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Ultra Petroleum (NYSE:UPL)

Q1 2010 Earnings Call

May 05, 2010 11:00 am ET

Executives

Marshal Smith - Chief Financial Officer

Sally Zinke - Director of Exploration

Julie Danvers -

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

Michael Watford - Chairman, Chief Executive Officer and President

Analysts

Nicholas Pope - Dahlman Rose & Company, LLC

Amir Arif - Stifel, Nicolaus & Co., Inc.

Noel Parks - Ladenburg Thalmann

Michael Scialla - Thomas Weisel Partners Equity Research

TJ Schultz - RBC Capital Markets

Subash Chandra - Jefferies & Company, Inc.

Andre Benjamin

Michael Jacobs - Private Investor

Operator

Good day, ladies and gentlemen, and welcome to the First Quarter 2010 Ultra Petroleum Corp. Earnings Conference Call. My name is Kawanda, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to Ms. Julie Danvers, Investor Relations analyst. You may proceed ma'am.

Julie Danvers

Thank you, Kawanda. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's First Quarter 2010 Earnings Conference Call. On the call with me this morning to discuss our first quarter results and our continued strategy of profitable growth, are Mike Watford, Chairman, President and Chief Executive Officer; Mark Smith, Chief Financial Officer; Bill Picquet, Vice President, Operations; and Sally Zinke, Director of 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 recently redesigned website or you can access it using the SEC's EDGAR system. In addition, this call will contain forward-looking statements that involve risks factors and uncertainties detailed in our SEC filings. Please refer to our 10-Q regarding selected financial information provided in this call. Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules for the non-GAAP financial measures can be found on our website.

Second, Ultra will be participating in several conferences over the next few weeks. We'll be at the UBS Oil and Gas conferences in Barton Creek on May 26, the RBC Energy Conference in New York on June 7 to 8, and the IPAA Credit Suisse Conference in London on June 10. Please visit our website to view updated presentation. Now let me turn the call over to Mike.

Michael Watford

Thanks, Julie. Good morning, and welcome. Being a natural gas focused E&P company today is like a little bit like being a Country and Western singer when Country wasn't cool. But nonetheless, Ultra Petroleum delivered very strong results in the first quarter of 2010. We again set new production records, which when combined with our stronger commodity prices, increased our revenues by over $100 million for the quarter compared to year ago results.

With our continuing strong focus on cost, results are top tier. We doubled earnings year-over-year and cash flow is up 52%. We are in the 47% return on equity and a 21% on capital. Yes, we make money. Operationally, we continue to improve productivity in our drilling operations in Wyoming, and are effectively transferring our skill sets to Pennsylvania where drill times are dropping. We are on our way to most likely exceeding our year-end production targets in the evaluation of our Marcellus acreage continues with positive results.

We closed our Marcellus acquisition during the quarter and funded it with long-term debt. We are clearly establishing a second growth platform. Mark, would you like to share financial results.

Marshal Smith

Certainly. Thanks, Mike, and good morning. As you've seen from our press release, we had another very good quarter operationally, with record production, continuing improvement in drilling efficiency and reduced cost. Ultra's realized corporate natural gas price was up significantly year-over-year as well as sequentially. We've previously discussed the impact of REX East and increased takeaway capacity out of the Rockies.

For the quarter, Opal natural gas prices averaged 97% of Henry Hub. Further and for the first time, Ultra's corporate realized gas price before hedges for the quarter, exceeded the average Henry Hub price for the period.

From a financial perspective, we're on solid ground. We closed and funded our Marcellus acquisition during the quarter. As of March 31, we had $6 million of cash and cash equivalents on hand, and $1 billion on outstanding senior debt.

Our total debt capacity is in excess of $2.5 billion, providing us with almost $1.5 billion in unused senior debt capacity. I believe most importantly, we again demonstrated strong organic growth on generating industry-leading returns.

For the first quarter, our Wyoming production was up 15% on a comparable year-over-year basis to a record 48.5 Bcfe. Once again, our quarterly production was an all-time high for the company. We'll hear more about this from Bill in a minute.

Realized natural gas prices for the first quarter were $5.37 per Mcfe, an increase of 20% over prior year levels. Condensate prices registered $69.52 per barrel for the quarter. As a result of our increased production levels and increased realized commodity prices, revenues for the quarter including the effects of our hedges, registered $272.5 million.

Corporate lease operating expenses for the quarter increased year-over-year to $1.05 per Mcfe, as a result of higher severance of production taxes due to higher commodity prices, offset in part by reductions in our unit production cost and gathering expenses. Our production costs have improved year-over-year as we've worked with our partners to bring down their expense levels, largely related to water handling cost.

Looking at our cash costs in Wyoming, excluding severance taxes or our field level costs, they decreased 8% year-over-year on a unit basis to $0.46 per Mcfe. Our transportation cost which represented our demand charges as an anchor shipper on REX, amounted to $15.9 million this quarter or $0.33 per Mcfe on our total production volumes. Our DD&A rate for the quarter registered $1.06 per Mcfe. General and administrative expenses increased, on a unit basis, $0.13 per Mcfe, while interest cost registered $0.24 per Mcfe.

On this point, recall that during the quarter, we refinanced our senior bank debt with longer dated favorable fixed-rate debt, that due to its term, carries a higher coupon. Net effect of all of these factors was a $0.15 per Mcfe year-over-year reduction. And overall, corporate cost, this includes all gathering and transportation costs, from $2.95 in the first quarter of 2009 to $2.80 per Mcfe this past quarter.

As a result of the increased production and improvement in realized prices that I mentioned, as well as our continued focus on operational improvements and cost reductions, our operating cash flow increased over the comparable 2009 quarter to $188.9 million, providing an operating cash flow margin of 69% and $1.22 in cash flow per diluted share.

Adjusted for unrealized gains associated with the mark-to-market position of our hedges, our net income registered $85 million for the quarter, over twice prior-year levels, for a 31% margin and $0.55 adjusted earnings per diluted share.

In terms of break even levels, our net income break even is now $2.52 per Mcfe, with cash flow break even at $1.25 per Mcfe. Our adjusted return on equity on an annualized basis for the first quarter was 47%, and our adjusted return on average capital employed was 21%.

Cash provided by operating activities during the quarter amounted to $168.7 million, with cash used in investing activities totaling $422.7 million. These investment activities were largely comprised of $333 million associated with the acquisition; roughly 78,000 net mineral acres in the Pennsylvania and Marcellus Shale; $198.6 million in oil and gas related capital expenditures, offset by $68.4 million in proceeds, related to consolidating and high grading our land position in Pennsylvania.

Over the quarter, net cash provided by financing activities totaled $245.8 million, consisting primarily of the $500 million of proceeds from our senior note offering that I mentioned, offset by $249 million in net repayments on our senior bank facility.

Now I want to spend a minute on our price outlook for 2010. Opal prices were up meaningfully and differentially. Last year, June through December 1, index prices at Opal averaged $3.21. This year, our 2010 pricing is currently trading around $4.26. This reflects an increase of over 33% over prior-year levels. This compares to 2009 Henry Hub June through December prices of $3.74, a balance of 2010 pricing at Henry Hub of $4.70, is up some approximately 25% over last year's levels.

This differential change in Rockies' spaces is very important. We've spoken about this before and I want to continue to emphasize this point. We see an increased takeaway capacity out of the Rockies on first REX East, and ultimately, on the Bison and Ruby pipeline projects. Both of these projects are said to be completed in the next 12 months and we'll add a further 1.7 Bcf per day of takeaway capacity to the region.

We're also seeing production in the Rockies decline due to reduced natural gas drilling activity, but we've seen gas congestion in other regions of the country. As a result, we've seen a tightening in the market's view of basis differentials going forward. I previously commented on the fact that when all of this is taken into consideration and one focus is on our firm transportation on REX, combined with our overall corporate mix of sales, one could see our put forward corporate basis improving to approximately 94% to 96% of Henry Hub. In fact, for the first quarter, our realized gas price before hedging measured $5.38. This compares to an average Henry Hub price of $5.30. So our unhedged corporate gas price for the first quarter registered 101% of Henry Hub, very meaningful.

Again, this changing corporate discounts driven by, one, the effects of REX on regional takeaway capacity. And as a result, Rockies prices. Two, our increasing production in the Northeast. And three, our firm transportation capacity on REX.

Moving to hedging. As detailed on Page 3 of our press release, we currently have approximately 46% of our 2010 forecast natural gas production hedged through fixed price swaps, and weighted average price of roughly $5.49 per Mcf in Wyoming. For calendar 2011, we have about 73 Bcf hedged in a price of roughly $5.61 per Mcf, again in Wyoming.

I'll wrap up my comments by pointing out that on Page 4 of our press release, we continue to confirm our full year 2010 production guidance at 215 Bcfe, and are establishing production guidance for the second quarter at 51 Bcfe, to provide additional detail on our outlook and guidance in our press release. And now I'll pass it off to Bill for an update on our operations.

William Picquet

Thanks, Mark. Wyoming in the first quarter, also brought on the stream 59 gross, 32 net new producing wells. The average initial 24-hour sales rate for these new Pinedale producers was 8.9 million cubic feet per day. Ultra's operated Pinedale wells averaged 9.8 million cubic feet per day, while the non-operated wells averaged 7 million cubic feet per day. The highlight for the quarter was the Ultra-operated Mesa 2C2 33D, which floated 17 million cubic feet per day. And as of first quarter, there were seven Ultra-operated rigs drilling at Pinedale, and five non-operated rigs also working on Ultra interest lands, for a total of 12 active rigs in Wyoming.

Two Ultra-operated wells, with initial production during the first quarter, averaged 6.1 Bcfe EUR. Our average reserve size per well continues to be excellent in 2010, whereas during 2009, when we were drilling essentially all of our wells in our operated program, the more prolific Riverside and Mesa areas of the field. Going forward, for the majority of the next decade, essentially all of our developed wells in our Wyoming program will be drilled in these areas.

We recently obtained additional approvals for five-acre pallets and are extending our five-acre activities in Pinedale during 2010. At the end of the first quarter, we drilled five new five-acre wells and expect to drill a total of 35 five-acre wells in our operated program for the full year. Our results, to date, are in line with our pre-drilled reserve expectations. We plan to continue to expanding a five-acre program as we develop these areas in the field going forward.

The expense of magnitude as resource is best summed up by the size of our estimated Wyoming resource potential, which we believe will ultimately reach 15 Tcfe. Our third-party reserve estimate at year-end 2009, places our remaining Wyoming drilled location inventory of 5,584 gross wells and 3,101 net wells. During 2010, we anticipate drilling a total of 222 gross, 117 net new wells in Wyoming, compared to 222 gross and 114 net wells drilled in 2009.

We expect to complete a total of 262 gross, 139 net wells in 2010, compared to 228 gross, 107 net wells completed during 2009. Our operating efficiency in Pinedale continues to improve. First quarter, we averaged 15.6 days spud to TD for Ultra-operated wells, a 31% improvement over the average for Q1 2009. During the first quarter, our average rig release to rig release was 19.7 days, down 36% from our Q1 2009 average. 92% of Q1 wells were drilled in less than 20 days from spud to TD. Over 50% of our wells were drilled in less than 15 days from spud to TD.

Our average operated well cost for the first quarter 2010 was $4.8 million per well. Our early 2010 performance continues to improve, drilling a very high percentage of PUD wells, and we continue to experience improvements in bid designs, thus having a significant positive impact reducing our drill times. Continuity of rigs and personnel is also a significant benefit to our operating efficiency. Our record well now stands at 10.25 days spud to TD, closing in on a sub 10-day well, our next significant goal in drilling efficiency.

Our completion operations results in Pinedale have also been outstanding. For the first quarter 2010, we completed 41 wells in our operated program. Second quarter, we anticipate completing an additional 54 wells as we ramp up our operated frac activity with the second completions [indiscernible], averaging 26.3 of frac stages per well in Q1 of 2010 versus 25.1 stages per well for 2009.

They averaged $73,500 per stage during Q1 2010 compared to $76,500 per stage in 2009. Increasing average in frac stages per well during Q1 2010 attributable to the fact that we're drilling and completing wells in the best areas of the field, but there is more net sand pay per well. This requires more stages to effectively access the larger reserves per well.

During the remainder of 2010, we expect continued improvements in our completion efficiency. We continue to benefit from the continuity of the equipment and personnel in our frac operations in a similar fashion with our drilling efficiency gain. Overall, in Wyoming, we're drilling deeper, increasing the number of frac stages per well. We drilled the more prolific Riverside and Mesa areas of the field, while we're still reducing cost, improving operating performance, efficiency gains and the ability to effectively assess and apply new technologies. With that, let me turn things over to Sally to discuss our Pennsylvania activity.

Sally Zinke

Thanks, Bill. Looking at Pennsylvania, we entered 2009 with an expanded acreage position of 326,000 gross, 169,000 net acres in our focus area of North Central Pennsylvania, based on the encouraging results that we were experiencing. In the first quarter of 2010, as Mark indicated in his comments, we continue to consolidate our leaseholds in this core area, focusing on proximity to infrastructure, logistical issues like terrain and access, lease term and the ability to amalgamate units for extended lateral links.

February, we closed on the strategic lease acquisition of over 78,000 net acres centered in Clinton County, which we described in the last call. This is a large contiguous acreage block, predominantly held by production, with water access, pipeline tabs, road and rights-of-way in place. More importantly, the geologic characteristics are strong, with twice the Marcellus' thickness of our other area, higher organic content, excellent maturation profile and added over pressure to enhance recovery.

With this consolidation and addition, our leasehold in Potter, Tioga, Bradford, Lycoming, Centre and Clinton County, at the end of Q1 2010, is approximately 413,000 gross, 125,000 net acres. Proprietary 3-D seismic data has been acquired over 50% of this acreage position, bringing our total coverage to over 300 square mile. We feel strongly that the seismic data provides valuable information for optimizing the design of drilling unit and the steering of lateral well bores.

Since Q2 2009, Ultra has drilled or participated in a total of 74 horizontals, 20 vertical Marcellus wells. Currently, 41 of these horizontal wells have been completed and 22 are producing. The average IP rate for these horizontal Marcellus wells is over 7.7 million cubic per day. The average 30-day production rate for these wells is in excess of 4.6 million cubic feet per day, with the highest average 30-day rate at 7.86 million cubic feet a day. The seven producing horizontal wells that IP did over 10 million cubic feet per day, strategically located across the 40-mile east to west span of our legacy leasehold, we feel our acreage position is currently 80% de-risk.

In the first quarter of 2010, Ultra drilled or participated in the drilling of a total of 26 horizontal wells. Our drilling and completion programs have continued, and we have added an additional 13 drilled wells since the end of Q1. In addition, in the first quarter, three vertical Oriskany wells in the Texas Creek area of Southern Tioga and Northern Lycoming County were put on production, with an average rate in excess of 9 million cubic feet a day [ph].

The highest IP of these three wells was over 13.5 million cubic feet a day. We expect to drill an additional 110 horizontal Marcellus wells, 70 net and 90 -- 45 net vertical wells in the remainder of 2010. We are proceeding with pipeline and gathering system construction, with the intent of having all drilled operated wells on existing PUD online by mid-July. As a result, we anticipate a strong increase in our Marcellus production in the second half of 2010.

You may recall our exit rate for 2009 was 24 million cubic feet per day. We fully expect to exit 2010 at 130 million cubic feet per day net. As part of assessing our frac design and optimal well spacing, Ultra recorded micro seismic events during the completion of a pair of Marcellus laterals in our Marshlands area during the first quarter.

By utilizing vertical and horizontal monitoring wells, we were able to observe a total of 24 frac stages horizontal wells and augment our frac designs in realtime to maximize propagation and growth. Results of this study suggest that lateral well spacing closer than 1,000 feet or closer than 100-acre spacing, would provide more optimal drainage for the resource. Ultra intends to drill a group of four parallel horizontal wells on 50-acre spacing in the early summer to test the potential of closer well spacing in our area.

Our partners have also utilized micro seismic technology to assess frac design and well spacing in the areas where they operate. The preliminary ultimate recovery estimated for our produced horizontal Marcellus wells consistently supports the tight curve used in our model, with an expected EUR per well of 3.75 Bcfe, with recent results suggesting that our tight curve maybe overly conservative.

For the higher-pressured Center County area, the estimated EUR is 5 Bcfe. Assuming 80-acre spacing, we estimate that we have more than 5,100 gross, 2,300 net remaining well locations across Ultra's 225,000 net acre position. If we apply expected EUR for these locations. The risk resource potential is over 8 Tcfe and to Ultra in the Marcellus. Back to you Mike.

Michael Watford

Thanks, Sally, that's some really good stuff. Our just released 2009 annual report is entitled, A Strong Foundation For Growth. We mean profitable growth, of course. We're both serious and sincere about that message. We have one of the best natural gas assets in North America and our Pinedale field in Southwestern Wyoming. It possesses scale, growth, low-unit cost, and with the expansion of pipelines, stronger commodity prices, leading to a very healthy margins and returns. And after seeding it capital over a few years in its early developed period, it continues to grow, providing cash and high returning reinvestment opportunities for decades to come.

Now we are establishing a second growth platform, building off our legacy-asset base in Pinedale, with another scalable low-cost, high-return asset in the Marcellus. One where with a few years of seed capital, we'll replicate the growth cash generation and high-returning reinvestment opportunities of our core Pinedale position. We are serious about consistency and sustainability, the diversification expands the resource base and diversifies our growth program lowering risks. We are sincere in our belief that our group of 100 employees is very close to capturing over 23 Tcfe of risk reserves. Now operator, we'd like to take some questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Andre Benjamin with Goldman Sachs.

Andre Benjamin

My first question was, if you could update us specifically on the updated learnings you have about the geology of your Marcellus acreage position, such as the pressure faulting et cetera, that specifically are leading you to think that your tight curve is conservative? And then the second part of that would be, if results do continue ahead of your expectations, should we expect a production guidance increase or would you just reduce spending somewhere else?

Sally Zinke

The adjustment in our tight curve is not geologic based. It's based on well performance.

Andre Benjamin

And in terms of the expectation that they continue to perform ahead of you expectation, will we expect an increase in production or would you just reduce spending?

Michael Watford

Let me help Sally amplify that a little bit more. I mean, it is based on well performance. We also have 50% of our acreage under our 3-D seismic survey, and we are doing an excellent job of being able to stay in zones, steering our wells based on that, staying out of faults or the problems. And we're going to expand to that. So I think all of that is helping us. On the production side, we were very, very, very conservative in estimating growth of Marcellus production, our 2010 plan. Our style normally is to under-promise over-deliver, and we're going to be consistent with that. I think we only have about 20 Bs of production from Marcellus in our 215 Bcfe target for 2010. And again, most of the wells are coming on the second half of the year, not the first half of the year. So it will all be tail-end loaded, back-end loaded. So I think, yes, I mean, we may see increased overall, and most likely see increased overall production for 2010. And there's probably more significant for 2011. And I think in our 2011 plan, we have about 70 Bs of production for the Marcellus. For 2012 plan, we have over 100 Bs of production in Marcellus. We're going to go from -- and whatever averages this year, 20 Bs of production on a daily basis to almost a little less than 200 million cubic feet a day of Marcellus production in 2011, and little less than 300 million a day of Marcellus production in 2012. At least that's the plan, with conservatism built into it. It's the lower reserve estimates that Sally was talking about. So there is significant upside if that's your direction of the question.

Andre Benjamin

It was. And I guess in terms of how you're thinking about the growth contribution from your legacy versus the newly acquired acreage, is there any way we should be thinking about that?

Michael Watford

Well, I mean, right now, we're trying to be prudent with capital. And we're unique. We put out a three-year plan in our corporate presentation material. And with calls on minimally 20% per annum production growth, at an annual capital run rate of about 1,050,000,000, exclusive of the acquisition of major in February. I mean, honestly, if you look at the 2011 and 2012 plans, we don't have $1,050,000,000 of CapEx to hit those 20% production targets that's less than a billion. But We have room there. To the extent we want to use additional -- if gas prices improve, or if we want to use additional leverage, we can certainly grow faster. It's just -- again, we are unique. We make money at $4 gas, other folks don't. If you look at our cost structure and our returns in this quarter, its stark contrast, the other folks reporting today that have cost structures closer to $6 in Mcfe, and ours is less than $3. And the increased revenue from higher gas prices is really working out for us. And we'll have the ability to go fast. So I think Mark would tell you that our debt capacity is $2.5 billion. And in the first quarter, we had, what, less than 1,050,000,000? So we have plenty of capacity to take on what we're doing now. We've ran some sensitivities internally that we presented to our board on Monday, with the $4 gas prices in 2011 and $6 dollar gas prices. It's just going to range the numbers. And so we've got plenty of downside protection to be able to hit the production growth numbers we have without stretching the balance sheet or doing anything aggressive at all. We're very conservative that our financial operations will continue to -- I mean, I think you're trying to get is to how fast we want to grow Wyoming. And that's just going to be based on product prices. All that acreage is held by production. We don't think the market is going to reward us for anything greater than 20% per annum production growth if they were wanting for that. And we're very comfortable in executing and trying to develop a second asset base.

Andre Benjamin

You clearly have two very nice assets in the Pinedale and the Marcellus, but a lot of your peers have also been looking at some opportunities to get into some more liquids or oil-rich place, shift some capital from gas to those. Have you taken a look at any of these opportunities, particularly in the Rockies or are you sticking to your two horses?

Michael Watford

Well, I mean, for the short term, we're sticking to our two horses. I mean, I think we surprised folks with the position we have in the Marcellus six months ago, and to what that KL is [ph] in sizes. And I don't think the market's fully grasped what we have there in comparison to our competitors. We will probably surprise on other opportunities in the future too. So we'll just keep that to our ourselves.

Operator

Your next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc.

First question on the Pennsylvania volumes, 32 million a day. What's the break out there between Marcellus and non-Marcellus?

Michael Watford

I don't think we're going to provide that, Subash. It's not meaningful to break it out.

Subash Chandra - Jefferies & Company, Inc.

And you think this restricted rates that's going on in some of the other, as they say, I guess soft rock shale plays will occur in the Marcellus?

Michael Watford

I don't know that we believe that it works where they're suggesting it works. So I don't think we have an intelligent comment on it.

Subash Chandra - Jefferies & Company, Inc.

And so trying to sort of figure out what the unknown sale are, when you say 80% de-risk, we sort of suggest that a lot of the geologic characteristics, as well as the completion techniques are known. And I guess on Marcellus players and things like that, where inflation is still very difficult to gauge, I mean what's known to you at this point? And what's unknown to you when you say that 80% has been de-risk?

Sally Zinke

I think from our perspective, the fact that we have drilled extensively across the acreage on at least the legacy portion of it is in pretty well tested, with pretty consistent result. Also on the frac issue, our micro seismic experiment indicated pretty good confirmation of the frac orientation that we've been using as a model. In addition to that, we frac-ed one well and listened, and as we frac that well, we tweaked the frac design a little bit in terms of proppant, comp rate, those kinds of things. And we were able to implement changes in the design for the second well with significantly better result, performance of the second well. So I think we're pretty comfortable with both our frac design, the orientation that we're assuming and the execution of that frac process.

Subash Chandra - Jefferies & Company, Inc.

How many observation wells have you drilled? And sort of, how has it been over this entire area?

Sally Zinke

We have data on two at this point, and one is being collected next week, the third part of the area.

Michael Watford

Micro seismic.

Sally Zinke

Micro seismic.

Michael Watford

Are you asking about wells or about micro seismic, Subash?

Subash Chandra - Jefferies & Company, Inc.

On micro seismic observation wells. So the two and the third one is what? And how about sort of where you bring the laterals? And is there a potential for upside in some of the different zones that you might be seeing and how that might be distributed over your acreage if there is additional upside?

Sally Zinke

We've identified a zone in the Marcellus that we like to stay in because of its frac ability and the potential of the organic material around it, and that's pervasive across our entire acreage area.

Subash Chandra - Jefferies & Company, Inc.

And are there any other zones of interest that you might do work on?

Sally Zinke

I think I've not fully explored some of the uphold potential. I think we've assessed the Marcellus itself pretty extensively.

Subash Chandra - Jefferies & Company, Inc.

So no other benches or so in the Marcellus that might be of interest?

Michael Watford

I think she's saying that we see some, what, 5,000 gross wells, 2,300 net wells, netting 8 Ts to us in this one Marcellus zone across our 225,000 net acres to that we haven't fully explored the remainder. I think that's what she's trying to provide.

Subash Chandra - Jefferies & Company, Inc.

And winding down on here a bit. What physically needs to happen now sort of between the July pad wells all coming on production and what sense of scale are we talking about when that happens? And so what physically needs to happen between this point and July?

William Picquet

This is Bill, Subash. It's mainly just gathering infrastructure, putting pipelines in which are permitted. And so we're doing that as we speak. It's not reliant upon anything other than just's being able to put that pipe on the ground.

Subash Chandra - Jefferies & Company, Inc.

And so the permitting issues have been resolved?

William Picquet

All the permits approved as far as that's concerned for everything that we've applied for, and our partners do as well where they operate.

Subash Chandra - Jefferies & Company, Inc.

And how many wells are -- are we talking about all the balance of wells waiting a completion are online by that date?

William Picquet

It won't be all the balance of wells that are waiting on completion, we'll be completing at a pace that there is a significant number of wells coming online, but we still have some inventory at that point in time.

Subash Chandra - Jefferies & Company, Inc.

No hard numbers around it that you care to share?

William Picquet

That's all kind of timing related, Subash. But as Mike said earlier, we've been very conservative as far as our forecast is concerned.

Operator

Your next question comes from the line of TJ Schultz with RBC Capital.

TJ Schultz - RBC Capital Markets

Just jumping over to the Pinedale. I guess in late last year, you were kind of talking about EURs in the 6.4 range and IPs, I think we're averaging 10.3 to 10.4. And turning down here to 6.1 EURs and 9.8 million IPs, just trying to get a sense if that's some variability or is there anything going on here, joining the new areas, just try to get a sense of how that trend's looking?

William Picquet

It will always vary because of where we're located as far as specific pads are concerned. I guess my comment would be that these wells are coming in pretty much right on the expectations for us. Our reserve estimates are concerned, so no variability that's of concern.

TJ Schultz - RBC Capital Markets

And then on well cost and you talked about more fracs in the Pinedale. Well cost just got 4.8, can it go lower than that as you continue to increase fracs or how should we look at that?

William Picquet

The number of fracs didn't increase significantly. But bottomline is we're continuing to get efficiency gains. And how low can we go? It will all depend upon how far we can go as far as efficiency gains are concerned. We continue to improve. The cost of services remained constant. I'd be able to predict that a little more of it, but that will vary. So I guess the one thing that I can say is days are coming down.

Operator

Your next question comes from the line of Mike Scialla with Thomas Weisel Partners.

Michael Scialla - Thomas Weisel Partners Equity Research

In Pinedale, it sounds like you just stay put in Mesa and Riverside for the next decade. Is there any more delineation drilling to be done there or is it all development at this point?

Sally Zinke

I think for delineation for right now in the Riverside, Mesa areas is pretty well defined, and so there's not really any need to do that. We will continue to delineate as we expand out into other areas and have the need to define those further and expand some of the expectation of resource in those areas. But right now, it's not on the calendar for the near term.

Michael Scialla - Thomas Weisel Partners Equity Research

And what percentage of your wells drilled in the first quarter were pad drilling, and then is that going to change at all over time?

William Picquet

Essentially, all of them were pad drilling in the first quarter, and it will remain a very high percentage go forward.

Michael Scialla - Thomas Weisel Partners Equity Research

And I may have missed it, but did you give a switch over to Marcellus well cost, maybe broke it up between your legacy acreage and then the Centre counties?

William Picquet

Overall, as far as legacy is concerned, it's about $3.5 million, maybe trending up just slightly because of these frac stages. But in that range and the new [ph](55:53) acreage, it's a little bit higher than that because of wells being drilled deeper, et cetera, et cetera, plus they're fairly early as far as number of wells drilled. So kind of early to state a cost as far as those numbers are concerned.

Michael Scialla - Thomas Weisel Partners Equity Research

And then when you've talked about the 80% being de-risked, does that vary between the legacy acreage and the new acreage or is it pretty consistent across all things? I guess you may have just answered, it sounds like that more of it's de-risk in the legacy acreage.

Sally Zinke

That's correct. Most of our seismic is in the legacy area with acquisition expected in the newer acreage later this year and into the first part of next. We do have a number of wells in the new acreage area, so that we're pretty comfortable with the resource there. But in terms of fully risking it, the bulk of that de-risking legacy.

Michael Scialla - Thomas Weisel Partners Equity Research

And it looks like you've talked about high-grading your acreage. I'm not sure if you actually let any acreage go, but you're talking about 225,000 net-acre number now versus I think, 240,000 or so earlier. Did you let some go? And if so was that, I assume in that legacy acreage area?

Sally Zinke

Yes, what we've done is high grade our leaseholds. All acres are not created equal, at least from my perspective. So if you have to scatter acreage with early exploration, that's not as useful or as valuable as some longer-term acreage that's in contiguous blocks or abutting your current drilling program and drilling units. So we've been able to swap or buy and sell some acreage. This changed the acre count. But it's actually, my opinion, increased the value of our leasehold significantly and provided the ability to execute on development much more efficiently.

Michael Scialla - Thomas Weisel Partners Equity Research

Likely to do some more of that or be pretty much done with that at this point?

Sally Zinke

I think we're getting close to being finished with the bulk of that. There still will be little pieces within units that we will make an effort to acquire to meet those units.

Michael Scialla - Thomas Weisel Partners Equity Research

Mike, was gas prices here at $4, are you a buyer of Marcellus acreage now? Can we see some more big deals like the one you recently did or price is just not to your liking at this point in general?

Michael Watford

Not at all, I mean, current [ph](58:41) prices aren't to our liking. But we're going to reiterate the central theme is our current Marcellus drilling program makes money in $4 gas. Our current Pinedale drilling program makes money in $4 gas. And we talked about break even net income, cash flow, we have lost downside of production. So it makes sense for us to be spending money developing these resources. Now as to how much additional funds we put forth for acreage for new resource, that's a little bit more difficult. But yes, we are still a net buyer of acreage in Marcellus. We're in some of the areas, that Sally referred to, where we find more attractive. We're not buyers of random acreage or scattered acreage, it needs to be concentrated, needs to be near to where we are now, where we think the better areas are. But yes, we'd buy more.

Operator

Your next question comes from the line of Noel Parks with Ladenburg Thalman.

Noel Parks - Ladenburg Thalmann

Just a couple of things and excuse me if you mentioned it already. Where do you stand as far as how of your Marcellus position overall is now held by production?

Michael Watford

I don't know where we stand at the moment, but the intent is that year-end 2010 is to have over 90% of an HBP. I think that's the relevant effort.

Noel Parks - Ladenburg Thalmann

And I was curious, East Resources your partnering your original set of acreage. Your agreement with them is an AMI, is that right?

Michael Watford

That's correct.

Noel Parks - Ladenburg Thalmann

Then just curious, what's their appetite? Since they're private, of course we don't know much about their financials. But their appetite for either more acreage acquisition or stepping up on drilling activity further if you decide that's warranted. Are they about inclined to go along with sort of a similar paces as you could or are they interested in going a little slower, a little faster?

Michael Watford

What was talked about some of the acreage is usually [ph](1:00:57) some of the swapping of acreage or netting down of less than shooting [ph](1:01:02) acreage has been done with our partner, East Resources, in that AMI. So that's -- we're one and the same there. As to their aggressiveness in drilling, I mean, they have three operated rigs operating in the area now. They are well capitalized and they have a plan put forward for 2010 we're executing under. And 2011, that's going to provide us the sort of production numbers we're talking about. They're like all of us, they're sensitive to economics. And if I run harder at $6 gas, then they do a $4 gas.

Noel Parks - Ladenburg Thalmann

And I actually just had a couple of numbers I couldn't quite hear. One of them, for the risk in new wells, could you just repeat what the rate was that you saw on those wells?

Sally Zinke

We had an average rate for three wells of 9.6 million cubic feet a day. But the highest rate for one of the wells was 13.5 million cubic feet per day.

Noel Parks - Ladenburg Thalmann

And just a last thing, you talked about, in the Pinedale, having success I guess, with changes in bit design. And I was just curious whether there was still more improvement you expected on that dimension? And also curious as to how specific the designs were to your needs at Pinedale or whether it was a matter of just fairly common designs, you just haven't quite match the optimal one previously with the drilling conditions there?

William Picquet

It's a little bit of both, but I'll answer your first question. First, which is if we see that continuing, and the answer is yes, quite a bit of work going on constantly as far bit design improvements are concerned for all portions of [indiscernible](1:03:03). And so we do see some upside continuing forward there. As far as specifics are concerned, we actually gave some of the bit manufacturers cores from wells in area that we're drilling in right now, had them specifically, go out and bit designs to be effective as far as that particular rock is concerned. So yes, it's varying.

Noel Parks - Ladenburg Thalmann

Just the service environment in the Marcellus, can you just tell us what you're seeing from listing to some of the surfaces vendor calls? It's a sort of mixed thing, some saying that they felt they were going to get better traction with their price as the year goes on. Others talking about trying to stay real competitive to keep their biggest customers happy. So just curious what you were seeing in the Marcellus?

William Picquet

We're seeing pressure upward as far as cost are concerned and whereas availability of services, height [ph](1:04:12) and forecast to improve somewhat. But I guess that depends on gas prices as well.

Operator

Your next question comes from the line of Amir Arif with Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc.

For your average IPs, I noticed that their still trending higher in the Marcellus, but you're still seeing a lot of variability. I think you mentioned 10 wells over 10 million a day. Can you just give us a sense? Is that just in the thicker areas like Lycoming or is it with newer completions and larger fracs that you're doing?

Sally Zinke

Those are wells scattered completely across our legacy acreage, just phased out. That's just to demonstrate that we have -- basically, de-risks that whole area. That would be Potter, Tioga and Lycoming Counties.

Amir Arif - Stifel, Nicolaus & Co., Inc.

These are for the 10-million-a-day wells?

Michael Watford

Yes. It's not concentrated in one little pocket like some companies have, it's extensive.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then when you compare the type curves on those wells are you noticing a faster decline or are they leveling at higher levels as well, despite the higher IPs?

Michael Watford

I'll just make a general statement as far as the declines have actually been less than what we anticipated. Therefore, our optimism as far as upside to our type curves.

Amir Arif - Stifel, Nicolaus & Co., Inc.

So that's even on the 10-million-a-day wells or for the higher-rate wells?

Michael Watford

It's a general statement. I guess if you asked the question about are we seeing this as far as on going improvements are concerned, then I do think it's related to standing [ph](1:06:03) experience, our wells are getting better.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And on just a couple of numbers that you mentioned in terms of your plans for the 2010 drilling. I know you've drilled 32 wells last year. What's the plan for 2010 in Marcellus?

Michael Watford

About 140 horizontal Marcellus wells in 2010.

Amir Arif - Stifel, Nicolaus & Co., Inc.

So that's up from 110 that you were planning before?

Michael Watford

That's correct.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And then can you give us a sense on how many wells are drilled and waiting on completion right now?

Michael Watford

A whole bunch. Sally gave some numbers...

Sally Zinke

These drills are participated in a total 74 horizontal wells, 41 of those are completed, 22 are producing right now.

Amir Arif - Stifel, Nicolaus & Co., Inc.

And it sounds like most of those should come on by June, July?

Sally Zinke

Yes. But remember, we're continuing to drill, so we will have it in [indiscernible](1:06:58)

Michael Watford

We're not forecasting catching up by the end of the year. We're just still going to have uncompleted, unproductive wells that have been drilled by the year-end. I don't want to give you the wrong idea.

Amir Arif - Stifel, Nicolaus & Co., Inc.

Just the final question, as you target the 140 wells for the year, when you've got your -- your drilling efficiencies have improved. Can you give us an update on ultimate [ph](1:07:17) capacity? What kind of constraint do you worry about in terms of being able to put these wells on other than the normal inventory that you can have that you mentioned?

William Picquet

Basically, it would be service excess. Inventory will -- an issue as far as how many frac spreads can you actually run. That's kind of the limit.

Operator

Your next question comes from the line of Michael Jacobs with Tudor, Pickering, Holt.

Michael Jacobs - Private Investor

Wanted to follow up on the Marcellus. You've emphasized geosteering a little bit earlier in the call, and it sounds like you've identified a sweet spot. Can you provide us any sort of color as to what you're seeing? And kind of as you're trying to avoid the purpose [ph](1:08:14) by placing these wells in a sweet spot, what is it specifically that you're looking for?

Michael Watford

I don't know how that helps us to share that.

Michael Jacobs - Private Investor

It sounds like a lot of the questions on this call are trying to understand a little bit better the timing of completion, so we can model it better, and again, maybe you can help us out this way. But understanding you've got a bunch of take away in terms of pipeline commitments. Can you give us a little bit of color on the gathering side? And then any sort of idea how we model the pace of completions throughout the year?

Michael Watford

I'm going to let Bill talk about the first question. But modelling of the completions, again, I don't think that helps us to give you any kind of details on that, since it's -- again, we're trying to be very conservative in 2010 with the ramp-up in Marcellus production, and we are trying to under promise and over deliver. We only have 20 Bs of Marcellus production in the whole forecast. I think extensive details, well by well schedules on your part, are going to be meaningless in terms of any impact to the value of the company. I mean, and most of it is back-end loaded as we've suggested. So if it's 20 Bs and it's back-end loaded, just allocate third and fourth quarter, evenly. That's what I will tell you. And I'm simple but we had issues with giving stream crossings borings proved, that's behind us. We've got the frac spreads up there performing. We had weather issues. All that's behind us. We're moving forward. So I guess I'm just not going to help you much with 2010. We'll be glad to help you more with 2011, once we get this history behind us. And I forgot the first question that Bill was going to answer.

William Picquet

As I said earlier, are putting pipe in the ground. Bottom line is we have all the permits that we need. It's a matter of getting pipe laid and getting wells online. I think it's back to how fast this have happened. We don't have a restriction. We don't have restriction as far as exit capacity is concerned, and we have a game plan that will, over the course of the remainder of the year, significantly increase that. So we're trying to pace, tap capacities and our installation of infrastructure meet the needs what we have as far as well capabilities are concerned. As Mike said, we lag a little bit because of stream crossing permits, that's behind us now.

Michael Watford

And let me go on a little more. I mean, the newly-acquired area that Anadarko operates, Anadarko has no intentions of frac-ing any of those wells to the fourth quarter. So again, in terms of scheduling of wells coming on and our half ownership in all those wells and the amount of money we're spending there in 2010, which is probably $125 million or so. All of that benefit is really, 2011. You get some at the tail under 2010. So I just don't think it's going to be productive if you try to be that granular in your forecasting.

Michael Jacobs - Private Investor

Final question is as you think ahead to 2011 and you gave kind of a sneak preview of 2012, can you talk a little bit about the permitting side with respect to water sourcing or disposal. Are there any kind of higher-level issues and how -- and this is more pervasive for the industry, and then how far ahead are you keeping permits ahead of the drill bit?

William Picquet

We haven't run into any timing issues as far as drilling permits are concerned. And with the due pace unpredictability of infrastructure permits, we're confident that we can execute what we've said we're going to execute. As far as water access is concerned, we have surface water access that will allow us to execute the program that we've talked about both now and going forward in all areas of our acreage. So we're a little unique and that we've parted quite some time ago going after surface water access. And we're also evaluating other sources, there's traditional South Louisiana terms line you up [ph](1:13:04).

Michael Watford

We benefit from having led contiguous blocks of acreage, when we go to gathering systems. We're also building water systems, the new water in the field [ph](1:13:15). So all those are fracs we're reusing. We're not disposing of it. And we have an ongoing program where we're going to be drilling and frac-ing wells for decades to come. And so we see that as continuing. The water access and I guess, water disposal issues haven't been a limitation to our activity so far.

William Picquet

It's hardly a little bit about reprocessing water in Pinedale. That's something that's not an issue for us.

Michael Watford

You have to remember in Wyoming, it's arid. There is no surface water to use for frac-ing. It's all well water in an arid environment. People are very sensitive to reuse of water, and have probably more environmental sensitivity there than federal lands. So in Pennsylvania, again, they're flushed with surface water. We haven't even had to go drill wells for water yet. And given that we're used to recycling the water in the federal acreage in Wyoming, Pennsylvania's not really a challenge from that standpoint to us. Maybe a challenge to others who aren't used to our history, but not a challenge to us.

William Picquet

My implication on that [ph](1:14:26). We don't talk about it very much, but our frac water in Pinedale 100 cycled water. We don't add any water to the system whatsoever as far as our frac water is concerned. And we're setting our infrastructure in Pennsylvania to give us flexibility. Every drop of water that we [indiscernible](1:14:48).

Operator

[Operator Instructions] Your next question comes from the line of Nicholas Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose & Company, LLC

When you look at Pinedale, you have the seven operated rigs there, it seems like what the excess capacity are seeing pipeline capacity improving differentials. I mean, do you all foresee any potentially, all of that might move some capital back towards to Pinedale with the results continuing to improve?

Michael Watford

Yes, we see that possibility.

Nicholas Pope - Dahlman Rose & Company, LLC

Would that be something you're having in 2010 or beyond?

Michael Watford

We're mainly [ph](1:15:43) in 2010, there's nothing we would do that would significantly impact capital or production in Pinedale this point in time for 2010. If we make that decision, it will be later this year for 2011, 2012.

Nicholas Pope - Dahlman Rose & Company, LLC

And then, I guess, just going into the acquisition, a little housekeeping here. What cost do you have? Is the full cost reflected in the cash flow statement for the acquisition? I see some stuff for the consolidation of undeveloped land and the restricted cash. Is that fully reflected now? The acquisition in the cash flow statement? Are there anything remaining?

Marshal Smith

There was some timing effects of one, that resulted in less than the stated purchase price. If you flip back into the back portion of the Q, note to the talks of our oil and gas properties, you'll see that amount there was at roughly $320 million. That's the acquisition you're referring to is getting left on [ph](1:16:46) properties.

Nicholas Pope - Dahlman Rose & Company, LLC

And that $68 million, that's the balance, I guess, is that coming from joint ventures partners and who are participating?

Marshal Smith

I'm sorry, the $68 million?

Nicholas Pope - Dahlman Rose & Company, LLC

Yes, there's cash inflow of $68.4 million consolidation, is that coming from just partners participating in the deal?

Marshal Smith

No, that relates to the net proceeds from the high grading in consolidation of our land position that Sally referred to earlier. That's the net proceeds from those activities. So on the one hand, you had a net purchase price of $333 million for the acquisition that we talked and on the other, you had a $68 million in net proceed.

Michael Watford

So were down there to what, $266 million or so?

Marshal Smith

Right.

Nicholas Pope - Dahlman Rose & Company, LLC

And then just I guess, in terms of kind of ongoing, like what transport costs look like with the fixed capacity you'll have? Certainly, with the focus on the Marcellus, I guess going forward, the guidance you'll give for transport cost for the second quarter, is that like, kind of unit rate what we should expect? I mean, are we seeing the full effect of REX pipeline and all the fixed cost now and the unit costs, is that we should expect going forward?

Marshal Smith

You're seeing the full effects for the transportation cost on REX flowing through now. But keep in mind, that's basically a flat absolute rate. As our production volumes continue to ramp up, then you'll see unit costs, transportation cost per Mcf settle down.

Michael Watford

200 Bs of productions to 300 Bs production over a couple of years before unit and transportation costs drops significantly.

Operator

And with no further questions in queue, I would now like to turn the call over to Mr. Mike Watford for closing remarks.

Michael Watford

Well, thank you for your time and attention. And again, if you have any follow-up questions, don't hesitate to give, I guess, Julie a call. And if you can't get her, you can get Mark or myself. But thanks again and enjoy your day. Bye.

Operator

Thank you for joining today's conference, that concludes the presentation. You may now disconnect and have a great day.

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Source: Ultra Petroleum Q1 2010 Earnings Call Transcript
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