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Ultra Petroleum (NYSE:UPL)

Q2 2011 Earnings Call

August 10, 2011 11:00 am ET

Executives

Michael Watford - Chairman, Chief Executive Officer and President

Marshal Smith - Chief Financial Officer and Senior Vice President

C. Johnson - Vice President of Reservoir Engineering & Development

Brad Johnson -

Douglas Selvius -

William Picquet - Senior Vice President of Operations

Kelly Whitley - Director of Investor Relations

Analysts

Brian Singer - Goldman Sachs Group Inc.

Leo Mariani - RBC Capital Markets, LLC

Ronald Mills - Johnson Rice & Company, L.L.C.

David Tameron - Wells Fargo Securities, LLC

Andrew Parr

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc.

Devin Geoghegan - Zimmer Lucas Capital, LLC

Andrew Coleman - Raymond James & Associates, Inc.

Michael McAllister - Sterne Agee & Leach Inc.

Robert Morris

Noel Parks - Ladenburg Thalmann & Co. Inc.

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter 2011 Ultra Petroleum Corp. Earnings Conference Call. My name is Caris, and I will be your coordinator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And I would now like to turn the call over to your host for today, Ms. Kelly Whitley, Director of Investor Relations. Please proceed.

Kelly Whitley

Thank you, Caris. Good morning, ladies and gentlemen. Welcome to Ultra Petroleum's Second Quarter Earnings Conference Call. On the call with me 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 of Exploration.

Before turning the call over to Mike, I'd like to cover a couple of 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.

Second, we filed our 10-Q with the SEC last night. It is now available on our website or you can access it using the SEC's Edgar System. Now let me turn the call over to Mike.

Michael Watford

Thanks, Kelly. Good morning, and thanks for joining us. The second quarter of 2011 was a really good quarter for Ultra Petroleum. We achieved record production led by our growth in the Marcellus, a tripling on a year-over-year basis, and a new peak production record in Wyoming. Our financial metrics were strong. Earnings grew 23% over year-ago comparisons and cash flow by 34%. Our cash flow per share of $1.55 for the quarter equal the record set in the third quarter of 2008 when natural gas prices were $8 Mcf in the Rockies.

Since then, our production has grown as has our asset quality and inventory. Our current estimate of the low risk reserves, not resource potential, reserves is 20 trillion cubic feet, with an associated $29 billion of future development capital. At today's inflated oilfield service costs, that's an F&D cost of $1.43 an M [Mcfe]. That's one of the reasons why our cash flow and net income margins are so strong in a low natural gas price environment. In fact, our cash flow margin and cash flow per unit production for both the second quarter and for the first half of 2011 increased over similar periods in 2010, margin expansion in a low natural gas price environment.

Our Marcellus activity is accelerating with increasing activity each and every quarter, and with 2/3 of 2011's planned wells to come online during the second half of the year. Our reserve estimates, our EURs are increasing, and our partners want to add more wells to the program. In Wyoming, our productivity continues to increase, causing us to drill more wells with the same rig fleet. We have new plays to discuss, both in existing and new areas. Mark, you want to update the financials?

Marshal Smith

Sure. Thanks Mike, and good morning. As Mike outlined and as you've seen from our press release, we had another very good quarter with record production and ongoing improvement and efficiencies in the field. Further we continue to maintain our industry-leading margins and returns while preserving our financial flexibility.

In terms of natural gas price for the quarter, our realized corporate natural gas price before the effects of hedges increased 7% year-over-year to $4.38 per Mcf. Again, this quarter I want to emphasize this price before the impact of our hedges registered 101% in Henry Hub, well above our prior guidance range. Our natural gas hedge positions improved our average realized gas price by $0.79 per Mcf or 18% to $5.17 per Mcf. Condensate prices registered $92.35 per barrel for the quarter

Our production was up 13% on a comparable year-over-year basis to a record 59.1 Bcfe during the second quarter. This year-over-year increase, combined with a 7% improvement in realized natural gas price, were the primary factors driving our 22% increase in revenues, including the effects of our hedges of $325.6 million.

From a cost perspective, all of our costs were within or better than our guidance ranges. Corporate lease operating expenses for the quarter decreased year-over-year to $0.85 per Mcfe, primarily as a result of reductions in our unit operating costs.

Looking at our cash cost, excluding severance taxes or our field level costs, they decreased 7% year-over-year on a unit basis to $0.43 per Mcfe. As a result, our operating cash flow increased 34% over prior-year levels to $239.3 million, providing an operating cash flow margin of 73%, up from 67% in the second quarter of 2010. Cash flow per diluted share registered $1.55 during the quarter.

Adjusted for unrealized gains associated with a mark-to-market position in our hedges, our net income registered $101.9 million for the quarter for a 31% margin and $0.66 per diluted share.

In terms of breakeven levels, our net income breakeven is now $2.73 per Mcfe with cash flow breakeven at $1.15 per Mcfe. Our adjusted return on average capital employed on an annualized basis for the second quarter was 14%, and our adjusted return on equity was 32%.

From a balance sheet perspective, we continue to be very well positioned. As of the end of the quarter, we had $6.7 million of cash and cash equivalents on hand and $154 million borrowed on our bank facility, and interest rate of roughly 1.5%. Overall, our debt capacity is in excess of $2.5 billion and provides us with just under $800 million in unused senior debt capacity. As an update we plan to refinance our senior bank facility in the late third quarter, early fourth quarter in an increased amount up to roughly $1 billion.

I should point out that the Ruby pipeline went into service as anticipated in the latter portion of July, and we continue to expect the Kern River Apex expansion of $300 million a day to follow in the fourth quarter of the year. Again, we see excess Rockies natural gas pipeline take away capacity at roughly 4 Bcf a day extending for quite some time.

Moving on to hedging, as detailed on Page 10 of our press release, we have approximately 95.5 Bcf or roughly 76% of our remaining 2011 forecast natural gas production hedged through fixed price swaps at weighted average price of roughly $5.21 per MMbtu. In calendar 2012, we have about 129.1 Bcf hedged in the price of roughly $5.02 per MMbtu.

I'll wrap up my comments by again observing that as we look towards the remainder of 2011, we continue to see ourselves well on our way to meeting our objective of better than 20% growth in adjusted earnings and cash flow. Now I'll pass it off to Bill for an update on our operations. Bill?

William Picquet

Thanks, Mark. In Wyoming in the second quarter, Ultra brought on stream 43 net new producing wells, the average initial 24-hour sales rates produced new Pinedale producers with 7.2 million cubic feet per day. Ultra's operated wells averaged 7.6 million cubic feet per day, while the non-operated wells averaged 6.3 million cubic feet per day, drilled a total of 38 net new wells during the quarter.

Our drilling efficiency continues to improve. Reduced drill times are allowing us to sustain an excellent cost performance as the upward pressure in cost of services continues. We averaged $4.8 million per well in our operated program in Pinedale during the second quarter. For the quarter we averaged just over 12 days spud to TD for an Ultra-operated wells, a 17% improvement over the average for Q2 2010. This is another record for Ultra's drilling operations in Pinedale.

In the second quarter our average drilling time rig release to rig release was 15 days down 14% from our Q2 2010 average. For the quarter, 92% of our wells were drilled in less than 15 days spud to TD. Drilling a sub-15 day well is a milestone that we first reached just over 2 years ago in Pinedale. It's significant that we're now consistently below this mark achieving it with all rigs. We are often asked what are the limits to efficiency gains and we still don't know. We're now beginning to drill a higher number of wells below 10 days and we anticipate to continue to increase the success as we work toward this new target for the entire fleet.

We demonstrated the 15-day goal was achievable and our team believes that in time, the same will be true of our new 10-day goal. Our record well currently stands at just under 9 days spud to TD. Our drilling and completion operations cost of services has increased during 2011. We've been successful in finding new efficiencies to offset some of these increases. Our unique alliances with our service providers give us consistency and continuity in our operations, a key factor in our ongoing efficiency gain.

Upward cost pressures in our frac operations has caused an increase in our overall completion costs for the first time in quite some time. In Q2 we averaged 22 stages per well, our cost average is just over $83,000 per stage compared to $76,000 in Q1. We're increasing our focus on efficiencies and the completion operation, and we're confident that we'll continue to produce excellent overall cost performance. So far our successes in these efforts have enabled us to hold the overall average cost of drilling complete close to prior-year levels. With that, I'll turn things over to Brad for our Pennsylvania update.

C. Johnson

During the second quarter, Ultra Petroleum and its partners drilled 23 net horizontal wells in Pennsylvania compared to 17 net wells in the first quarter. Activity brings Ultra's total Pennsylvania shale program 133 net horizontal wells since its inception in 2009. The company also participated in 5 net vertical wells across this acreage.

Also in the second quarter, Ultra and its partners initiated production from 14 net horizontal wells versus 8 net in the first quarter. These wells had an average lateral length of 5,061 feet, with an average of 15 frac stages per well. Initial production of these wells averaged 5.8 million cubic feet per day. Currently, 10 drilling rigs and 3 completion crews frac given the company's Pennsylvania acreage position.

With net production for the quarter averaging 106 million cubic feet per day, we posted a 16% increase from Q1, a 321% increase from the second quarter last year. In the second quarter, Pennsylvania production reached a peak of 118 million cubic feet per day. And in July, Ultra's net production reached 131 million cubic feet per day.

In the company's operated acreage position located in its Northern area, Ultra completed 2 more extended lateral tests on the Pierson 810 pad, including the Pierson 810-3H well from the previous quarter, these 3 extended laterals on this pad had an average of 6,300 feet of lateral length, 21 frac stages per well and the laterals were spaced 750 feet apart. This set of extended laterals had an average initial rate of 8.3 million cubic feet per day. We shared additional well results in our press release that also demonstrate the high quality of our Northern area.

In Ultra's Southern acreage area, actual well performance and execution is well ahead of our expectations. In July, in a previously untested portion of Lycoming County, another 6-well pad was brought online, with an average initial production of 7.3 million cubic feet per day per well. These recent test, along with the production performance of previous wells, demonstrate much stronger results than our current 5 Bcf-type curve.

Consistently strong IPs, lateral declines and longer production histories from more than 125 wells is the reason Ultra is raising its type curve in 2 areas. In the northern area, Ultra is increasing its type curve ultimate recovery from 3.75 to 4.25 Bcf per well. This is being applied to the eastern half of Tioga County where over 60 wells have been producing for more than 180 days.

In the southern area of Ultra's acreage position, Ultra's increasing its type curve from 5.0 to 6.3 Bcf per well. Higher estimated ultimate recovery is being applied to certain areas in Lycoming and Clinton counties and is based on more than 20 wells producing at flatter production and higher flowing pressures than previously expected.

We have shared some of these observations before, but it's important to note again that the Marcellus horizontal wells continue to demonstrate flatter declines and increasing EURs with more production history. It is even more important to understand that Ultra's resource estimates are not based solely on conventional decline curve analysis.

The company has conducted advanced geological, geophysical and petrophysical studies to understand the rock. We have also incorporated analytical models for deep reservoir flow dynamics and completion efficiency and we have utilized advanced well performance models and firm our production forecast and reserve estimates. It is with strong intention that Ultra is rigorous and conservative with its reserve estimates and type curve models.

As we reported last quarter, the activity pace and production volumes in Pennsylvania are ramping up during the course of 2011. Significant increases were posted for the second quarter, and we expect that pace to increase even more in the second half of the year. In the first half of 2011, 33 horizontal wells were brought online. In July alone, 12 wells were brought online, thus demonstrating that our ramp up for the second half of the year is well underway. Expect to bring online twice as many wells in the second half of the year as we did in the first half of the year.

At this time, Doug is going to discuss more about our technical studies in Pennsylvania, and also an update on our efforts in new ventures.

Douglas Selvius

Thank you, Brad. Although we're getting quite comfortable with our Marcellus resource, we are constantly working to improve knowledge and gain further efficiencies. Last call, I mentioned a study we conducted with Schlumberger that utilized our well and seismic data to help identify Marcellus sweet spots. We since tested that model with additional completions that further support its usefulness to finding high-value areas. We're extending this work now across the rest of our data, and have realized similar success in matching seismic attributes to well performance. As a result, we're currently acquiring an additional 140 square miles of 3D data in an area we think lends itself to sweet spot delineation.

Something else we've talked about in the past are pilot studies for well spacing. Ultra has now completed 3 pilots, 2 with wells 500 feet apart and a third with wells spaced 750 feet. The first pilot at 500 feet performed poorly and made us think the wells were too close together. We've since taken a second look at this area in light of our seismic work, and now think those wells are poor for geologic reasons, not because they were too close. A second pilot, also at 500 feet, yielded much more encouraging results, and the same is true for our third pilot at 750 feet. We need to watch all of these pilots for a while to understand interference effects, but downspacing looks like a real possibility, and we have 3 more studies planned between now and the end of the year [indiscernible].

The other studies we're conducting are focused on completion technique. We've been testing fluid and profit volume, stage spacing and curved cluster counts, all in an attempt to maximize efficiency. Early data suggests we can possibly reduce stage counts and profit volumes without materially impacting well performance. This is early information that needs verification, but if it holds up, the savings will be substantial. For that reason Ultra and its partners will be conducting 2 more well spacing pilots, 3 more stage spacing pilots, 2 stage volume pilots and at least 1 curve cluster pilot in the coming months.

I'd like to move away from the Marcellus now and make a few comments about the Geneseo and our new ventures effort. In the Geneseo, we TD-ed our first horizontal well in late March. We drilled a 4,300-foot lateral and kept it in zone the entire length. Completed the well 2 months later and began flowing it back on June 4. After achieving early flow back rates of 2.5 million a day, the well stabilized at just over 1 million a day. And has been steady at that rate for over 60 days now. We're encouraged by this test and we're also encouraged by the reports we're seeing from other operators in the area. As a result, we're trying to learn as much as we can about the Geneseo. We've acquired core in 2 wells and have plans to acquire core in 4 more wells in the coming 6 months. We're also making plans to drill as many as 5 Geneseo laterals during that same period. Our geology indicates the Geneseo has potential across 75% of our acreage positions, so we're going to keep working to delineate.

Let me finish now with a few words about the new ventures. We've assessed resource opportunities throughout North America, and it's no secret we've seen some things we like in the Niobrara. Because of that, we've assembled roughly 100,000 acres in the DJ Basin. We're not in the center of the current Niobrara activity, though. This is an exploratory venture for us, but I'd like to emphasize that we don't jump into plays like this recklessly. There are a number of factors driving our decisions, and I'd like to summarize the main ones.

First, we've done the regional work to support our decision. We've mapped all 3 chalk benches from both a structural and a thickness standpoint. We've also mapped thermal maturity and net oil pay across the DJ Basin. Second, beyond regional mapping, we have 30 feet of recent conventional core from a Niobrara bench in the middle of our leased position. We got a full suite of shale logs including fracture identification logs from that same key well. We also have 21 square miles of 3-D seismic data and regional gravity and regional arrow magnetic data.

Everything we've seen so far indicates our leasehold is every bit as prospective as Weld and Laramie counties, where it's currently being played. Our rock quality from a porosity, oil saturation, lithology, brittleness standpoint is every bit as good, if not better than it does in those areas. We have positive indications of fracture in our well logs and regional work indicating the area is likely to be fractured. In short we like what we see.

Third factor behind our decision is cost. We have assembled an attractive leasehold position in a highly prospective area at costs much lower than leases in Weld and Laramie counties. We're currently making plans to drill 4 exploratory wells across our acreage position this winter. We'll be acquiring modern shale logs and taking additional Niobrara core. Our intent is to test the Niobrara chalk benches individually in these wells as all 3 look prospective in the area, and we want to determine where the value is. We plan to test the resource with horizontal wells early next year.

Assuming EURs of 250,000 barrels per well and 320 acre spacing, our acreage position exposes us to well over 50 million barrels of potential. Other well spacing could more than double that, and at the same time we're continuing to grow our leasehold position out there and are optimistic this new play will add significant value to the company. Now let me turn it back to Mike for some final comments.

Michael Watford

Thanks, Doug. As opposed to summarizing our comments today, which is my normal style, let me just list some second-half expectations. In Wyoming, our legacy property, we will continue to increase efficiency and productivity while enjoying healthy margins in a low commodity price environment. We have an extensive inventory of wells to drill, over $13 billion of future development capital.

In Marcellus, we are barely scratching the surface and we're enjoying improving results. Our Marcellus activity will continue to accelerate into 2012 with more wells drilled, completed and put online.

For second-half production, our July company production just set a new monthly record. Now we are excited about the opportunities in the Geneseo and Niobrara and we'll work to evaluate those. We will deliver 20% growth in earnings and cash flow for the calendar year.

And on a net asset value comment, Ultra's year-end 2010 proved reserves were 4.4 trillion cubic feet equivalent, and that included a 3-year limit on PUDs, our more conservative nature. We disclosed that exclusive of that PUD limit, our proved reserves do total 8.8 trillion cubic feet equivalent. Of course with our success in 2011, the number has grown. But at the 8.8 trillion cubic feet equivalent of proved reserves, if we looked at our enterprise value today of somewhere near $7.8 billion, $7.9 billion equity in debt, then Ultra is valued at about $0.89 an Mcfe for proved reserves, which in my mind is quite a bargain when you look at our low-cost and our resource upside. With that, I'll end my comments and take any questions.

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

Can you talk to some of the geological characteristics you see or expecting south -- in your position south of Denver, and how that compares to maybe what you or others are seeing in the Wattenberg or central DJ basin?

Douglas Selvius

Sure. Any particular characteristic you're interested in or just...

Brian Singer - Goldman Sachs Group Inc.

I mean, I guess, and ideally would be thickness, depth, liquid to content, and then if you have any initial expectations for EURs and well cost.

Douglas Selvius

There's a lot of items there. From a thickness standpoint, we've got all 3 benches and I'm sure you're familiar with the A, the B and the C that's typically discussed across the basin. The one that looks best to us petrophysically is the C, and it's in the 35- to 50-foot, it's actually the 65-feet in thickness range. The A and the B are actually thicker in certain areas. The A and B don't have lateral extent to cross the entire position. It's primarily the C. But they're all pretty good thickness. Resistivities, you didn't mention that one, but we've got resistivities in the 50 to 60 ohm range. We expect it to be oil saturated. Water saturations 25% to 50% in the good zones. A little bit higher than that in some of the miles in between. I answered, anything else that I neglected there?

Brian Singer - Goldman Sachs Group Inc.

I think you mentioned you thought it would predominantly oil or did you have a sense of what GORs or oil & gas NGLs breakout would be?

Michael Watford

We don't have that yet, no.

Brian Singer - Goldman Sachs Group Inc.

Okay. And then you may have mentioned this earlier in the Marcellus, can you just talk to backlog of wells? Apologies, again, if you mentioned this drilled uncompleted and then completed and awaiting time.

Brad Johnson

I can answer that, Brian, this is Brad. At the end of the second quarter, we had 78 wells waiting on completion and 32 wells completed and waiting on hookups.

Michael Watford

That's gross wells. Let's talk net. On a net basis, the number I think is 53 wells waiting on completion and gathering to go online. So the backlog has grown over the course of the year, plus that's aimed at one of our partners up there. And who is accelerating and wants to go even faster next year. They talk about doubling their effort in 2012 versus 2011, which we're not on board with yet. But they continue to add human resources and technical resources to catch up. But bottom line is, the backlog has grown. The 53 net wells, which is more than $0.25 billion of idle capital for us. So we're visiting with them routinely to see if we can help them move forward faster.

Operator

And your next question comes from the line of David Tameron with Wells Fargo.

David Tameron - Wells Fargo Securities, LLC

Mike, can you talk about 3 quarters back, I guess you laid out a 20% kind of growth target over the next 3 years. Can you talk about -- is that still on track for '12? And if so, if you hold the Pinedale flat, that essentially means doubling kind of full year Marcellus. Is that 20% still a target and secondly is that the right way to think about that?

Michael Watford

I think that's the correct way to think about it, David. A year or so back, we talked about an early 2012 target, 290 Bs or thereabouts. And that means -- let me talk about Marcellus first. Talking about 40 plus or minus Bs, probably more than 40 Bs of production in 2011. Our early look at 2012 is anywhere between 80 to 100 Bs. And that's without much of a reduction in the backlog. So if we can get better performance from one of our partners up there to where that backlog shrinks which is what they're committed to, then that range goes up, obviously. But if we think of 80 to 100 Bs there and we think of 200 to 210 Bs in Wyoming, then we're at 280 to 300. The odds are that moves up given progress in Marcellus, which we see. I mean we see July record production for the company with most of that growth coming from Marcellus. We see more wells about -- already being completed within the gathering system for August and September. So it's about to happen. But we're not committing to it yet until we see more real evidence.

David Tameron - Wells Fargo Securities, LLC

Okay. Can you give us any color -- obviously, with higher cash flow or higher production, higher cash flow, can you give us a sense for and where you'd expect, call it E&D levels, '12 versus '11 on the CapEx front?

Michael Watford

Well, right now, assuming there's no more oilfield cost inflation which hopefully with slightly lower oil prices it brings it down some. We're a fan of $80 oil, we like that. We would anticipate that 2012 CapEx would be less than where we are in 2011 now.

David Tameron - Wells Fargo Securities, LLC

Okay, E&D CapEx or total CapEx? You have some acreage in there this year, right?

Michael Watford

We have some acreage in there, but again right now we're not forecasting 2012 CapEx other than 350. We would have something less than that, but we're really not quite prepared to go there yet.

Operator

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

Leo Mariani - RBC Capital Markets, LLC

Just wanted to kind of touch base on the CapEx once again here. Wanted to get a sense of how much of the incremental 2011 CapEx, I guess, the roughly $250 million through your prior budget is going towards new acreage here.

Michael Watford

Only about $10 million is new acreage. We already had a $30 million budget before, so we just bumped it up to $40 million at this point in time.

Leo Mariani - RBC Capital Markets, LLC

Got you. Okay. And I guess with respect to the Niobrara, you guys continuing to pick up acreage there or are you guys kind of content with your 100,000 acres at this point?

Michael Watford

We're not content. We're continuing to pursue acreage out there.

Leo Mariani - RBC Capital Markets, LLC

All right. And I guess in terms of well cost, just wondering what you guys are spending right now in Lycoming County on the Marcellus and Tioga? And if you could comment on the Geneseo well cost also.

William Picquet

Sure. Well cost up in the Northern area are running about $4.8 million per well. Down South where they're deeper and longer laterals, those costs are running to $7.5 million per well. And with respect to the Geneseo those costs are slightly less than our ordinary acreage, $4.5 million per well range. Those wells are drilled about 1,500 feet shallower.

Operator

And your next question comes from the line of Jessica Chipman with Tudor, Pickering, Holt.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc.

Just real quickly, I wanted to ask on the CapEx raise, how much of that was due to third-party activity?

Michael Watford

Let me go at it this way, we had 11% increase overall for just cost inflation, which is about $130 million. And that is clearly far more weighted to Marcellus than it is Wyoming. I would say maybe 70% or so off the top of my head or more. So maybe 80% there and that's going to be all outside operated at this point in time. So the remainder would be the Wyoming. And that $110 million associated with more wells, more wells being drilled in Wyoming because rig fleet is more productive getting wells down faster or net wells, and then more wells in Marcellus because our partners are smiling broadly at the success and wondering why we're so conservative in our reserve estimates. But nonetheless, they want to drill more wells and we want to see them drill more wells because the returns are outstanding even at $4 gas prices.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc.

Okay. That helps. And then you gave a lot of really good color on the Niobrara. Just wanted to see I think one thing that wasn't hit was what depths and what well cost do you expect for the first well.

Douglas Selvius

We appreciate your report yesterday, Jessica. The depths we're looking at, we're probably 1,000 to 1,500 feet shallower than the wells in Laramie County area. Where our acreage spans probably 4,000 feet down to 7,500 feet, something like that. And I can't remember what else you asked. I'm sorry.

Jessica Chipman - Tudor, Pickering, Holt & Co. Securities, Inc.

Just on well costs expected.

Douglas Selvius

Well costs, we're projecting the $4 million to $4.5 million for a completed lateral.

Operator

[Operator Instructions] And your next question comes from the line of Noel Parks with Ladenburg Thalmann.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Looking ahead to the Niobrara, and this maybe a bit early, but assuming success out there, do you have any sense of what your infrastructure investment might look like? How aggressive you'd be as opposed to relying more on third-party infrastructure and to the infrastructure you know existing so far.

Michael Watford

There is no existing infrastructure. So we just haven't dealt with that yet. We want to go in there and drill some vertical wells first and then based on that, go drill our horizontal wells, so we're not really ready to even deal with the infrastructure issue.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Sure. So a little soon than to think about whether you look to do it alone and sort of be more aggressive on your own in that respect?

Michael Watford

That's correct.

Noel Parks - Ladenburg Thalmann & Co. Inc.

Okay. I noticed you're talking about the Niobrara spacing, your ideas of that. I'm assuming that's more or less on the conservative end of things at this point?

Michael Watford

Exactly right. It could easily go down from 320 to 160s.

Noel Parks - Ladenburg Thalmann & Co. Inc.

And just -- sorry if I missed this. Can you talk a little bit about your process of elimination in the acreage that you did go after increasingly, especially over the last few months people have ventured even further and wider in pursuing the Niobrara, some folks much further west, some folks a little deeper into the Powder River Basin and so forth. Can you just talk a little bit about how you prioritized your particular targets?

William Picquet

Basically it was based on regional geology. I think the initial thing that got us interested was just mapping those individual Niobrara ventures out. You saw a very similar characteristics. As we acquired more data, we started to drill down into the lithology variances, the porosities, the perms. We were very fortunate to get that core in the full suite of recent jail logs that everything we're looking at shows us the rocks we've got are very comparable if not better than what's up in Laramie where these are going on. It was driven just by regional mapping. Does that answer your question?

Noel Parks - Ladenburg Thalmann & Co. Inc.

It does. Yes.

Operator

And your next question comes from the line of Ron Mills for Johnson Rice.

Ronald Mills - Johnson Rice & Company, L.L.C.

Mike, based on your comments just trying to look at the percentage of Pennsylvania versus Wyoming. The Pennsylvania budget went up $175 million, $185 million. I'm trying to back out the cost increases that you highlighted on average then, would that suggest that your overall activity level looks like you may drill another 15 to 25 net wells in the second half of the year? Is that the primary driver behind that big Marcellus increase?

Michael Watford

Part of it is the service cost inflation that was asked about with more than $130 million some, maybe, 80%, as Brad was waving at me, aimed towards Marcellus. And the remainder is net wells. I think that the net well ad is 8 on the Anadarko side. Our budget with Anadarko has gone up from $120 million to $220 million over the course of the year. That has to do with their well cost not being where we thought they would be. They still don't have fit-for-purpose rigs, they still don't have their water distribution system built. They've got a number of inefficiencies. We thought their well cost now would be down closer to $7 million, to $6.5 million or is it $7.5 million. So we're dealing with that reality. In fact they're drilling 6, 7, 8 B wells and maybe even some 9, 10 B wells in some of the areas makes it very economic. We just need to right size our capital expectations. So it is more net wells there clearly.

Ronald Mills - Johnson Rice & Company, L.L.C.

And I'm assuming it's not just those 8 net wells you also have an increase in terms of net wells under the -- with shale up in Tioga as well?

Michael Watford

No, that's not true. The shale was not meeting expectations. We've done a better job at drilling it behind completions and online. We've allocated a tremendous number of additional human resources to try and get permitting caught up, try and get gathering systems caught up, try and get right level of compression. We thought that with their acquisition of East in July a year ago, that would be behind them. But it's not behind them, they've tried to accelerate and they've hit a few bumps in the road. We're confident they're going to get it right. It's important to them. They spent $5 billion of buying this property. They wanted double activity next year, but we're less inclined to do that. So there's no lack of enthusiasm. They just need to catch up with where they're behind before we'd agree to go do that. But there is no new activity in terms of drilling there, no addition.

Ronald Mills - Johnson Rice & Company, L.L.C.

And on the Geneseo, 75% of your acreage, is it more prospective on the Northern portion of your acreage on the Southern portion? And I'm assuming that -- is that first well is that one that you operated and not under either Anadarko or shale?

Michael Watford

That is correct. The first well that I was mentioning in the call was the one that we drilled. I think the Geneseo is prospective across all of our Northern acreage. And a good -- the Eastern half probably of our Southern acreage, where it gets to the far Southwest it starts to get pretty thin and doesn't seem to have the shale look you want to see out there. Everything to the North looks prospective and the East half of our Southern.

Operator

And your next question comes from the line of Bob Morris with Citigroup.

Robert Morris

Mike, just one more question on the Niobrara. Well, your position in your acreage down there, there are already huge water shortages and municipalities fighting over water rights there. How are you positioned for water in frac-ing these wells?

Michael Watford

I'll let Doug answer it, but we're in great shape. Go ahead, Doug.

Douglas Selvius

There is groundwater present in the area. We don't expect this to be without challenge, but there's groundwater that exists and we believe we're going to get access to the rights.

Michael Watford

Remember, we're buying 18,000 acres in fee, the service and everything. And then we have, well I won't go into details, but 100,000 acres leased. Water's not going to be an issue. We don't need potable water, remember that.

Operator

And your next question comes from the line of Michael McAllister with Sterne Agee.

Michael McAllister - Sterne Agee & Leach Inc.

How much of the new acreage is on federal land?

Michael Watford

0.

Michael McAllister - Sterne Agee & Leach Inc.

0?

Michael Watford

0.

Operator

And your next question comes from the line of Andrew Coleman for Raymond James.

Andrew Coleman - Raymond James & Associates, Inc.

You may have covered this at the beginning, do you guys have deeper rights for this acreage in Colorado or is it just for Niobrara?

Michael Watford

We're on all depths.

Andrew Coleman - Raymond James & Associates, Inc.

Okay. Given your portfolio mix and the recent move here in the oil price, do you think there's service companies have been a little more receptive to you guys or is there any opportunity you might have to accelerate some of this testing?

William Picquet

I'm not sure I understand the question. We're not -- we're going to be able to get services down there, if that's what you're asking.

Michael Watford

Yes. Our issue is how fast we go in evaluating. It has nothing to do with service cost availability or service availability.

Andrew Coleman - Raymond James & Associates, Inc.

Okay. Let me ask it then, I guess this way. Given the higher gas waiting of your portfolio there, I guess how much more insulated are you to I guess slowing down activity? I mean we've heard some operators say that around $70 a barrel would impact them. Given your existing portfolio there, can you -- obviously at current gas prices, you can keep going. How much more insulated are you on the oil side if that price continues to fall?

Michael Watford

Let's deal with our economics or sort of exploration-based economics. You want to go through that, Brad?

Brad Johnson

Sure. On the economics for Niobrara, we're using 250,000 barrels per well, 4.1 for drill complete and equip of horizontal wells into [indiscernible] mode. A lot of factors are still yet to be determined with respect to the rock, fluid types, but breakeven prices could get $30, $40 per barrel depending on fracture content, kind of GORs we encounter. We are focusing our efforts on higher quality Niobrara acreage. We believe within a success case, we would have a lot of room for margins.

Michael Watford

$70 to $80, it's very economic.

Operator

[Operator Instructions] And your next question comes from Devin Geoghegan with Zimmer Lucas Partners.

Devin Geoghegan - Zimmer Lucas Capital, LLC

I was wondering if you can shed some clarity on 2013's guidance as well, given your comments on 2012 and then how the timing of the backlog impacts the speed of the production in terms of the beat relative to your current '12 guidance versus '13? If that makes sense.

Michael Watford

I think I'm sticking my neck out to talk about 2012. I don't think I have anything to add about 2013. I mean 2012, that Marcellus piece at 80 to 100 Bs without any significant reduction in the backlog, obviously with the new reduction backlog, 50, 55 net wells is a big production boost. And I'm confident, very confident, all of that will be behind us by 2013.

Devin Geoghegan - Zimmer Lucas Capital, LLC

So when do you think the backlog will be removed?

Michael Watford

Well, we don't -- right now, we're not planning on it being removed in our forecast. That's why there's so much upside to the volumes. I'm just going to know they're working it diligently, but right now we're going to be very conservative with our estimates.

Devin Geoghegan - Zimmer Lucas Capital, LLC

But just to clarify, if the backlog were removed, there is significant upside to the 3-year plan that you guys have already gone out with.

Michael Watford

Yes, absolutely.

Operator

And your next question comes from the line of Andy Parr with Fidelity.

Andrew Parr

What's the gross well count now for the Pinedale?

Michael Watford

Wells that have been drilled historically?

Andrew Parr

No, sorry, for the year. The new well count. Gross operated well count.

Michael Watford

Gross operated. Hold on, Brad will get it for you. The gross total is 234, something like that.

Andrew Parr

And how many operated rigs is that?

Michael Watford

We have 8 operated rigs. And Andy, I'm sorry, that wasn't in operated, that was in gross. But we'll get it for you.

Operator

And at this time, there are no further questions in queue. I would now like to turn the call back over to Mr. Mike Watford for closing remarks.

Michael Watford

Well, thank you. I want to thank everyone on the phone this morning. We look forward to updating you on our third quarter results this fall. If anyone still have questions, please call the Investor Relations team. Thank you.

Operator

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a wonderful day.

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