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Ultra Petroleum (NYSE:UPL)

Q4 2010 Earnings Call

February 18, 2011 11:00 am ET

Executives

Michael Watford - Chairman, Chief Executive Officer and President

Kelly Whitley - Investor Relations Manager

William Picquet - Vice President of Operations and Vice President of Operations for Rocky Mountains

Douglas Selvius -

Brad Johnson -

Marshal Smith - Chief Financial Officer

Analysts

Brian Singer - Goldman Sachs Group Inc.

Leo Mariani - RBC Capital Markets, LLC

David Tameron - Wells Fargo Securities, LLC

Joseph Allman - JP Morgan Chase & Co

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Great day, ladies and gentlemen, and welcome to the Fourth Quarter 2010 Ultra Petroleum Corp. Earnings Conference Call. My name is Thelma, and I will be your coordinator for today's event. [Operator Instructions] I would now like to turn the presentation over to Ms. Kelly Whitley, Director, Investor Relations. Please go ahead.

Kelly Whitley

Thank you, Thelma. Good morning, ladies and gentlemen, and welcome to Ultra Petroleum's 2010 year end earnings conference call. On the call with me this morning to discuss 2010 results and reserves and our 2011 guidance are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Senior Vice President, Chief Financial Officer; Bill Picquet, Senior Vice President, Operations; Brad Johnson, Vice President, Reservoir, Engineering and Development; and Doug Selvius, Director, Exploration.

Before turning the call over to Mike, I'd like to cover a few administrative items. First, this call will contain forward-looking statements that involve risk factors and uncertainties detailed in our SEC filings. All statements other than statements of historical facts included in this call are forward-looking statements.

Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found in our 10-K and other filings with the SEC available on our website. SEC permits oil and gas companies in their filings to disclose proved reserves, probable reserves and possible reserves. References in this call to 3P reserves include estimates from each category of reserves are forward-looking statements. Once again, investors can find the disclosure in our 10-K and other filings with the SEC available on our website.

Second, Ultra will be participating in several conferences over the next few weeks. To name a few, we will be at the Raymond James Institutional Investors Conference in Orlando on March 7 and the Howard Weil Energy Conference in New Orleans on March 30. Please visit our website to view updated presentations and listen to webcasts.

Now let me turn the call over to Mike.

Michael Watford

Thanks, Kelly. Good morning. Thanks for joining us. With me today to discuss our year-end results are Mark Smith for the financial update; Brad Johnson on reserves; Bill Picquet to discuss Wyoming operations; and Doug Selvius, our Pennsylvania results.

Let me start by noting that 2010 was a good year for Ultra Petroleum. We delivered double-digit growth in reserves, production, cash flow and earnings. We enjoyed the largest capital budget in our history, that allowed for the acceleration of development of a second core area. Budget was funded from internally generated cash flow and inexpensive debt, no equity.

We maintained our healthy margins and earned superior returns. Of particular note is our net income margin of 31%, a return on equity of 39%. We grew our reserves in volume and value. A development program in the Wyoming Lance play is hitting on all cylinders, as we increase productivity and lower cost.

Our down spacing efforts have been well received, with positive resource and financial impact. In the Pennsylvania Marcellus play, our evaluation and exploration effort has gained scale and understanding. We now control 260,000 net acres in the fairway and our ultraconservative third-party reservoir engineering firm estimates in excess of 5 trillion cubic feet of natural gas reserves net to Ultra, on only 50% of the acreage. And again, I think we've lived up to our reputation as the low cost producer.

With that, let me ask Mark to share our financial results.

Marshal Smith

Thanks, Mike, and good morning. As Mike outlined and as you have seen from our press release, we had a very good 2010 despite weakened natural gas prices during the year. We saw strong performance in the field, with ongoing improvement in drilling efficiency, record production levels and reduced cost.

In terms of natural gas price for the year, Ultra’s realized corporate natural gas price before the effective hedges, increased 24% year-over-year and registered 98% of Henry Hub.

Operating cash flow per share was up 18% year-over-year at $4.96 per diluted share, with adjusted earnings up 17% to $2.18 per diluted share. On a balance sheet perspective we continue to be very well positioned. As of year end, we had $70.9 million of cash and cash equivalents on hand and $1.56 billion in outstanding senior debt with a weighted average cost of 5.6% and an average life over nine years.

Our debt capacity is excess of $2.5 billion, providing us with roughly $1 billion in unused senior debt capacity, and we continue with our strong organic growth, while maintaining our industry-leading margins and returns, maintaining our financial flexibility.

For 2010, our production was up 19% to a record 213.6 Bcfe. Again, this was an all-time high for the company. Bill will address our operations in a bit.

Although natural gas prices remained at relatively low levels through calendar 2010, our average unhedged gas price increased 24% to $4.31 per Mcf compared to prior year levels of $3.49. Additionally, our natural gas hedge positions improved our average realized gas price by another $0.57 to $4.88 per Mcf. As a result of our increased production levels I discussed earlier, revenues, including effects of our hedges, registered $1.1 billion for the year.

Corporate lease operating expenses for 2010 registered $0.90 per Mcfe, compared to $0.85 during 2009. This increase was a result of increased severance and production taxes due to higher average year-over-year natural gas and oil prices, offset in part by reductions in our unit production costs.

Transportation costs amounted to $65 million during the year or $0.30 per Mcfe on our total production volumes, down from $0.32 per Mcfe during the prior year. Our DD&A rate registered $1.13 per Mcfe for the year. General and administrative expenses on a unit basis were flat year-over-year at $0.11 per Mcfe, while interest costs registered $0.23 per Mcfe.

The net effect of all these factors was $2.68 per Mcfe in overall corporate cost, one of the lowest in the industry. With continued focus on operational improvements and cost reductions, our cash, field level cost decreased to $0.45 per Mcfe, a 6% decrease over prior year levels.

Operating cash flow registered $764.5 million for the year providing a 70% cash flow margin. Adjusted for the non-cash unrealized gain associated with the mark-to-market position on our hedges, we recorded adjusted earnings of $336.3 million for the year, providing $2.18 in adjusted earnings per diluted share and a 31% net income margin.

In terms of returns for the year, our return on average capital employed was 17%, which compares very favorably to our weighted average cost to capital of roughly 9%. Our return on average equity for the year was 39%.

Cash provided by operating activities during the year amounted to $824.7 million. Investment activities for the year were largely comprised of $1.2 billion in oil and gas property investments, together with $341.8 million in net acquisition costs for additional acreage in the Pennsylvania Marcellus Shale, as Mike discussed.

Additionally, we invested $76.7 million associated with gathering systems, as we finalized our liquids gathering system in Wyoming and built out infrastructure in Pennsylvania.

For the year, net cash provided by financing activities totaled $761 million, consisting primarily of just over $1 billion from our senior note offerings in the first and third quarters, offset by net repayments on our senior bank facility.

In terms of our price outlook for the remainder of the year, balance of 2011 pricing for [indiscernible] is currently indicated around 91% of Henry Hub. Dominion South for the balance of the year is indicated roughly at 103% of Henry Hub. As a result we continue to believe our corporate basis differential will run approximately 94% to 96% of Henry Hub for the year.

Moving to hedging, as detailed on Page 4 of our financial and operational press release, we have approximately 168 Bcf or roughly 71% of our 2011 forecast natural gas production hedged, through fixed price swaps and a weighted average price of roughly $5.63 per Mcf. For calendar 2012, we have about 99 Bcf hedged at a price of roughly $5.35 per Mcf.

I'll wrap up my comments by pointing out that on Page 2 of our capital investment guidance press release, we're establishing production guidance for 2011 at $245 to $255 Bcfe with a capital investment program of $1.1 billion. We'll also note that guidance for DD&A increased to $1.30 to $1.32 per Mcfe, as we've been consistent with our practice and have conservatively booked reserves in Pennsylvania, particularly with respect to our capital spending in the region. Additional detail on our outlook and guidance is provided in our press release.

And now I’ll pass it off to Brad for an update on our reserves.

Brad Johnson

Thanks, Mark. In the same manner as previous years, Ultra's 2010 year end reserve determinations include the review of every single producing well in every potential location in our portfolio.

Ultra's year reserves had been prepared in accordance with all the updated guidelines set forth by the SEC. Ultra continues to self-impose its limit of proved undeveloped reserves to those PUD locations that can be drilled within our three-year budget and planning cycle.

Ultra's year end 2010 proved reserves are 4.39 trillion cubic feet equivalent. Proved developed reserves are 1.74 Tcfe and represent 40% of the total proved reserves. Proved undeveloped reserves are 2.65 Tcfe. With corresponding future development costs of $2.9 billion, the development cost of our PUD reserves is $1.10 per Mcfe.

2010, the company posted another year of outstanding reserve growth. Reserve replacement was all organic growth and totaled 324%. Finding and development cost for drilling activities were $1.48 per Mcfe, and the all-in F&D costs were $2.28 per Mcfe. Ultra chose to remain consistent with past years by limiting its PUD pool. And the company also chose not to book Pennsylvania PUDs this year. Instead, we look forward to the reserve additions of our 2010 Pennsylvania investments in future years.

Year end proved reserves for 2010 were determined with a 12-month average wallet price of $4.05 per Mcf of gas, $68.93 per barrel of oil. For our 1P proved reserves 99% of these volumes are located in Wyoming. For year end 2010, the company's ratio of PUD locations to its proved undeveloped locations is 0.64:1, a slightly lower and more conservative ratio than what we posted last year.

Our PUD reserves remain limited to our Wyoming assets. We did book 146 Bcfe of proved developed reserves in Pennsylvania, those wells producing at year end 2010. And we have another 437 Bcfe of technical PUDs that we will save for another year.

For year end 2010, Ultra's 2P reserves totaled 10.7 Tcfe. Within the probable category, we have 1.9 Tcfe of technical PUDs. Please recall that Ultra's technical PUDs are those bookable, economic PUD locations, that are scheduled beyond our three-year planning and budgeting cycle and are therefore included in our probable reserves.

Ultra's 3P reserves are 15.9 Tcfe at year end 2010, a 9% increase from a year ago. The increase is due to our continued growth in our Marcellus assets. Pennsylvania, we added almost 1,400 locations to our 3P database. Our new total is just over 3,000 future horizontal Marcellus locations.

Each of these locations have a planned drilling unit and are incorporated into our development plans. These locations represent about half of our Marcellus acreage captured at year end 2010. We expect to add additional 3P reserves in 2011, as well as elevating the quantity and quality of our Pennsylvania proved and probable reserves, as appropriate.

Ultra's 3P reserves are reported using a $6 Mcf gas price and a $68.93 per barrel oil price. At these prices, pretax PV-10 value for our 1P reserves, $8.6 billion. The 2P reserves, this value is $13.1 billion. And for the 3P reserves, the pretax PV-10 value is $17.1 billion.

In 2010, the company completed its Pinedale five-acre pilot program in the Riverside area, by drilling 60 five-acre pilot wells. Initial production from Ultra's pilot wells brought on this year averaged 7 million a day. By the end of 2010, over 200 wells had been drilled in Pinedale at five-acre density.

The performance of these wells, coupled with Ultra's comprehensive analysis of incremental recovery, associated with these five-acre density locations is presented to the Wyoming Oil and Gas Commission last week in Casper, Wyoming. The commission approved Ultra's filing, which immediately provides for five-acre density development in nearly all of Ultra's position in the Pinedale Anticline.

As of today, if Ultra booked all of its technical PUDs, the proved reserves would be 8.9 Tcfe, at $6 gas price, PV-10 value is $11.4 billion dollars. And the resulting ratio of PUD locations, the proved developed locations, would still be less than 1.6:1.

Ultra delivered another outstanding year of double-digit reserve growth, all organic reserve replacement of 324% and a drilling F&D cost of $1.48. Ultra's economic 3P reserve base currently exceeds 15.9 Tcfe. Ultra's reserve pipeline is full for many years to come, over 1.9 Tcfe of technical PUDs are reported at year end 2010, and another 2.5 Tcfe of five-acre wells in Pinedale are now eligible for booking with the recent regulatory approval of five-acre density in that field.

In Pennsylvania, Ultra's net acreage position grew over 50% to 260,000 net acres. Half of the Marcellus acreage considered as contingent reserves, not yet included in our 3P reserve estimates.

At this time I will turn it over to Bill for an operational update.

William Picquet

Thanks, Brad. In Wyoming, in the fourth quarter, Ultra brought on stream 59 gross, 32 net, new producing wells. For the full year 2010, we brought online a total of 247 gross, 137 net, new producing wells.

The average initial 24-hour sales rate for these new Pinedale producers for the full year was 8.2 million cubic feet per day. Ultra's operated Pinedale wells averaged 9 million cubic feet per day, while the non-operated wells averaged 6.3 million cubic feet per day. We drilled a total of 247 gross, 134 net, new wells in Wyoming for the full year.

Our overall operating efficiency in Pinedale continues to improve. Our cost performance has been excellent. We average $4.6 million per well in our operated program in Pinedale. In the fourth quarter, we averaged 12.7 days, spud to TD, for Ultra-operated wells, 19% improvement over the average for Q4 2009.

For the full year 2010, we averaged 14.2 days, spud to TD, compared to 2009's full year average of 19.7 days spud to TD. This is a 28% improvement in drill time year-over-year.

During the fourth quarter, our average rig-release to rig-release was 16 days, down 14% from our Q4 2009 average. For the full year 2010, we averaged 17.4 days rig-release to rig-release compared to 24.3 days for the full year of 2009, also a 28% improvement.

For full year 2010, we drilled 76% of our wells in less than 15 days, spud to TD. Completion efficiency in our Pinedale operations has also been outstanding. During Q4, we continued our fast-paced completion activity in our operated frac program, drilling a total of 39 new wells.

During 2010, we completed a total of 174 wells in our operated program, averaged over 26 frac stages per well on Pinedale for the full year 2010, versus 25 stages per well during the full year in 2009. We averaged $70,000 per stage during the full year 2010, compared to $4,000 per stage for the full year in 2009.

Continued improvement and efficiency in our drilling and completion activities is producing overall cost improvement on a per well basis in our Wyoming operations. Our year-end average cost per well continued the downward trend, even though we had more fracs per completion, even with upward pressure on cost of services.

In Q4, we completed the installation of the second phase of our liquids gathering system. During 2010, we invested over $28 million of capital in this important project at the timing commitments set in the Pinedale SEIS Record of Decision and now move essentially all of our condensate and produced water within the field in pipe rather than using trucks. Over time, this will result in improved efficiencies in our production operations.

In summary, we continue to find ways to improve our operating efficiencies in all phases of our Pinedale operations. Our drilling completions and production operations aims are very focused on these efforts and continue to produce results among the leading operating teams in industry.

I'll turn things over to Doug now for an update on our Pennsylvania activity.

Douglas Selvius

Thank you, Bill. I would like to provide a summary of our 2010 drilling activity in Pennsylvania and a brief preview of our 2011 plans. I will also update our leasehold situation and talk briefly about plans for testing a second prospective exploration target.

During the fourth quarter, Ultra participated in drilling 37 gross, 24 net, horizontal Marcellus wells and 27 gross, 14 net, vertical wells in the company-operated and JV areas. This brought our total activity for the year to 116 gross and 72 net horizontal wells.

Our vertical activity, primarily focused on lease maintenance in the Shell JV, totaled 61 gross and 31 net wells for the year. Dating back to Ultra's entry point in the play in early 2009, we have now participated in 154 gross and 87 net horizontal wells.

For the full year, we turned 77 gross and 51 net wells to sales. A large percentage of those wells, 33 gross and 21 net, came on in the fourth quarter as our JV program started to hit their stride. At year end, Ultra's total producing well count in the Marcellus was 92 gross and 52 net wells. The average 24 hour IP for all of these wells was $6.2 million, just under our 2010 average of $6.4 million. We exited the year producing a net 90 million cubic feet of gas per day.

Lateral length drilled during the year varied somewhat by area. To the north, laterals averaged 4,100 feet. To the south, in the deeper part of the play, laterals averaged 5,655 feet. We define lateral length, by the way, as that distance from the first lower Marcellus penetration to total depth of the well. It is worth noting that we just drilled our longest lateral in the field, at the Pierson #3H, a total lateral of over 6,700 feet and all of it was in-zone. This is an area where we've experienced some good results with shorter laterals, so we're looking forward to the results of this well when it gets completed in early April.

Last quarter, we commented about some changes we were implementing to reduce drilling costs in our company-operated program. Those changes were primarily focused on well design, lateral placement, jiva [ph] steering, and the results achieved were impressive.

During the first three quarters of the year, our drill time from kick-off point to total depth averaged 10.8 days. The fourth quarter, with those implemented changes, our drill times dropped in half to 5.4 days.

As a result, our average cost to drilling case a horizontal Marcellus well dropped from $2.1 million in the first three quarters to $1.5 million in the final quarter. Unfortunately, much of this savings has been offset by significant increases in frac cost.

2011, we expect total well cost in the northern area to average $4.2 million. The south, we're expecting well cost to average $6 million. But bear in mind, those are wells in a deeper part of the basin. They have longer laterals. They typically require four to six more frac stages.

From a resource standpoint, we have now gathered information from 154 horizontal and 77 vertical wells. That data is starting to give us a very good handle on the Marcellus resource and its inherent geographic variability. Our evaluation efforts were deliberately designed to assess the resource across the majority of our acreage position. Through that process, we've identified some good development areas, some great development areas and a few disappointing areas.

Going forward in 2011, we are focused on investing our capital in the highest return areas, and we're using this knowledge to guide us. We plan to participate in 163 gross and 80 net horizontal wells this year. Those wells will be concentrated in the highest NPV areas.

These are areas where the rocks are good, average well performance is good, infrastructure is either in place or under construction, takeaway capacity is readily available. Examples of such areas are Grugan; and our Anadarko JV and Kraus; and our Shell JV. Grugan we're seeing wells with EURs above 8 Bcf and rates of return approximating 90%. In Kraus, our EURs are 5 Bcf with rates of return exceeding 70%. In areas like these that we'll be concentrating our capital in 2011.

Coinciding with this drilling program, we expect 150 to 160 gross and 75 to 80 net wells, that will be coming online this year. This is based on realistic assumptions for frac spread availability and pipeline startup dates. It nearly doubles our producing well count and starts reducing the percentage of drilled wells waiting to sell gas. By concentrating on wells and the best part of the resource, we should more than double our net production in the Marcellus this year.

Now a few words about leasehold. We entered 2010 with 169,000 net acres in the play. At first quarter, we strategically acquired an additional 78,000 acres through our acquisition of MCLs properties in Centre, Clinton and Lycoming counties, built on this foundation during the course of the year with additional unit fill-ins and bolt-on leasehold purchases.

We exited 2010, as you've heard, with 260,000 net acres. This affords us an additional 1,380 new drilling locations. Our company operated position increased from 26,000 net acres, 50,000 net. I might add, that in light of recent transactions in the Marcellus, our leasehold cost for this position look quite attractive at an all-in average cost of less than $2,000 per acre.

Now one final comment about exploration. Last quarter, we talked a bit about the Geneseo formation and the attention it was getting from industry. At that point, we were just starting to evaluate it, but we saw some things in the play that looked attractive to us.

We are now planning our first Geneseo test and hope to spud the well in early to mid-April. We're optimistic about this target, and we feel it has the potential to add significant value across a large part of our Pennsylvanian acreage position.

In summary, we're very pleased with the results we see in our Marcellus program. We are continuing to expand our knowledge base and expertise in the play, and fully expect to translate that knowledge into gained efficiencies, even better performance results, in 2011 and beyond.

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

Michael Watford

Thanks, Doug. Again, in 2010, I think we demonstrated the consistency and sustainability of our business model. We avoided the trap of profitless growth. We've always believed in making money first and growing second, our consistent growth and profits bear this out.

We continue to be ultraconservative in recognizing our proved reserves, staying true to our three-year PUD limit, while annually adding to the 3P reserve base. Of note, is the opportunity we have to book as much as 8.9 trillion cubic feet equivalent of proved reserves with a PV-10 value of $11.4 billion, all of which can be developed very economically for approximately $1.60 an M [Mcf].

2011, we again plan to deliver double-digit growth in reserves, production, to cash flow and earnings. Our 2011 capital expenditure budget is truly a bottom-up effort, with allocations to the investment opportunities with the best returns.

And now I'd like to ask the operator to open the call for questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

If we look at the $1.1 billion budget for the year, how much of that is being spent on wells that you're operating versus what your partners are operating? And when you think about the potential fluctuations in gas prices either up or down, what are the key thresholds at which you would consider increasing or decreasing CapEx?

Michael Watford

We'll start with returns. First, I think as I've talked about some of the returns in the areas that are going to get most of the focused capital expenditures in 2011, in the Marcellus set of investments. And he was mentioning returns based on a $5 gas price. So that I guess, I'm going to say that if gas prices move much, it won't have much impact there because those returns are so stellar where the concentration’s going to go. In Wyoming, we have returns anywhere from – because we’re sort of forced where we drill at given times with the rod, the returns from low of 25% of the wells we’re going to drill to a high of 50%, 60% based on the mixture, the paths we're going to sit on, again, that's all predicated on $5 gas. And so if -- and again, Wyoming, we probably are 90%, 95% of the budget up there in terms of how we spend the money. And then the Marcellus in 2010, it was probably 55% to 60% with outside operator, in terms of capital. 2011 it’ll be more, it’ll probably be a guess of 70%, 75%, but we just don't have all the file numbers as you know, for example, Anadarko hasn't finalized their capital budget for us. So for us to tell you in detail what their investments are would probably be impractical. But I don't know that gas price movement is going to change our investments short term. Obviously it’ll have an impact longer term as to what happens in the 2012, 2013 period. I think Mark mentioned, or perhaps the press release mentions, that we've already hedged maybe perhaps as much as 1/3 of our forecast production for 2012 at a $5 Henry Hub gas price. Again, at $5 gas prices we do really well with our cost structure and the assets we have. We continue with our net income margins in excess of 30% and our returns on capital of 18% to 20% returns on equity, close to 40%.

Brian Singer - Goldman Sachs Group Inc.

Can you just give us an update on the new ventures and the capital investment there? And whether you think that, that will turn to something that you can talk about later this year or whether those are projects that are a bit longer term?

Michael Watford

How about I just pass on that answer, Brian. Is that okay?

Brian Singer - Goldman Sachs Group Inc.

Can I ask a follow-up then, do you see any additional new venture opportunities within other zones in the Marcellus beyond the Geneseo you talked about?

Douglas Selvius

You mentioned Geneseo, there’s some other plays getting a little bit of attention, you probably heard Range Resources talk about Upper Devonian, the Rhinestreet, they're looking at the Utica. Last call, we mentioned that we’d looked at the Utica. We think it's got some potential, it probably is gas-bearing and prospective under our acreage, but right now, it's probably sub-economic. So really, the best additional exploration target we have is the Geneseo in our area right now.

Operator

Our next question comes from Leo Mariani with RBC.

Leo Mariani - RBC Capital Markets, LLC

Trying to get a sense of what your fourth quarter 2010 production was in the Marcellus.

Michael Watford

We can dig it out. What other question do you have?

Leo Mariani - RBC Capital Markets, LLC

I guess, it looks like, just in the Marcellus, you guys were a little bit short of your prior exit rate. Just trying to get a sense of some of the dynamics there and kind of what held you back a little, if it's access to frac crews or some of your partners dragging their feet a little bit.

Michael Watford

I think when we came out with our 2010 plan, both of capital and production, we clearly suggested greater contribution production mix from Pennsylvania Marcellus. And we didn't get there. I guess we've been broadcasting that for a while now. And the biggest piece of it is simply because Shell spent $5 billion to buy East resources. And when they acquired the company or right before the acquisition was finalized in terms of the closing, you had a slowdown by the East folks, as you expect when they don't know what happens to them next. And then you have Shell coming in and change out all the rigs and change out all the frac crews and firms. And there was probably 100, 120-day hiatus. And so we just lost that in terms of wells getting drilled, wells getting put on, getting fracked, and gathering lines getting filled, so we've lost production there. That's a negative. The positive is, that Shell's pocket books are much larger. That Shell has a very aggressive view of the upside in the assets, I think, which we share, based on some of the comments that Doug had for you. That you're going to see them spend more money and be more aggressive in 2011 and '12 as we march forward. That's the principal difference. Brad, do you have the volume numbers for fourth quarter?

Brad Johnson

Yes, I do. In Pennsylvania, our fourth quarter volume, 6.8 Bcfe.

Leo Mariani - RBC Capital Markets, LLC

I'm sorry, I couldn't hear that number, what was that again?

Brad Johnson

Yes. The fourth quarter volume for Pennsylvania was 6.8 Bcfe.

Leo Mariani - RBC Capital Markets, LLC

Just sticking in the Marcellus here. You talked about your well cost a little bit, varying between the north and the south on your acreage. In terms of how you characterize that, what percentage of your acreage is considered your north and what south, I realize there's somewhat of a gradient there though?

Michael Watford

It's very close to a 50/50 split. It might be 55 north, 45 south.

Leo Mariani - RBC Capital Markets, LLC

And is that principally depth that's characterized in the difference in well costs at this point?

Michael Watford

There's a couple of factors. Depth is of course, one of them, you’re probably 1,500 feet, few thousand feet, on average deeper from a true vertical depth standpoint. We're also drilling longer laterals, down to the south, just because it's mechanically easier to do so at those depths. And with longer laterals inherently, you've got more frac stages, so there's a number of things that push those costs up.

Leo Mariani - RBC Capital Markets, LLC

Jumping over to Wyoming, you guys obviously had a fair number of five-acre wells at this point and clearly some decent production history. Have you refined any of your EUR expectations on the five-acre wells here?

Brad Johnson

I can answer that, this is Brad. Actually, our successful pilot program for 2010, really affirmed our previous estimates for five-acre development. And we shared a lot of details with the commission last week on that. We're very pleased with that pilot program. I would not consider it refining, I would consider it affirming, or estimates of our expectations for five acres.

Leo Mariani - RBC Capital Markets, LLC

What are those EURs?

Brad Johnson

We build in, as we may have explained in the past, we build in anticipated mixture of acceleration in incremental recovery. We spoke a lot last week with the commission about five acres having roughly a 60% incremental recovery, 40% acceleration component.

Operator

Our next question comes from Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I noticed that in the financials, G&A was down nicely in the quarter and I just wanted to see if that was a onetime effect or something we could look to see recurring.

Marshal Smith

Noel, that's just you're just observing a continuing trend. And we continue to bring on more staff, as we add out on the field. But we've got – but we're rolling production volumes at a higher rate, so the unit costs are trending down.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I thought it was actually on an absolute basis that it was down. I thought it was sort of low $2 million versus about $3 million in the third quarter?

Michael Watford

While we look it here, what else do you have?

Noel Parks - Ladenburg Thalmann & Co. Inc.

I guess looking at the Marcellus and just what's going on with the different players there, just curious if you had seen much coming your way, as far as farming opportunities from other operators. I guess, my thinking was that, since so much of what you have is held by production that you have a lot of flexibility as to where you could deploy some capital. So I was wondering, I know you have a lot of acreages, but wondering if drilled or earned, if you saw any opportunities there right now.

Michael Watford

You're right, we do have a lot of acreage. Almost got our hands full developing it. There are deals that we see every now and then, more people just trying to cash out their acreage position as opposed to just wanting us to come in and drill to earn. You see these things all the time. Whether the rate of influx is increasing or decreasing, I don't really get the feel for that. But we look at them, and I have to stack up with what we've got, and we really haven't seen much that looks better to us than what we already have.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I'm not too familiar, of course, with how the leasing works up there. Are there significant top leasing efforts going on up there for people who have older acreage?

Michael Watford

Yes, there is top leasing taken.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And if you want to just say later on the call the G&A...

Marshal Smith

I'm getting there. Year-over-year, G&A went on an absolute basis, when you consider stock comp, G&A went from $19.8 million to $24.3 million year-over-year. I'm not seeing where it came down on absolute basis, but it is down on a unit basis because production’s up.

Noel Parks - Ladenburg Thalmann & Co. Inc.

I meant sequentially between third quarter and the fourth quarter.

Marshal Smith

I haven't looked at it sequentially. I'll get with you off line.

Operator

Our next question comes from Joe Allman with JPMorgan.

Joseph Allman - JP Morgan Chase & Co

On your reserves, when we look at the additions and revisions net, is there any significant negative revisions tucked into that number? And also could you just comment about the additions, how do they compare, sort of on a per well basis versus, say, 2009?

Brad Johnson

This is Brad, I can comment on that. First, when we look at revisions and adds on a combined basis, we posted positive 692 Bcfe. Also keep in mind, we had another 432 Bcfe in Pennsylvania that we could have booked but we chose to save for another year. As we do each year, we'll have some revision details associated with our reserve reconciliation in our 10-K, we'll be posting that later this month. As far as comparison year-over-year, I spoke about our PUD ratio. Our PUD ratio right now is 0.64 on a location basis, relative to our proved developed. And we look at our PUD pool every year. Each well in our inventory has to compete for that three-year PUD pool. I hope that addresses your concern about your question about PUD quality.

Joseph Allman - JP Morgan Chase & Co

In terms of the vertical well that you're planning on drilling going forward, what's the main purpose in drilling those vertical wells?

William Picquet

That's mainly just to preserve leasehold. We find it's cheaper to drill vertical wells and hold units, than it is to release acreage.

Michael Watford

We got – you need some signs on them, and we log every well and we get the data, but the real driver is leasehold maintenance.

Operator

Our next question comes from Dave Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Back to the Marcellus, can you talk about -- I'm just trying to figure out the year-over-year growth rate, it says 15% of your 2011 production is Marcellus. And if I do the math, it seems like for the amount of wells being drilled, that we're not seeing the uptick in production, can you talk about...

Michael Watford

I think we're talking about a 140%, 150% increase in production of the Marcellus, 2011 over 2010, so it's more than a doubling. I think we're talking about 16 Bs [Bcf] to 40 Bs, something of that nature.

David Tameron - Wells Fargo Securities, LLC

So if I just think about, Mike, and I'm obviously focusing on fourth quarter, you said you exited the year at 90. If let's say you get to that 15% number, let's say you get to 40 Bs, you're just 100, 110, 90 fourth quarter exit, then all those wells being drilled that average 110 for the year. Am I -- is there something else going on there, with the amount of drilling being -- or am I missing something?

Michael Watford

I don't think you're missing something. The reality is that wells getting drilled aren't getting connected the next day. Because your billing debt, gathering systems once you drill and once you test them to connect them, and you're also getting them fracked. So our partners are a little slower in getting that done than we are. So I haven't done the math as to try to take peak rate or exit rate at the end of the year and what that implies for the year and absolute growth over that. But I'm comfortable with our 140%, 150% year-over-year growth in overall production there.

David Tameron - Wells Fargo Securities, LLC

Let me go back to another big picture item. Everybody in the industry is chasing some type of moneterization strategy, at least those names where the share prices lagged a little bit, and they feel there’s value locked up. Have you guys looked at anything. Is there anything -- I'm sure you've looked at stuff, but is there anything you can share on that front?

Michael Watford

I mean, we have folks knocking on our door asking us if we'll do JVs, and if that's what you're suggesting. Certainly, we’re approached. We always ask ourselves why do you it and principally you do it because you need funding, for your capital program. Since we've been very underleveraged for many, many years, that hasn't been a driver for us. And so I understand, and what we've also seen is when you have those transactions, it doesn't seem that, that enhanced value translates over into the equity price for very long.

David Tameron - Wells Fargo Securities, LLC

But then have you ever looked at anything like I've written this before, but anything like a trust to do anything with Jonah or -- I know it's a Canada incorporation, but is there anything you can do on that front?

Marshal Smith

David, from some of our prior discussions, you may recall I've been involved in a number of those types of transactions over the course of my career. And I've looked at them for many years in the past, and we continue to look at them at very much along the context that Mike just described. So none of that’s new to us, we're very familiar with it, we continue to look and evaluate those types of things.

Michael Watford

I mean, we're in the midst of trying to do a structure now, that allows us, makes it easier for us to, without some friction in taxes, pay dividends and do something else if we want to. So we're involved in that. I don't mean to suggest there’s something imminent, we're going to go create an MLP tomorrow, but there are some efforts underway on sort of dividend program.

Operator

At this time, that concludes our question-and-answer session. I would now like to turn the call back over to management for closing remarks.

Michael Watford

Okay. All right. Well, thank you. First of all, I thank everybody on the phone this morning, as we appreciate all the questions. Also, I want to thank our shareholders, employees for an excellent year in 2010. We obviously look forward to talking to all of you during 2011 and appreciate very much your support and attention today. If anyone have any questions after the call, please contact our Investor Relations group. Thank you very much.

Operator

Thank you for your participation in today's conference. This concludes today's presentation. You may now disconnect and have a wonderful day.

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