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Ultra Petroleum (NYSE:UPL)

Q2 2012 Earnings Call

August 02, 2012 11:00 am ET

Executives

Michael D. Watford - Chairman, Chief Executive Officer and President

C. Bradley Johnson - Vice President of Reservoir Engineering & Development

Marshal D. Smith - Chief Financial Officer and Senior Vice President

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Mark P. Hanson - Morningstar Inc., Research Division

Subash Chandra - Jefferies & Company, Inc., Research Division

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Robert L. Christensen - The Buckingham Research Group Incorporated

Operator

Good day, ladies and gentlemen, and welcome to the Second Quarter Ultra Petroleum Corp. Earnings Conference Call. My name is Lacey, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today's call, Mr. Mike Watford, Chairman, President and Chief Executive Officer. Please proceed.

Michael D. Watford

Thank you, operator. Good morning, and thank you all for joining us today. With me is Mark Smith, Senior Vice President and Chief Financial Officer; Bill Picquet, Senior Vice President of Operations; Brad Johnson, Vice President of Reservoir Engineering and Development; and Doug Selvius, Vice President, Exploration.

I'd like to point out that many of the comments during this conference call are forward-looking statements that involve risks and uncertainties affecting outcomes, many of which are beyond our control and are discussed in more detail in the risk factors and forward-looking statements section of our annual and quarterly filings with the SEC. Although we believe these expectations expressed are based on reasonable assumptions, they are not guarantees of future performance, and the actual results or developments may differ materially.

Also, this call may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website also.

Let me start my comments this morning by picking up where I left off last quarter. I shared a view where I thought that natural gas prices have bottomed, that production was flattening, that natural gas rigs would continue to decline and a correction in pricing was imminent. We were limiting our investments with reductions in capital while preserving our valuable long-life assets. We also anticipate a noncash accounting directed ceiling test write-down caused by unsustainably low natural gas prices. This write-down muddies our financial statement presentation going forward, but has no lasting impact on the health of our business. Today, that view expressed 3 months ago appears fairly accurate.

Now let me summarize our financial performance for the quarter. We produced 65.1 Bcfe, just above our quarterly guidance range with strong well performance and better runtimes offsetting planned reduced completions in Wyoming and a slower partner activity pace in Pennsylvania. Our hedged natural gas price for the quarter was $4.04 per Mcf. On an unhedged basis, our realized price was $2.23 per Mcf, down 49% year-over-year. We've hedged 103 Bcfe, representing over 80% of our remaining 2012 production at a weighted-average price of $4.31 per MMBtu. We generated $190.6 million in cash flow or $1.25 per diluted share and $55.1 million or $0.36 per diluted share and adjusted net income during the second quarter.

Primarily due to dramatically reduced trailing 12-month natural gas prices, we recorded a full cost ceiling test write-down of $1.1 billion net of taxes at the carrying value of our natural gas and oil properties. Oil and gas property accounting rules do not allow us to increase the carrying value of our properties when commodity prices improve. Said in another way, it's a one-way street.

As you are probably aware, the 2 primary reserve accounting standards for E&P companies are full cost and successful effort methods. Impairment tests for the successful effort methods are subjective and differ from the full cost method in 3 primary ways. First, the successful efforts impairment test is based on expected future commodity prices as opposed to trailing 12-month average pricing for full-cost companies. Second, successful efforts impairment test are valued on 3P reserves, whereas full-cost companies are limited to proved reserves alone. Finally, future cash flows are measured on an undiscounted basis for successful efforts companies, compared to future cash flows discounted 10% for full-cost companies. As a result, successful-effort companies are less susceptible for ceiling test impairments during periods of low prices.

For the quarter, our all-in costs were $3.16 per Mcf, about the midpoint of our guidance range. Our industry-low cash costs were $1.40 per Mcf, resulting in a cash flow breakeven of an impressive $1.30 per Mcfe. Our focus on low costs allows us to defend our margins even during low points of the commodity price cycle. Our net income margin was 19% and our cash flow margin was 67% for the second quarter.

Looking at our CapEx investments for the first half of 2012, we've already invested about 2/3 of this year's $825 million budget, which as a reminder, is half of our 2011 capital program. Our activity and capital spend rate will slow further as we correctly respond to the price signals. Adjusted for the expected midstream asset sale, our net CapEx for the year is $625 million. We produced 133 Bcfe in the first 6 months of 2012 with an expected 122 Bcfe combined production plan for the third and fourth quarter of 2012. Production lags capital spending, which is why we haven't seen a volume reduction on a year-over-year basis, but it is imminent not only for all throughput for the rest of the prudent natural gas producers that have cut spending. Our recent industry production data shows flat volumes, but production declines will soon be evident.

In response to oil natural gas prices and the need to reduce the natural gas supply, you will recall we released 4 operated rigs in Wyoming earlier this year. We expensed the remainder of our rig-cancellation fees in the second quarter of $4.7 million, totaling our exposure of $9.5 million.

In Wyoming, we continue to experience better-than-anticipated field operating efficiencies, particularly given the challenges earlier in the year as a result of the compressor station outage. As a reminder, at the end of April, we suspended completions in Pinedale for the remainder of the year. The compelling economics tell us that deferring completion for 12 months requires a mere $0.15 per Mcf uplift in natural gas price to achieve the same rate of return we would have otherwise realized by completing the well today. This deferral decision allows us to preserve capital, and produce our asset in a more profitable environment of higher gas prices, increased cash flow and better returns. This is particularly important to us as we are drilling in the more prolific areas of the field and plan to stay there for the next few years. We are witnessing peer companies follow our lead in deferring completions to achieve future higher returns. We think more companies should adopt this prudent practice.

This reduced activity level has allowed our geoscience and engineering teams the opportunity to go back and analyze the historical field data. In doing so, we discovered a correlation between seismic reflection character and reservoir quality. We're now utilizing this work to guide our current investment decisions related to well sequencing. We're also working to develop better log analysis techniques, which will help identify the highest values in our -- some well bores. Our goal is to further improve overall development efficiency in the field.

To briefly update you on our Niobrara progress, we are still analyzing the core and log data collected from our 3 vertical wells. We are continuing to receive core data, but the most important components will not be available until November. We don't have any lease expiration issues until 2014, so we're not rushing to drill horizontal wells in advance of the data.

Glancing at our Pennsylvania operations. Our horizontal Marcellus program continues to deliver strong well performance and execution. For example, 2 pads in Tioga County were brought online with average IP rates of 8.3 and 9.4 million cubic feet per day. In addition to Lycoming County pads, each came online with constrained rates of 6.2 million cubic feet per day. Year-to-date, we have drilled 58 wells and brought online 77 wells, making significant progress towards reducing our inventory wells waiting on completion of pipeline connection. We are seeing reduced well costs in one of our joint venture areas and are continuing to be diligent in our investment pace during the current gas price environment. In our news release, please note an updated type curve that reflects a flatter decline, an additional production data through to 540 days.

3D seismic has become invaluable to our Marcellus development efforts and we're continuing to use it for sweet spot identification. Last week, we received 140 square miles of new 3D data that essentially covers the remainder of our acreage position in Tioga County. With this additional data, we continue to expand implementation of this technology, using it to guide investment decisions in this area. Fortunately, Shell has continued to slow the pace of activity in our joint venture, allowing us to realize the full benefit of this 3D data going forward. The original drilling plan cover 182 wells during 2012. Last quarter, that count was reduced to 112 wells and now stands at 95. We're encouraged that Shell's reacting to our suggestions and market conditions in the Marcellus by slowing their activity in investment pace.

And our other joint venture, Anadarko, with the last rig out of our AMI in early July and has no plans to bring a rig back anytime soon. Due to the high quality resource in this area and positive returns of today's gas prices, we plan to continue completing wells for the end of the year.

We're seeing greater potential for economic development in the Upper Devonian Geneseo formation. Today, we brought online 3 wells and tested a fourth, all broadly distributed across our acreage position. Using these results, along with our regional geologic and engineering analysis, we're beginning to identify high-value areas in the Geneseo, where well performance could equal or possibly even exceed Marcellus well performance. In other words, it looks like we have a stack development opportunity for both Marcellus and. Geneseo under a significant portion of our Pennsylvania acreage. We have another Geneseo well due to come online this month and that additional data should enable us to start quantifying our total resource potential.

Today's extremely low natural gas price is caused by the imbalance of supply and demand are simply not sustainable. Even low cost, Ultra Petroleum struggles in a $3 per Mcf gas whirl. Capital is being withdrawn from natural gas investment as seen by a rig count reduction and pressure pumping softness. Production lags capital expenditures and declining production is imminent. We see $4 gas in 2013 and a $5 gas, 2014.

We'd now like to open the line for questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And our first question will come from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you talk to the -- any trends that you expect looking out into the fourth quarter versus the third quarter as it relates to production, i.e., would you expect the same pace of decline that you see in the third quarter continuing into the fourth quarter? Is there anything unique in terms of the timing of completion to coming on that you would see moderating that decline?

Michael D. Watford

I think it'd be pretty consistent, Brian. I mean, we're not completing any wells in Pinedale because the returns are better if we just wait. Particularly, we are return-driven, not production-driven. And we have some ongoing completions in Marcellus with Shell and Anadarko. But they're at a pretty steady rate. So, no, I don't think you'll see anything different.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And I guess, do you have any early read on how you're looking at 2013 and how that would change if gas prices are being at $2.50, $3.50 or $4.50?

Michael D. Watford

Oh, I mean if gas prices are $2.50 or $3.50, you'll see us spend less money. That $4.50, well, maybe at $4.50, we won't spend any more money we did this year. We have -- maybe a view that says production supply is about to shrink pretty rapidly. I think there's some comments out yesterday with some companies and announced and talked about in Haynesville that they would see a 10% per quarter reduction in their production. I think it's plus or minus 40% for the year. If you apply that sort of over a 6 b per day Haynesville production. And then like 2.5 b's on annual rate of reductions, so I think we're about to see a lot of drop in supply. We are returns-focused. We always have been. I do simple math, 250 b's of production at $4 gas gives you $1 billion revenue. 230 b's of production at $5 gas gives you $1,150,000,000 revenue. Clearly, my cash flow and earnings are enhanced at the lower production and higher volume price. So we're going to wait for commodity prices to invest in the assets. We have tremendous asset. We're only getting better. So there's just no hurry for us to score capital.

Brian Singer - Goldman Sachs Group Inc., Research Division

And lastly, on the Geneseo, any more color on -- you mentioned a significant chunk of your acreage has -- you feel good about. Can you add any color across for 1% that represents? And where do you think the Geneseo rates of return are superior to both Marcellus and Pinedale or one or another?

Michael D. Watford

To answer your first question, it really, the percentages really have not changed much from what we said on the last call, which was around 70%, I believe. We're still affirming that and the well results we're getting validate that position in terms of how the rates have returned. Stand up, Brad. Do you have a comment?

C. Bradley Johnson

I will just add that we see the potential for the Geneseo to deliver similar returns to the Marcellus and in similar returns to the Pinedale. So it will be another item for us to develop and then go forward.

Michael D. Watford

So resources gets larger.

C. Bradley Johnson

Resource is large.

Michael D. Watford

Yes.

Operator

And our next question will come from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just wanted to -- if there's any more color around the midstream asset sales? I guess that's -- you're still in progress. Not sure if you guys are at final negotiations with potential buyers? Any color you had around that would be helpful.

Marshal D. Smith

Leo, this is Mark. We continue to move forward on monetization of that system as you described. We're well-advanced in the process. We've narrowed down the playing field. We're optimistic in terms of being able to get across the finish line. Just stay tuned.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, great. In terms of Marcellus, you mentioned that one of your partners is making progress in reducing well costs. Can you give us some quantification there? And I guess, additionally the Marcellus, I guess you said the Anadarko is not running any rigs. How many is Shell running on your JV property now?

C. Bradley Johnson

Sure, this is Brad. On the rig count question, Shell is currently running 3 rigs in our AMI in Tioga County. On the low-cost front, the Anadarko costs we see trend down, impressively down to the $7 million range. So costs are still holding at $7.5 million.

Michael D. Watford

And I guess you want to add that Anadarko is extending their lateral length.

C. Bradley Johnson

Yes, $7 million that Anadarko spends are drilling deeper and longer. So they've been able to cut costs despite drilling longer.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And where is that current lateral line to get to the $7 million number there?

Michael D. Watford

Anadarko's averaging 5,700-foot laterals across the program right now. And that compares, to give that a comparison to Shell, Shell's at 4,200 feet.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. I just wanted to clarify in the Pinedale. So at this point, you guys have no plans to complete any wells for the rest of the year. I think at one point, you all talked about, if we got north of $3, you might complete some wells. Is that totally off the table for this year? And we could just kind of look at maybe some completions this winter into early next year? How should we think about that?

Michael D. Watford

Our current plans are to defer completions until 2013.

Operator

And our next question will come from the line of David Tameron with Wells Fargo.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Mike, can you talk a little bit -- can you just give us more clarity? You're saying at $4 gas or $4.50 gas, you want to accelerate drilling? Or what level -- can you just give us a sense for what level of gas you put money back to work in the Pinedale and Marcellus, given current service costs?

Michael D. Watford

Well, I mean I think one of the cusp was getting higher natural gas prices and lower service cost. So my view right now is, the more patience we have, the more reward we're going to have. Let's do this. This time last year, the forward curve 2013 said gas prices would be $5. And then at -- and our stock price is $45 a share, I thought I'll add in there. As we move forward through the remainder of 2011 and early 2012, with more supply and no winter, gas prices bottomed out. And for 2013, our futures carry about $3.20 sometimes in April. Since that time, they've bounced back up to go about $3.70-ish. And we think they're going to continue. We think they're going to be $4 for 2013. And we think as we walk forward, that just gets better because we think we're going to have reasonable winter and supply shrinking. So it's -- we're just not in any -- again, we're return-driven. We're not cash flow-driven because that doesn't say we can make a dime. I think a number of folks in the Bakken today have rich cash flow, but not making any money at all. They're not giving return on investment. So we want a return. I have an old-fashioned view, and we think gas prices are going to go back up to $5 as soon as they came down from $5 to $3. And our current valuation is -- where are we? $3.3 billion, $3.4 billion in equity and $2 billion of debt, so $5.4 billion, $5.5. billion. That sort of implies, and I think our PV-10 at year-end 2011 on our proved reserves at $4 gas price was $5.3 billion. So we basically traded that $5 gas price on -- in our reserve base. With all the PUDs, it's about a $9 billion valuation. So less $2 billion of debt, that's $7 billion of equity that's factored at $45 of share price. So I'm saying that we're not likely to increase capital at all until we get closer to $5 gas price. And we think we have reasonable expectations that occurring over the next 12 months from the forward curve. And that should drive our stock price to a doubling of where it is now. And I think more and more people have our attitude. And therefore, gas prices -- I mean, gas supply will shrink faster than anticipated.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

Okay. Let me ask you another question. There is -- any comment or -- have you guys looked at any oil plays? I know you drill in Niobrara, but have you looked at any type of acquisitions outside of core areas to get a little more oily?

Michael D. Watford

We have -- we're return-driven. I want to keep using that because again, our error was that at $4 gas, we have a highly profitable business for like the current assets, that which equal $80 oil in Bakken opportunities, for example. But we have -- we've done quite a bit of work on acquisitions. We have a couple of key ideas. That's why we're reluctant to talk about what we might do in 2013 because our asset mix may change significantly. So we're just -- we'll kind of pursue our plan and see where it falls out right now. We're just not ready to give any kind of indication what that's going to result in.

David R. Tameron - Wells Fargo Securities, LLC, Research Division

All right. Final question, 2-part question on the impairments. If gas prices continue along the same trend, will you have another write-down in the third quarter? And if so, should we anticipate another leg down in DD&A? And then second, can you talk about any potential reserve impacts from next year as 2012 year-end reporting?

Marshal D. Smith

David, when we take a look at -- remember, the impairment test has changed for full-cost companies. So it was a 12-month look back. So we've got some insight in terms of what the third quarter looks like. And I think we've taken the bulk of the write-down. But if based on the way things look today, we're coming up with a number around $2.80, $2.90 that would test back the NC impairment versus a $3.15 that we just made. So we -- it looks like we've got another one possibly in the third quarter just depending upon how gas price is at between now and then. But the bulk of it's, I think is, behind us. In terms of reserve impact, I'll pass that to Brad.

C. Bradley Johnson

Yes, I'll just speak to -- just to affirm that the second quarter write-down was a price-driven scenario. And it was not related to performance of our assets. We're being very confident in the strength of own reserves in both areas, obviously, because of price reduction that triggers a 12-month trailing average below where it is today. There will be a reserve impact.

Michael D. Watford

Yes, I mean let's -- gas price at year-end 2011 is for a reserves of $4.04, I think. Without a significant increase in the fourth quarter gas prices, it's going to be less than that in 2012. So one could assume we're going to lose some PUDs. Now after losing those PUDs, if you look at the forward curve for 2013, at today's gas price, there are always PUDs we come right back on the books. So it's a transitory event, meaningless in terms of the value of the impact.

Operator

And our next question will come from the line of Ron Mills with Johnson Rice.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

You talked about the -- was people were saying about the Haynesville? If I look at your third quarter production's guidance, your full year, assuming gas prices didn't go back to $4 and you started completing wells again, is that sequential fourth to third quarter decline rate, what you think is fairly representative of Ultra's corporate decline rate?

Michael D. Watford

I guess I haven't looked at that. I'll let Brad help. But I think Ultra's corporate decline rate, I'll look to this. Well, I think Ultra's corporate decline rate on well production beginning in 2012 was about -- is in excess of 20%. And we're probably on the low side of most companies.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

No, I agree. That's why I wanted to ask the question. I think you have a flatter decline given the maturity of particularly, your Pinedale. Secondly, on Anadarko activity, it sounds like they've pulled their rig out. So I'm assuming the cost comments you were talking about in lateral lengths for -- on the last wells that they drilled in the program. Have you all had any discussions about what it would take for them to get a well back in? Or is that purely price-driven like your own activity out in the Pinedale?

C. Bradley Johnson

Sure. This is Brad. Certainly, the well cost that we talked about earlier is based on year-to-date performance. And that performance of cost is over 10% reduction in the last 6 months, which is very positive. Unfortunately, gas prices have dropped greater cliff. So we have a lot of discussions with Anadarko and we find ourselves in lockstep with those guys with respect to how to optimize the value of that asset since Romania. As far as trigger points, we don't have the trigger point to find, specifically on return. But we would expect Anadarko to do that at a time that we'd be in agreement.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And how much longer, their 5,700-foot laterals versus what they were drilling before to get a sense as to how much more they were drilling and still achieving a 10% cost improvement?

C. Bradley Johnson

Early on in the field, lateral lengths were in the 4,000- to 4,500-foot range, and that's going back a couple of years now. With time, they've steadily increased the length of leary laterals. And now, the common perception is, and we agree with them, that the optimum length is in that 6,000- to 6500-foot range. And they do that wherever they can. In some places, and in this most recent quarter, in some places, they're limited by the unit boundaries and so forth. But 6,000 to 6,200 feet is really where they want to be.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay, good. And Mike, can you talk about the plans for the Boulder area? You have 2 rigs in that area. What's different about the Boulder area to keep activity moving along there?

C. Bradley Johnson

This is Brad again. The Boulder area is alternatively called development area 3. It's really in the central part of the field that's south of the New Fork River. And historically, it has not been developed due to restrictions imposed by the BOM. Earlier this year, we gained access to develop in area 3. We're going to rig in, in April and we've moved our second rig in just earlier, well, in the early parts of July -- excuse me, later parts of July. So our 2 rigs in Boulder, we plan to be there for the next couple of years. And this is an area where we think URs are going to be significantly better than what we had in the last couple of years as we get the area that's been less developed.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Great. And then one last one for Mark. On your guidance, everything seemed to be pretty much in line with prior guidance, obviously, DD&A coming down with the write-down. But the only other thing that caught my attention was your guidance on interest and debt expense. It was up quite a bit for the third quarter. What's going on in that?

Marshal D. Smith

Sure, let's -- sure, Ron, that's a good question. If you look at our unproved property base associated with the impairment charge, we looked at that. We moved it into the full cost pool. And then that was part of the overall impairment. As a result, there's no capitalized interest against that unproved property pool going forward. So it's all -- it will all be run through the income statement. That's the difference that you're seeing.

Operator

And our next question will come from the line of Mark Hanson with Morningstar.

Mark P. Hanson - Morningstar Inc., Research Division

I have a question for you on the Pinedale program. If you're running 2 rigs currently in that Boulder area, is that sufficient to hold production flat or roughly flat as you look even beyond kind of Q4 in the 2013? And kind of what trajectory do you expect in next year in the Pinedale, if you keep that 2-rig program flat?

Michael D. Watford

You go ahead, Brad.

C. Bradley Johnson

Sure. No, 2 rigs by themselves will not keep Pinedale flat. I think it's important to point out that the Pinedale assets have inherently low decline as they continue to produce. But I would say that Pinedale will go down somewhat, not at the same clip you're seeing right now for the quarter because we're coming off of a higher investment pace over the last 12, 18 months. So once that settles out, it will be a modest decline. But it will not be flat with just 2 rigs.

Michael D. Watford

I think, historically, we've said somewhere in the range of $400 million a year keeps Pinedale flat. And we're not anticipating spending anywhere near that amount of money in 2013 in Pinedale, so, no.

Mark P. Hanson - Morningstar Inc., Research Division

Okay. And then beyond the 2 operated rigs, how many non-op rigs do you guys have in the Pinedale?

C. Bradley Johnson

Well, we've currently 6 rigs being run by Questar and 0 being run by Shell.

Mark P. Hanson - Morningstar Inc., Research Division

Okay. And then one last question. On taxes, in terms of the -- I mean, how do you think about the balance between reduced drilling activity in IDCs? And then the ceiling test write-down, when you look at cash tax rates for this year and then kind of going forward? If you could give us more detail on that, it would be helpful.

Marshal D. Smith

Sure. And let me start from a high-level perspective. In guidance, we've said we believe that if cash taxes for the full year will be about $2.6 million, so you have to keep in mind that we -- as Brad indicated, we had very significant levels of capital spend going back last several years. And as a result, we've got with -- that's a pretty high pace of IDC deductions. Those have been rolled over in NOL carryforwards. So we don't see ourselves seeing a current cash tax payer for quite some time.

Operator

And our next question will come from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

I hopped on late. I apologize if this was covered already. But where do you think Marcellus now peaks out with continued completion of the backlog?

Michael D. Watford

From our net production, just the Bossier or in general?

Subash Chandra - Jefferies & Company, Inc., Research Division

Yes, your net production.

C. Bradley Johnson

Yes, we're currently around 210 to 220 million net a day out of Pennsylvania. We expect that to remain flat for the rest of the year.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. Right, okay. And do you think that by year end, you still have a significant backlog in the Marcellus?

C. Bradley Johnson

No. We think our backlog's going to be reduced significantly, and just to context that in Pennsylvania...

Michael D. Watford

To net wells.

C. Bradley Johnson

Net wells, sure. We expect to drill just under 29 net wells in 2012. And we expect to put online just under 49 net wells. So a net reduction of the inventory is around 20 wells, and double wells online relative to wells drilled in 2012. So I think there was comments earlier about the execution. We're definitely pleased with working off the inventory in Pennsylvania from that standpoint.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. And a strategic question, I guess. Mike, I guess you've set a high bar for renewal of gas activity, $4.50 and change. I mean, we can debate the macro coal gas switching versus supply coming off. But if you can talk to maybe your views on oil or NGL sort of a strategic fit or not for the company, what you do or don't like about it?

Michael D. Watford

No, it's -- We're, I guess to what the commodity we produce or develop. It's all about returns. Historically, when we look for a third leg to our stool, as we like to talk about, or I like to talk about it, and we're looking heavily at oil or liquids areas. We just -- we didn't do anything better in those areas other than the very sweet spots at $80, well than we did with our existing assets of $4 a gas. Now we got blindsided by where gas prices end up because of oversupply. But -- so we continue to evaluate other opportunities. We've got a couple that we're really keen on right now. But you see the relative oversupply of NGLs and the collapse of pricing there. There's some areas that high returns in February, March have minimal returns now. So we have to be mindful of that. But no, we don't care. It's all about making money. It's all about returns. It's not about production growth. It's not about mere cash full of growth. It's about return on capital.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. So the return on capital would then influence -- it's, I guess, more comprehensive that a well had return in that you would take into account if you decide to issue equity or something like that to make a transformational acquisition?

Michael D. Watford

Yes, we would take them and consider, and we certainly would.

Operator

And our next question will come from the line of Noel Parks with Ladenburg Thalmann.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Just a couple of things. If we fast forward to when eventually I believe the natural gas prices come back, and you started thinking again about increasing activity, I was wondering, based on Anadarko's and especially Shell's sort of reluctance early on to lower their activity, do you see in the future any potential I guess, as the staff's working on that, maybe get specs on other things within Shell? Is it a potential for you guys perhaps stepping and assuming operatorship of some of the Anadarko or Shell venture wells?

Michael D. Watford

Well, we would look forward to assist them in any way we could. But I think it's doubtful that they'd want to transfer operatorship. Most companies are very proud of operating. So -- but we are unhappy to see Anadarko make what we think are the right decisions in terms of decreasing investments, decreasing activity in the area until commodity prices improve. And we're seeing some pauses on Shell moving a direction. A direction not, nearly as aggressively as we would like or as others have done, but we're hopeful that they'll continue to move in that direction.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Okay. And thinking about the Rockies as we see gas activity continue to go down there. I was wondering if any opportunities that present themselves where people might have had exploratory opportunities, where they had acreage, whether they'd might be interested in accompanying your size, maybe coming and looking to do some farm-in type of opportunities? I'm assuming you don't want to spend a lot of money, but I was wondering if you're seeing anything along those lines?

C. Bradley Johnson

We get approached almost daily with opportunities like that, and we evaluate them all. But right now, we haven't seen anything that wets our appetite, that's got us interested in jumping and doing such a deal. It's typically shops that have some economic projects that they want to promote somebody into to leverage a partner in and enhance their rate of return. And we're not interested in that type of deal.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Got you. Just if you would characterize those, what sort of time frame would you say that these are -- were projects that, that got started? I mean, things that got started in the 2006, '07, '08, over a heated time or things that people brought on or entered more recently?

C. Bradley Johnson

It runs in the gamut. It's across the spectrum. The preponderance of them seem to be play, oil plays that people got in when oil was $110, $112 a barrel. And now, they're looking for help.

Noel A. Parks - Ladenburg Thalmann & Co. Inc., Research Division

Well, do mean in the recent sort of runup we saw over $100 or more if we talk of the 2008?

C. Bradley Johnson

Yes, a couple of years ago, right.

Operator

And our next question will come from the line of Hubert Van der Heijden with Tudor, Pickering & Holt.

Hubert Van der Heijden - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

One thing that I was looking for a little more clarity on is the actual CapEx number you said that you spent, and maybe a little bit color on which areas it went to for this quarter?

Marshal D. Smith

Growth CapEx spend?

Michael D. Watford

Yes, why don't you give him CapEx spend? Hubert, you want -- so with cap expense for the quarter, you must led...

Marshal D. Smith

Brad...

Michael D. Watford

We give him the total and see if Brad -- if not, we'll get back to him

C. Bradley Johnson

Well. Year-to-date, we're about $570 million for first 6 months. The majority of that has been driven -- has been funded in Pennsylvania. But our drilling capital in the month of June is reduced down to the $40 million range, so a significant reduction already in effect. And going forward, we expect $40 million a month for the balance of the year. So if we work the math leading back up to the $825 million or so for the year. But just to reiterate, the majority of it today has been Pennsylvania funding.

Marshal D. Smith

Let me tally into Brad's comment and help find it a little a bit. We said that our capital spending would be front-end loaded this year. We've talked about working to match CapEx with cash flow. We spent $560 million in CapEx, as Brad said, in the first 6 months of this year. That compares to $716 million, same time frame last year. And that compares to EBITDA for the first 6 months of this year of $425 million. So we outspent it for the first 6 months. But in the month of June, as Brad indicated, we spent about $44 million, $45 million. EBITDA registered $81 million for the month. So we've turned the corner. We expect a slowing pace of capital spending go through the rest of the year. And we expect to outperform in terms of cash flow.

Operator

[Operator Instructions] And our next question will come from the line of Robert Christensen with Buckingham Research.

Robert L. Christensen - The Buckingham Research Group Incorporated

Question, can you please refresh my memory. How much of your Wyoming gas can, I guess, go westbound towards California? And what direction is the Wyoming gas going in at the moment?

Michael D. Watford

It can all go west, Bob. But currently, off the top of my head, 250 million a day is going east. And that means what, 350 million a day is going west. So right, 600 million gross sales. That's different to the net sales because we sell throughout [indiscernible] off the top of my head.

Robert L. Christensen - The Buckingham Research Group Incorporated

Okay. And what is the transportation rate, I guess, taking it west versus taking it east? How do we look at that on a per unit basis?

Michael D. Watford

It was more expensive going east because of the pipes and the racks that we had signed up for. And I just got to get back to you. I don't know the numbers off the top of my head.

Operator

And our next question is a follow-up question from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

I was just hoping for a little bit more color in terms of how many wells you expected to roughly get online in the Marcellus in the second half this year according to the current plan?

C. Bradley Johnson

Sure, this is Brad. I'm going speak to net wells again. For the remaining part of 2012, we expect 17 wells to come online, about 2/3 of that from Shell and 1/3 from Anadarko.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, great. And I guess -- Okay. And I guess in terms of the Pinedale, obviously, you guys suspended completions. What do we think the backlog of uncompleted wells can be in the Pinedale as we head into 2013?

C. Bradley Johnson

Here in '12, the backlog is going to be, on the operative front, 40 to 45 wells.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Is that gross or net?

C. Bradley Johnson

That will be gross.

Operator

Ladies and gentlemen, this concludes the question-and-answer portion of today's call. I would now like to turn the call back to Mike Watford, Chairman, President and CEO, for closing remarks.

Michael D. Watford

Thanks, everybody, for participating today. Should you have additional questions, please contact the Investor Relations groups. We will see you next quarter. Thank you.

Operator

Thank you for your participation in today's conference. This concludes your presentation. You may all disconnect. Good day, everyone.

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