference Call. On the call with me this morning to discuss our third quarter results are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Chief Financial Officer; Bill Picquet, Vice President, Operations; Brad Johnson, Director, Reservoir Engineering; and new to the Ultra team, Doug Selvius, Director, Exploration.

Before turning the call over to Mike, I'd like to cover a few administrative items. First, earlier this morning, we filed our 10-Q with the SEC. It is available on 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. Reconciliations and calculation schedules for the non-GAAP financial measures are also on our website.

Second, Ultra will be participating in several conferences over the next few weeks. We will be at the Jefferies Energy Conference in Houston on December 1, Capital One Energy Conference in New Orleans on December 7, and Wells Energy Conference in New York on December 8. Please visit our website for updated events webcast. Now let me turn the call over to Mike.

Michael Watford

Thank you, Kelly. Good morning. Joining me today is a little larger contingent of the Ultra team to share more of our management depth with you. These are interesting times. With the current investment view towards natural gas producers, one would think there's no money to be made in the business. No margins, no profits and no returns. And for 95% of our competitors, that is probably true. In times like this, we are reminded of our differences. Primary one being that we've always focused on returns first and growth second. Because of that and our mix of assets and people, we make money throughout the commodity price cycle. In fact, for the third quarter of 2010, Ultra Petroleum's earnings actually increased when compared to the third quarter of 2009. Earnings are also up on a sequential basis over the second quarter of 2010, and are up again for the nine-month period in 2010 versus 2009, a trifecta. It's the same for cash flow, up for all three of the comparable time periods. And yes, Ultra Petroleum is still highly profitable with a net income margin for the quarter of 33% and cash flow margins of 71%. Our return on equity was 42% and return on capital, 17%. Yes I know, we're the only company that talks about margins and returns before production. Such is our focus. The third quarter of 2010, we increased our production over the third quarter of 2009 establishing a new record. And we also increased it sequentially over the second quarter of 2010. And again, on a nine-month basis grew production over 2009 similar time period, consistent and sustainable growth. Surprisingly for many, our unhedged natural gas price realization for the third quarter 2010 was up over 30% when compared to 2009, and up almost 40% in the year-to-date comparisons.

We still enjoy the lowest cost in the business. We don't mask any gathering or transportation costs in the midstream segment. Natural gas price that Ultra needs to receive to break even on a corporate net income level is $2.39 an Mcf. That's not a field level or well level but on a fully loaded all in corporate cost level. That's why our margins and returns of $5 gas, equal or exceeds other companies at $75 to $80 oil. We're just different. Our cash flow breakeven natural gas price is as you would expect a much lower $1.11 per Mcf.

I think we are alone in our industry in sharing these basic financial metrics. But we want to provide clarity that our individual project returns translate directly to our corporate returns, and we believe margins matter.

On the operating side, our tight gas development project in Wyoming continues to impress with improving efficiencies and increased productivity. We will participate in over 230 wells in 2010 with an additional 5,400 to drill in the coming years. Our shale gas opportunity in Pennsylvania is in a different place. We are in our first full calendar year of assessment with numerous evaluations occurring across the 470,000 gross acres. We are very positive with early time results and realized we lack the depth of data we are accustomed to in our Wyoming project area. We also take note of the billions of dollars spent and committed by Shell and Mitsui to build a position consistent with Ultra's, welcome them as our partners in our mutual goal of long-term value creation. To that, we see an expanding inventory of future drilling locations, well in excess of 5,100 wells to be drilled in a joint acreage. We're trying to participate in 115 horizontal wells in 2010. On the debt side, we continue to be underlevered. 100% of our corporate debt is fixed rate long term at very attractive rates. I think we are rather well positioned and very mindful of where we are in the business cycle. Mark, you want to talk about the finances?

Marshall Smith

Sure. Good morning. As you've seen from our press release, we had another very good quarter operationally with record production, continuing improvements in drilling efficiency and reduced costs. In terms of commodity price for the quarter at 93% of Henry Hub, Ultra's realized corporate natural gas price before the effective hedges was up significantly year-over-year. Operating cash flow is up 15% for the quarter to $198.7 million. From a balance sheet perspective, we continue to be very well positioned. As of September 30, we had $7.2 million of cash and cash equivalents on hand and $1.3 billion in outstanding senior debt with our debt to EBITDA ratio in a very comfortable 1.68 times. Our total debt capacity is in excess of $2.5 billion providing us with over $1.2 billion in unused senior debt capacity. We continue to demonstrate strong organic growth, while generating industry-leading margins and returns and maintaining our financial flexibility. For the third quarter, our Wyoming production was up 21% on a comparable year-over-year basis to a record 55.4 Bcfe. Once again our quarterly production was an all-time high for the company. You'll hear more about this from Bill in a minute.

Moving to the current market conditions that many tend to overlook is a strong year-over-year improvement from Rockies gas prices. This is the primary factor behind the increase in our natural gas price, excluding the effect of hedging for the third quarter. Prices rose to $4.08 per Mcf, an increase of 32% over prior year levels. Condensate prices rose to $66 per barrel for the quarter, largely as a result of our increased production levels. Revenues for the quarter, including effects of our hedges rose to $281 million.

Corporate lease operating expenses for the quarter increased year-over-year to $0.85 per Mcfe as a result of higher severance and production taxes due to higher commodity prices. This was partially offset by reductions in our unit operating costs and gathering expenses. Looking at our cash cost in Wyoming, excluding severance taxes, our fuel level costs, decreased 7% year-over-year on unit basis to $0.43 per Mcfe. Transportation costs which represents our charges [indiscernible] amounted to $16.2 million this quarter or $0.29 per Mcfe on our total production volumes. Our DD&A rate for the quarter rose to $1.08 per Mcfe, general and administrative expenses remained flat on a unit basis year-over-year at $0.11 per Mcfe, while interest costs were also flat at $0.21 per Mcfe. That net effect of all these factors was a 2% increase in all-in cost to $2.52 per Mcfe compared to $2.48 in the third quarter of 2009. I'd like to point out that our all-in cost numbers include all costs, including gathering and transportation, unlike some of our peers. This increased again and all-in cost was primarily driven by higher severance of production taxes due to higher commodity prices and was largely offset by continued reduction in fuel costs combined with a decrease in unit transportation cost due to higher overall increased volumes.

As a result of the increased production and improvement in realized gas prices before hedges, as well as our continued focus on operational improvements and cost reductions, our operating cash flow increased over the comparable 2009 quarter to $198.7 million. This provided for an operating cash flow margin of 71% and $1.29 in cash flow per diluted share. Our cash flow per share was up 13% over prior levels and 11% sequentially. On an unit of production basis, our cash flow for the first nine months of the year amounted to $3.62 per Mcfe compared to our all-in F&D cost for 2009 of $1.29 per Mcfe or corporate recycle ratio of 2.81 times.

Adjusted for unrealized gains associated with a mark-to-market position on our hedges, our net income ratio is $91.9 million for the quarter or 33% net income margin and $0.60 adjusted earnings per diluted share. As Mike indicated, in terms of breakeven levels, our net income breakeven is now $2.39 per Mcfe, cash flow breakeven at $1.11 per Mcfe. Our adjusted return on equity on an annualized basis for the third quarter was 42%, and our adjusted return on average capital employed was 17%.

Cash provided by operating activities during the quarter amounted to $232 million, with cash used in investing activities totaling $378.1 million. These investment activities were largely comprised of $291.6 million of oil and gas related capital expenditures, $28.4 million in gathering and infrastructure investments. For the quarter, net cash provided by financing activities totaled $145 million consisting primarily of net borrowings on our senior bank facility. Recall that subsequent to quarter end, we raised $525 million at very favorable fixed rate debt, proceeds were used to repay senior bank debt and pre-fund the remainder of our 2010 investment programs. Weighted average maturity for the offering was 11.8 years with a weighted average coupon of 4.65%. We're very pleased with the offering and it confirms a low risk, long-lived nature of our underlying assets.

In terms of our price outlook for the remainder of the year, balance 2010 pricing for Opal is currently trading around 95% of Henry Hub, Dominion South for the balance of the year is trading at roughly 105% of Henry Hub. We continue to believe our corporate basis differential will run approximately 94% to 96% of Henry Hub.

Moving to hedging as detailed on Page 5 of our press release, we currently have approximately 24 Bcf of our fourth quarter projected natural gas production hedged and fixed-price swaps and weighted average price of roughly $5.50 per Mcf. This represents approximately 40% of our expected production during the quarter. Calendar 2011, we have about 133 Bcf hedged at a price of roughly $5.83 per Mcf.

I’ll wrap up my comments by pointing out that on Page 6 of our press release we continue to confirm our full year 2010 production guidance at 213 to 216 Bcfe and are establishing production guidance for the fourth quarter at 56.7 to 59.7 Bcfe. We provide additional detail on our outlook and guidance on our press release.

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

William Picquet

Thanks, Mark.

In Wyoming in the third quarter, Ultra brought on a stream 68 gross, 37 net new producing wells. Year-to-date 2010 total through the end of Q3 we brought online 195 gross, 106 net new producing wells. Average initial 24-hour sales rate for these new Pinedale producer was 8.4 million cubic feet per day. Ultra's operated Pinedale wells averaged 9.3 million cubic feet per day while the non-operated wells averaged 6.3 million cubic feet per day. We anticipate drilling a total of 239 gross, 128 net new wells in Wyoming for the full year. We expect to bring online a total of 249 gross, 139 net new producers in Pinedale for the full year.

During Q3 in Wyoming, we averaged 531 million cubic feet per day net production. End of the third quarter, there were a total of 13 rigs active on Ultra's interest lands in Wyoming. Our overall operating efficiency in Pinedale continues to improve. Our cost performance has been excellent. We averaged $4.6 million per well during Q3 in our operated program at Pinedale. Third quarter, we averaged 14.4 days spud to TD for Ultra operated wells, a 21% improvement, the average for Q3 2009. During the third quarter, our average rig release to rig release was 17 days, down over 27% from our Q3 2009 average. 79% of our wells were drilled in less than 15 days spud to TD. Efficiency in our Pinedale operations has also been outstanding. During Q3, we've maintained our rapid completion phase in our operated frac program leaving a total of 46 wells. We're averaging over 26 frac stages per well in Pinedale year-to-date through the third quarter of 2010 versus 25 stages per well during the full year in 2009. We averaged 70,000 per stage during the first three quarters of 2010 compared to 74,000 per stage for the full year in 2009. This increasing average in frac stages per well during 2010 is due to the fact that we're drilling and completing wells in some of the best areas in the field where there is more net sand pay per well. As mentioned earlier this is resulting in excellent well performance.

I’m going to turn things back over to Brad Johnson now for more details on Wyoming resource, Brad?

Brad Johnson

During the third quarter of 2010, the company had obtained meaningful performance data on our Ultra operated five-acre pilot program. 24 five-acre wells were brought on production in the quarter bringing our year-to-date total to 29. Among these 29 Ultra operated five-acre wells, the average IP 7.5 million cubic feet per day. The importance of these wells along with an additional 31 five-acre wells brought on by Questar and Shell so far this year were all in line with our pre-drill expectation. Furthermore, these results validate the incremental recoveries that we have estimated for increased density drilling down to five-acre spacing in Pinedale. We plan to complete the majority of our five-acre pilots by year end, utilize these results to pursue additional five-acre development in the remaining parts of the Pinedale field.

September 2010, we reached the second anniversary of BLM’s issuance of its record of decision, the development of Pinedale Anticline. Since the release of the ROD, Ultra has continued to efficiently develop its resources by employing its fit for purpose rig fleet, operational best practices in Pinedale, so the volumes have been the driver for the company's sequential production growth for the last 12 quarters. We have worked closely with the BLM and their stakeholders to ensure the execution of our development program without significant interruption or regulatory delay. This has resulted in an increased predictability of our program as compared to times before the ROD was issued. One of the key elements of the development in Pinedale is the once a pad, stay a pad concept, this has enabled Ultra to continue to improve its cycle time.

Now let’s shift the attention to our Pennsylvania activity, it is important to emphasize that in Pennsylvania, and in contrast to the development efforts in Pinedale, Ultra is in the early stages of resource assessment across the vast amount of resource. We're very pleased with the early results in the Marcellus program, but we remain focused on learning quickly about the resource potential of our acreage position. During the first three quarters of 2010, Ultra has been very active in this horizontal program in the Marcellus Shale. As of September 30, Ultra had a total of seven horizontal rigs drilling in the Marcellus. The third quarter, we participated in the drilling of 20 new horizontal wells, which brings our year-to-date total of horizontal Marcellus wells drilling case to 79 gross, 48 net wells. For calendar 2010, we expect to drill and case approximately 115 gross, 17 net wells. Also in the third quarter, 23 horizontal wells were brought online. This was the most active quarter to date for getting wells completed and online, nearly doubling the number of wells producing as compared to the end of the last quarter.

For the first nine months of 2010, Ultra has put 44 gross, 30 net wells on production. With the 16 wells that were brought online in October, we expect full year totals to approximately reach 79 gross, 50 horizontal Marcellus well. Well performance continues to increase our confidence in the quality and profitability of our Marcellus program. During 2010, we assessed that multiple wells at over 10 million cubic feet per day, all areas of operation. Also in 2010, our average lateral length averaged 4,500 feet, with average 12-stages per completion. Our year-to-date average well cost among other areas is $4.2 million.

Activities in our joint venture with Anadarko continue to ramp up. In the third quarter, 11 wells were drilled and five wells were brought online. Increases in development activities that we have projected for the last part of the year are well underway. Gathering system with a capacity of 200 million cubic feet per day officially commissioned in Southwest Lycoming County. We are excited about this area. In fact a significant amount of drilling activity to be focused here in the near term.

In July , Shell closed on its nearly $5 billion acquisition of East Resources became our 50-50 partner in that JV. Immediately Shell began changing out its rig fleet and fraccers. It initially expected about a 45-day interruption, development activities. That interruption has now extended to three months. As a result, we have adjusted our schedules and forecast accordingly. This has resulted in a reduction to our full year 2010 forecast for wells drilled as well as brought on line. Pennsylvania, Ultra averaged 49 million cubic feet per day net production in the third quarter, up from the second quarter average of 33 million cubic feet per day. We are currently producing a net volume of 79 million cubic feet per day and anticipate an average of approximately 80 million cubic feet per day for the fourth quarter. At this point, we are accomplishing this performance in Pennsylvania despite the reduced activity in our Shell JV. Although fewer Marcellus wells are currently contributing to the production volumes that we originally forecasted, the average well decline has been flatter than we project in our 3.75 Bcf type curve.

With that, let me turn things over to Doug Selvius for details on the Pennsylvania program.

Douglas Selvius

Thank you, Brad. Ultra's technical team is very focused on value creation. And we are continually looking for ways to improve cost efficiency and well performance. During the third quarter, we made significant progress on a number of fronts. From a drilling standpoint, we have applied our learnings about lateral placement, (inaudible) and well design to our latest wells and have reduced drilling comps from kick off point to total debt from 11.4 days per well to under four days.

Rig release to rig release time have similarly dropped from 15 1/2 days per well to under 10. We've also dedicated considerable efforts to understanding the geographic variability of the Marcellus, possible impact to geologic features might have on well performance. Specifically, we've been studying such things as lateral placement, structural positioning of wells, well proximity and bed curvature. Results are directly contributing to both better drilling efficiency as discussed above and a better understanding of acreage prospectivity across our 470,000-acre position. We plan to continue this work going forward particularly as we progress the announcement of our 3D data volume.

With these main purposes of technical understanding, Ultra recently participated in its third micro- seismic survey, with a proprietary evaluation of two frac jobs on our State 8 15 bed. Our intent with the survey was to enhance our understanding of four different criteria, frac design, well spacing, well bore orientation and again our lateral positioning within the lower Marcellus. Prior to the survey, we drilled four wells from southeast to northwest in the past. Average lateral length was 3,600 feet with 500 feet spacing between wells, put two laterals right in the middle of the lower Marcellus to a bit deeper in the section near the highly organic ridge member at the base. We hope this over and underplacement would teach us something about how lateral positioning impacts both fraccing and well performance.

Our fraccing the middle two wells of the foursome due to the outer two wells, to listen and record results. Data recorded was exceptionally good and several things are clear from the information, confirms that we're drilling our horizontal at the correct orientation. We validated previously observed relationships between pump rate and frac performance, and we obtained data suggesting lateral placement has a meaningful impact with frac initiation and propagation. Most importantly though, in this data, we gained insight that will help us design and space our wells properly. Our next pad will be drilling and testing wells with 750 feet between laterals. Assuming an average lateral length of 4,500 feet, the spacing results in a drainage area of roughly 80 acres.

We will continue to evaluate lateral lengths and overall well spacing. But if our future work continues to affirm this 80 acres is accurate, we will have more than 5,100 gross, 2,300 net locations across. At our current UR estimates, those counts indicate over 8 Tcf of Marcellus potential net to Ultra.

I'll wrap up my comments with just some general observations about other exploration targets that added value of our partnerships in the Marcellus. First, with respect to other targets, there's been a fair amount excitement generated by recent test in some of the other shale, particularly the Geneseo and the Utica. We've been evaluating both of these formations across our acreage position, and we recognized potential in both targets. Geneseo, in particular, being shallower than the Marcellus was quite interesting.

Last comment I have pertains to our two joint ventures, one with Anadarko and the other with Shell. Our technical teams are working closely together in very healthy collaborative environment. Our discussions and our shared learnings on drilling practices, completion techniques, geological and geophysical observations provide a competitive advantage not realized by individual operators focused simply on their own development projects. The larger pool of data that Ultra has available through these JVs has moved the learning curve forward very quickly, any breakthrough in understanding will be transferred very quickly to other areas.

With that, I'll hand it back to Mike for some closing comments.

Michael Watford

Thanks, Doug.

At times like this in the cycle, we ask ourselves whether we are doing the right things. And we'll remind ourselves to what it takes to build a successful energy business, one that is profitable and gross. First you need assets with low development and acquisition cost, low land cost, low drilling cost, low F&D cost which drive low DD&A expenses as a fixed cost component. In addition, you need low operating cost, preferably onshore large-scale projects with lean staffing, marry that with low overhead cost, low corporate G&A cost, low interest cost, low amount of debt, and that combination is your variable cost. For the profit part of the calculation you need healthy reasonable product prices, the revenue piece. For Ultra, the product price requirements for healthy margins and returns are simply lower than others. Our margins are very resilient. Recently in an industry report, an analysts wrote that Pinedale is the only dry gas asset that has positive returns of $4 gas. We think Marcellus will prove out to have similar economics. The growth portion of a successful energy business, you need a large inventory of reinvestment opportunities. We have a large-scale developed project in Pinedale with approximately 5,400 wells drilled, and we have our equally large scale but newer Marcellus assessment project, similar project scale and rewards when evaluation is complete. We're very mindful of the current environment but realize we are different. For example, over the next five years, at the current future strip price for natural gas, we can fully fund $1.1 billion a year in capital expenditures and double our production, while generating in excess of $1 billion of free cash. And we don't need to sell equity assets or increase debt to achieve this. And we think we're at the market trough, and natural gas pricing only improves. While driving in this morning, heard that GM is starting a roadshow for the sale of equity to repay the government and others. Their theme is Built for Profit, a message they can make money in North American market unit sales of 10 million units in a market that is currently at 12 million and growing. If there ever was an energy company built for profit, it's Ultra Petroleum.

Now, I would like to ask the operator to open up the lines for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question today comes from the line of David Tameron. [Wells Fargo Securities]

David Tameron - Wells Fargo Securities, LLC

Mike, can you talk about '11 and '12. I have put this in my write-up this morning but noticed you didn't reiterate that 20% for '11 and '12 like you had in previous press releases. Can you just talk about your outlook right now, given where gas prices are?

Michael Watford

Sure, David. We just elected we don't go to our boards for formal approval of the capital budget till February of next year. But given that, a number of other companies have final board approved capital expenditures budgets for 2011 out there. We didn't want anyone to think that our rough three-year plan and forward estimates was approved by the board or official in any way. We did that early in the year to provide direction and give folks some context where we think we're going. Having said that, we're not trying to back away from $1 billion, $1.1 billion capital budget 2011 or the 20% growth in production. We just want to afford our board the opportunity to opine as to what the opinions are what the approval is going to be. At the same time, we have a new player in Marcellus with Shell and we spent $5 billion to approximate Ultra's position there. And we need to give them time to work through what they're doing. Right now it looks like both Anadarko and Shell are going to have a significantly greater projects or larger CapEx, more wells, more production plan there in 2011 than what we’ve earlier had our projections. We've got to work that in and see what we want to do with it and hatch it up with our Wyoming assets, which gives a balancing effect but no way are we walking away from previous estimates.

David Tameron - Wells Fargo Securities, LLC

As I think about these, obviously you’ve seen Exco, Quicksilver, how do you think about assuming obviously there's frustration on your end with your stock price. How do you think about monetizing, or what are different avenues I'll just leave it open and let you take that wherever you want it.

Michael Watford

I’ve got to get a new CFO with bigger pockets, I think. Clearly, – I mean we just finished a strategic review this week with our board -- our board meeting, are looking at the two assets we have, looking at a different growth profiles and how much CapEx we'd like to invest in each and came away with, we're very bullish on our asset mix, we're probably more bullish now given a very weak gas price environment. Clearly there's no refection of net asset value, the pre-occupation with cash flow multiples and those that have higher multiples should somehow have lower multiples doesn’t make much sense if you create value. No doubt that our assets are very profitable. We're on a ramp up in terms of production profile. If you look at that, that PB 10 timeline as to, maybe 15 years after giving it value, we actually create value whatever gas price you want to use as we move forward (inaudible). So given that we think we're in a trough of pricing and that we're only going to be more valuable tomorrow than we are today, we understand why folks decide to take themselves out in public market. And given that we've never done equity offering, and the debt we can go after is private debt, at this point in time, because the market strategies, we can -- with lower interest rates, we are doing that, and that’s proving to be correct for us. We don't really any deal that’s public from that standpoint and use our stock as consideration in sort of acquisition. We're giving all this thought, we're certainly looking at it, and we just have such a very high level of undeveloped properties in our asset base that makes it very difficult to do traditional LBO. But we're certainly attuned to trying to do things to – just in growing shareholder value.

Operator

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

Brian Singer - Goldman Sachs Group Inc.

As you've tested and gained confidence in 80-acre spacing in the Marcellus, have you seen any communication between wells and ultimately when you talk about upside to your 3.75 Bcf type curve, should we still expect that at 80 acres spacing?

Michael Watford

80 acre spacing, it's a function of lateral length as well as well space. So it's hard to address that directly. But our micro-seismic data is just one pad. But we're tending away from 500-foot spacing. We're going to be trying 750. If I just take wells lateral space of 750 feet, and you assume it's a 4,500 foot lateral, that's right at 80 acres and that – we are starting to feel pretty comfortable with that.

Brian Singer - Goldman Sachs Group Inc.

And so I guess that is -- is that consistent with what you've been drilling where you have seen the stronger-than-expected results relative to your 3. 75 Bcf type curve, or is that tighter relative to what you've done?

Michael Watford

Pretty consistent with what we've seen to this point.

Brian Singer - Goldman Sachs Group Inc.

And then secondly, Mike, I think you mentioned there you highlighted that you are underlevered. Can you talk to how comfortable you are increasing leverage to either fund continued growth or acquire an existing or new area?

Michael Watford

We're probably going to be optimistic and rather be an acquirer than a seller in the market trough. So we have a fair amount of dry powder as Mark would suggest. We have the opportunity to grow the business pretty dramatically over next five years while staying well less in cash flow over a five-year period in today's low five-year strip price. So that -- it means probably we have more dry powder we suggest we have. I think we're just going to be optimistic and keep our eyes open. It's hard to argue for acceleration our gas price environment. And beyond what we already have. More so I think that there's no need for us to grow any faster. Just try to look -- there’s more opportunities in Marcellus or whatever it is.

Brian Singer - Goldman Sachs Group Inc.

Do you think if growth isn't going to be accelerated for reasons you mentioned, is the balance sheet in '11 enough for you to worth considering increasing leverage for the purpose of buying back stock or putting out a dividend or any other, anything else like that?

Michael Watford

I'll let Mark comment in a second if he wants to. It's hard to add leverage to buy back stock. It's very difficult especially when you're in a market trough. We're pretty conservatively run company, so I don't see that happening in large-scale manner. So the share repurchases you see out there now have to do with asset sales and larger amount of cash coming back and get back to in buying value stock. So I don't think we’d go there. We are considering in times some sort of a dividend, we think that a dividend policy. We believe in returning cash to our shareholders. Historically, we're under half a billion dollars share repurchases. And we're looking at possibly dividend program or ongoing share repurchases going forward, but not in a way where we lever up to achieve that.

Operator

Your next question comes from the line of Marshall Carver. [Capital One]

Marshall Carver - Capital One Southcoast, Inc.

You've talked positively about your studies on the Geneseo and Utica. Any plans to test those in the next few quarters?

Douglas Selvius

We don't have any well design in the works right now. We're still in the evaluation stage. But I can say without going into too much detail is that for the handful of parameters, technical folks like to look at when they are evaluating, generally, that's been very encouraging. Maybe save that question until next quarter, we'll have a little more information. We're encouraged by what we see right now.

Michael Watford

Marshall, I'm not telling him, though.

Marshall Carver - Capital One Southcoast, Inc.

I agreed 80-acre downsizing would be encouraging, did you see anything on the 50-acre test, did you think that the 50 acres wouldn't work, or do you have a comment on that versus 80-acre spacing?

Brad Johnson

Marshall, this is Brad Johnson. We just conducted a pilot on our State track 815 where we were four wells. I'll repeat also as Doug mentioned earlier that the early analysis indicates that we had very effective treatment of the rock of our frac staging. And we're awaiting production there to further assess effectiveness of 500 foot laterals.

Marshall Carver - Capital One Southcoast, Inc.

So you wouldn't rule out 50 acres at this point, you just need more data to make sure it would work?

Brad Johnson

It’s way too early to rule that out. We're about to embark on a pilot at 750-foot offsets. If you look at offsets, you look at lateral lanes, you look at size of your fracs and spacing your fracs, there's a number of parameters that (inaudible) is the ultimate optimum development scheme. We're aggressively pursuing all of those options, if you will.

Michael Watford

I think part of what Brad is trying to say which he said were directly yesterday was that you may have smaller fracs and longer laterals than maybe that 50-acre space. We haven't optimized yet.

Operator

Your next question comes from the line of Nicholas Pope. [Dahlman Rose & Company]

Nicholas Pope - Dahlman Rose & Company, LLC

One, when you look at the CapEx budget I guess that your showing for the full year, it seems to imply a little bit of a drop there in the fourth quarter from where we were in the third quarter. Is that associated with kind of the slow down or the shell ramp up in activity there, is that what the difference is in CapEx what we're seeing?

Michael Watford

It’s the -- I'd say (inaudible). It's a transition, and it is typical of anyone if you make a large acquisition and buy an operating company, there will be transition as you move in and learn more about it. Then you want to put your own safety and operational procedures and practices in place. And we've seen Shell did that before when they joined us in Wyoming in 2001, 2002, and they bought a big position there, and it's normal. We just modeled it to be a little shorter. And we are involved in that, but we’re still going to hit all our production targets, hit all our – what we said we’re going to do in terms of earnings and cash flow. But yes, the slowdown in CapEx is attributable to that.

Nicholas Pope - Dahlman Rose & Company, LLC

And then I guess looking at Pinedale drilling, I know you've talked in the past about kind of a perfect Pinedale well. And it seems like your sitting here with spud to TD 14 days, rig release to rig release of 17 days. I mean where do you think – I guess two questions, where do you think like kind of that optimum perfect well is, kind of knowing what you know now? And when you look at the cost of the Pinedale, how is that $4.6 million and the change going lower to the $4.6 million per well. How much of that is associated with being able to drill faster, and what are the components you are seeing in terms of cost changes that are kind of moving that cost down right now?

William Picquet

In answer to the first part of the question, you previously were talking about a 10-day well being our target and we very recently, matter of fact, this week, we said that perfect well, we drilled one in slightly over nine days. Our record is nine days, one hour something. And we're seeing average Q4 drop well below that 14 day number right now. So I'm not sure exactly what perfect is. We'll take another look at what we think about that or re-establish what perfect is. And as far as impacts on costs are concerned, it continuously benefits from the efficiencies working into our operations. As time does to equate to lower cost per well. But we're also seeing cost pressure, cost of services like everybody else is seeing. We're offsetting that upward cost pressure, that 4.6 number going a little lower. As long as realize those efficiencies, not seeing any (inaudible) cost of services, what the future holds on that one, we don't know yet. Efficiencies are having that downward pressure impact offsetting that upward pressure on the cost.

Operator

Your next question comes from the line of Subash Chandra [Jefferies & Company]

Subash Chandra - Jefferies & Company, Inc.

Mike, on the Marcellus, is there an opportunity to pick up more operated acreage, stuff that you actually would buy or is sort of the nearby potential pretty much locked up by folks who want to operate versus those who might have popped before and be willing to flip?

Brad Johnson

This is Brad Johnson. There is opportunity to grow on our operated plan standpoint position, in fact we’ve done so in 2010. We started the year at about 26,000 net acres. And we currently sit at 43,000 acres at operated areas. And there's more room to run that area as well.

Michael Watford

What's the goal of operated acreage in our five year strategic there, Brad?

Brad Johnson

As big or bigger than our other assets.

Michael Watford

Part of the attractiveness to additional acreage acquired up here, nearby, fee, private acreage, as well as large amounts of state acreage, and got even success with Anadarko in a rather large oil source negotiation of dead acreage here, and the Anadarko operators were also trying to achieve some of them on their own, so I think we are going to be able to have substantial growth to our operating position in 2011, 2012.

Subash Chandra - Jefferies & Company, Inc.

Do you have an opinion in Pennsylvania politics? I mean it looks like a lame-duck administration, and change at the, top but the last thing was done was putting some prohibitions on further leasing of state acreage, at least in the forest part. So what is your sort of on the ground interpretation of what's going on, and what changes do you think you might see, come inauguration, a new government?

Michael Watford

First almost that was 2 for 2 in my political contributions with the governor and senator there in Pennsylvania winning the right ones. I think that the government elect pledged in his campaign rhetoric to not have a severance tax in the (inaudible) business and got to be very sensitive to regulations frankly on the regulatory side, make them work with industry and I think he will do all that. So I think the current governor’s frustration in not getting the severance tax he wanted and therefore his injective order on a moratorium on some of the state acreage I think that will be short-lived. I think the regulatory environment, bill can jump in on this, in Pennsylvania is adequate, I think the continuous strength in that additional staffing and consistency, what we really want consistency in rules from one area to the other that we see is different. And I think Mr. Corbett is tuned to that, I think as he changes from the previous administration, like Corbett versus Governor Randall.

Marshall Smith

Let me add a couple of comments on the predictability on the regulatory, as Mike mentioned, added capabilities. What that's doing is helping for us timing on permit approval processing, administrative side activity and making that process more predictable.

Subash Chandra - Jefferies & Company, Inc.

Can that capability be sustained without a severance tax? So a new source of revenue versus trying to divert pieces of existing revenue streams?

Marshall Smith

I think that what we'll see ultimately, the new administration, first will be absent budget items, I'm not sure that's going to necessarily impact what we’ve seen as part of the recent shift in capability on the regulatory side because I think they're very committed to a robust regulatory function as oil and gas is concerned. We didn't expect that to…

Brad Johnson

Subash, when you're looking at that, you can’t overlook the fact that Pennsylvania has an existing state income tax, that for example, Wyoming doesn't have. So with the ramp up of produced volumes, the state’s going to benefit from those incremental income taxes.

Marshall Smith

I don't think any of the severance tax offsets the cost of regulation, if that's all he wants service tax for, that’ll be a pretty low one, like our state income tax will more than cover that.

Subash Chandra - Jefferies & Company, Inc.

And the Marcellus Lateral placement, that you referred to a few times, is that specifically the lower Bakken or what else is going on?

Douglas Selvius

This is Doug, I’ll address that. I believe you meant to say lower Marcellus. What we've been learning through our micro seismic and some of our regional studies of well performance, we’ve kind of been cross plotting that stuff with (inaudible) and so forth. We’re targeting – we think staying low is better. We don't want to get too high in the lower Marcellus for a couple of reasons. It appears you frac out a zone a lot more easily and your contribution, your well performance is a little bit lower. We are now tending to stay in the lower half of the lower Marcellus.

Subash Chandra - Jefferies & Company, Inc.

With all the shift in the focus for Pennsylvania, regulatory our environmental stuff, are there any sort of lasting issues and new issues in the Wyoming side other than maybe sort of the low intensity type conflict, that’s probably again -- that continues everywhere but anything to look forward to in the next year or so?

Marshall Smith

The decision being in place for as long as it has is nothing but confirm the predictability of Pinedale and that project is going to be regulated. So what it's doing is providing a path as far as development activities are concerned, a very predictable regulatory environment.

Operator

Your next question comes from the line of got Don Crist.

Don Crist - Johnson Rice

Can you talk a little bit about your infrastructure build-out in the Marcellus and I'm assuming that the large ramp up in wells that came on this quarter or in the third quarter in October are a factor of that, can you kind of tell us where you think your fictional backlog should get to and when that should happen?

Brad Johnson

We've made significant strides in our infrastructure buildout in 2010. As of right now, our tap capacity for example is half a Bcf a day, and that will exceed one bcf a day by year end. We’ve been strategic in building out our structure, so that we can get our wells online. if you noticed in the numbers I stated earlier, we actually brought more wells online than we drilled, will also occur in the fourth quarter of 2010. I like that trend to continue on 2011. We will certainly fiddle that inventory and get more wells online

Don Crist - Johnson Rice

And in regards to the Shell delays with swapping out rigs and frac crews, do you think that this is going to impact your 2010 exit rate forecast, or do you think that there should be just a minimal impact and that should be made up early in the first quarter or sooner?

Michael Watford

The reduced activity is accounted for in our accounts. And as mentioned earlier, our average now for the fourth quarter we're expecting to be 80 million a day, previous quarter was 90 million. So that delta is attributable to the slowdown.

Don Crist - Johnson Rice

But you don’t – I mean you said that should be made up in the first quarter or with other backlog wells coming on, or it shouldn't be a real big deal for us right?

Michael Watford

We don't consider that to big of a deal. We think it's going to fall into 2011 and wells continue to perform at or above expectations. I think the overall takeaway is with the increased activity that on a preliminary basis both Anadarko and Shell are suggesting for 2011 have robust Marcellus direction.

Operator

Our next question comes as a follow-up from Noel Parks. [Ladenburg Thalmann]

Noel Parks - Ladenburg Thalmann & Co. Inc.

Just following up on the Marcellus and the infrastructure picture there, looking forward, more on the longer-term sort of, what sort of volumes you might ultimately see out of the play in the region, have you changed your assumptions to any degree around just what your transportation and gathering costs might be out of the play. I'm thinking in particular that the big pipeline companies, for example, have so many places they can put their capital these days with so many new shale plays coming online. I think I'm just wondering if you through any bigger slice of the pie is going to need to go to them from the industry to entice them into the Marcellus and keep building out in a timely manner.

Michael Watford

We have a different strategy in the Marcellus than we do in Wyoming. In Wyoming, you have basically stranded gas assets that you have to build more infrastructure to and that's why we supported REX and FTC Ruby in building financial current, et cetera. Marcellus where you are surrounded by many interstate pipelines, to us it’s a question of interconnecting your various gathering systems to a myriad of interstate pipelines, and a number of those pipelines will end up with capacity additions. But we don't want to loose sight of the fact that the customer, the gas utility holds the transportation in many of those online, Eastern U.S. pipeline. So if you pay for expanding capacity for transportation, it doesn't get you to being – you have to make a deal with an end user. Our preference right now is to have a diversity of pipeline versus the end customers, and interconnect with five to six different interstate pipelines there from all the various gatherings systems that we're going to end up in, our operated one, the Shell operated one, and the Anadarko operated one, give us multiplicity of markets.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I guess more specifically on the processing plant side, you said the same thinking applies there than you just don't expect there to be problems with capacity for the longer-term.

Michael Watford

We have dry gas in Marcellus, where you don’t need processing. And in the Wyoming we need processing and we've done a good job of causing additional processing plants to be built over the last decade.

Operator

Your next question comes from the line of Anil Sharma [ph] .

Unidentified Analyst

My question is about the Marcellus development. So if shale continues to grow slow, will you guys think of adding additional rig on the operated part of the acreage and does the GOA with Shell gives you guys room to propose wells -on their operated acreage and if so would you guys consider putting Shell in a position where you guys are proposing wells on their operated acreage.

Michael Watford

I'm going to disagree with your opening statement that our position (inaudible) the slow. They didn't go out to spend $5 billion to go slow and sit on their hands. This is just a transitional window and it's coming to an end, so there is no indication at all current activity as they begin to ramp or their plans that they are going to – plans for 2011 that they are going to slow. As to the other issues, we have a second rig operating here, but we’re really in an evaluation and assessment mode, not in a developmental or maximized production mode at all. We're still trying to get our arms around, where the best parts of the field are, the best way to drill the well, how we can bring some efficiencies, how to better understand it, and we are going to drill wells in different areas, and not all of them are going to work, and some of them are going to get far off field and not having work and have stranded wells where will build a gathering system too, a size of gathering system based on what we find in wells. I don't think this is a time where we want to add additional rigs for operated area. Of course in our operating agreements with the Shell or anyone else, we can propose wells. Shell’s a good partner, so I don't think we will have to resort to anything like that.

Unidentified Analyst

Do you guys sit down with their operating teams on the drawing board and chart out the plan for 2011 how and where you guys are going to drill the wells?

Michael Watford

We have frequent meetings with Shell and Anadarko, yes, we have work with them very closely.

Operator

Your next question comes from the line of David Heikkinen.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

As you think about Wyoming versus Pennsylvania, Mark gave us expected realization, can you walk us through operating expenses, transportation, DD&A as we think start thinking about net income and cash flow margin in each region?

Michael Watford

On the revenue side, we're suggesting 90% of Henry Hub from Wyoming and 103%, 104% for Marcellus. On LOE, we’re $0.21, $0.20 in Wyoming that we are now, $0.25 in gathering, $0.24 in gathering. And then we have corporate transportation costs with REX which we allocated a Corporation we can allocate the Wyoming assets in any way we want to which is $0.29 and now these volumes will continue up. And you have severance tax in Wyoming, about less than 12%. On the Marcellus side, I think we have no gathering cost this time, we are building gathering infrastructure as part of our capital cost and may revisit that at a point in time. Our LOE is $0.23, $0.24, it’s sort of now through volume plus a fixed charge. We don't have a lot of wells that have been on for many, many months, we feel good about. You have to look it through September, it was $0.25, $0.26. And there's no service tax currently. There is a state income tax there that should be allocated to it (inaudible).

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

And then just thinking about seven rigs running now, you have one operated rig, can you – what is the Shell and Anadarko operated rig count?

Brad Johnson

Currently one rig Ultra, five rigs Anadarko and 1 rig.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

And Shell well is running three rigs, I am kind of thinking about. Probably a reasonable guess is that it would be at least five [ph] at a minimum and maybe beyond that.

Michael Watford

(inaudible)

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Just thinking about your comments around acquiring an existing or new areas and in the new area side with relatively small staff and kind of the size of the company like your first deal, you did it, Ultra way back and it was a corporate transaction, corporate transaction on the table are being considered?

Michael Watford

There's nothing being considered as we speak, but certainly we’ll consider corporate transactions. I don’t see any reason not to.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Nothing active. Using your stock or you think about it.

Michael Watford

(inaudible) for Anadarko today.

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

On the Pinedale rig count, just thinking about with the record decision and efficiency gains, how many growth wells do you think you'll drill per year next year as well?

Michael Watford

Actually it probably will be something very similar (inaudible).

David Heikkinen - Tudor, Pickering & Co. Securities, Inc.

Okay, on production about 230 gross wells.

Operator

Your next question comes from the line of Eugene Lipovetsky .

Eugene Lipovetsky - Zimmer Lucas Partners

On a 5-acre basin pilot that you're engaging in the Pinedale. First, can you comment on what sort of expected EUR you're anticipating realizing from some of those wells where you mentioned you're getting (inaudible) in IPs? And as a follow-up to that, also comment how much 5-acre wells do you expect to drill next year.

Brad Johnson

Regarding our five acre program, year to date, as I mentioned (inaudible) You might expect we do incorporate a combination of incremental recovery and some level of acceleration (inaudible) . We impose a haircut if you will as we down space to 5 acres, implement that in our pre drill expectations. what we’re seeing the results are there are well that are meeting those expectations and I want to emphasize that wells are validating, in fact they are touching additional gas and recoveries will go up in Pinedale with the 5 acres.

Eugene Lipovetsky - Zimmer Lucas Partners

You mean the recoveries will go up on a per well basis or on a program wise basis?

Brad Johnson

On an aggregate basis the entire resource, the recovery factor at Pinedale Field is going to go up.

Eugene Lipovetsky - Zimmer Lucas Partners

Do you think a 5D curve is reasonable to use a five-acre down spaced well that IPs at 7.5?

Michael Watford

On a go forward basis, our UR spud wells are 6 BCF, as we done space, that UR is going to go down as you implement haircut process if you will. I think you see less on the IP but you will see more of it over time in the decline rate. So you end up with all over our wells.

Operator

The next question comes as a follow-up from David Tameron. [Wells Fargo Securities]

David Tameron - Wells Fargo Securities, LLC

On stock price, obviously as I mentioned earlier frustration on your end, if you're undervalued as you think you are, why wouldn't you just go ahead, and slowdown CapEx and go on and do a big share repurchase program?

Michael Watford

I'm not convinced that the share repurchase program would make my stock price move. That's why. I think the money flows into the sector, especially the dry gas sector, is pretty low. And even though we tried to differentiate it ourselves, the fact that we have low costs and make money, so perhaps if you are focused on profitability you have a different answer as opposed to just throwing out the baby with bathwater I guess is what they say. So we wouldn't be – we’re not just convinced that would get us where we want to be in the time we there is value to be created. We also see that even if long-term modest gas prices, we value, we have returns at $4 gas and our project areas that personally I’ve loved being able to invest in that, will have that in my personal portfolio. So it's hard for us to not go forward with a reasonable capital program.

Operator

We do have one more question as a follow-up from Anil Sharma [ph] .

Unidentified Analyst

Mike, would you consider bookings some the 5-acre pud location in Pinedale for the year end reserves this time?

Michael Watford

I'm going to help Brad with this one. We're blessed with far more reserves than we annually booked in our official proved reserve report. And if we drill the 5-acre well, we will be able to include the PDPs. If a 5-acre pud well (inaudible) that fits in where are going to book wells year end 2010, we will certainly consider. We don't look at wells, whether it’s 5 acres, 10 acres, 20 acre, 40 acre wells anymore, we just kind of look at how many wells and area. So we would just go about our normal business of trying to match development capital, reserve additions so that we have an F&D cost which it is closer to our depletion rates, which we think is more honest, more factual, and then the excess which is still set in that unbooked category which Brad calls technical puds. Those I think total grew by a true SEC measure, year 2009, was 6.7, 6.8, 43.9 [ph], so there's a big delta there, wouldn't see that delta decrease here in 2010.

Unidentified Analyst

So we can see some 5-acre puds this time in the year end reserves possibly.

Michael Watford

Yes.

Operator

I'd like to turn the call back over to the Mike Watford for closing remarks.

Michael Watford

Thank you. We appreciate your time and interest in the Ultra story today. And if you have follow-up questions or comments, please don't hesitate to give Kelly or Julie a call. If they're not available, you can give Mark or myself a call. Thank you.

Operator

Thank you very much, sir, and thank you ladies and gentlemen for your participation in today's conference call. This concludes your presentation for today. You may now disconnect. Have a good day.

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