Ultra Petroleum Management Discusses Q3 2012 Results - Earnings Call Transcript

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 |  About: Ultra Petroleum Corp. (UPL)
by: SA Transcripts

Ultra Petroleum (NYSE:UPL)

Q3 2012 Earnings Call

November 01, 2012 11:00 am ET

Executives

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

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

William R. Picquet - Senior Vice President of Operations

Douglas B. Selvius - Former Senior Vice President - Exploration

Analysts

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Devin Geoghegan

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

Mark P. Hanson - Morningstar Inc., Research Division

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

Matthew Portillo

Operator

Good day, ladies and gentlemen, and welcome to the Third Quarter 2012 Ultra Petroleum Corp. Earnings Conference Call. My name is Caris, and I will be your coordinator for today. [Operator Instructions] Later, we will conduct a question-and-answer session. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And I would now like to hand the call over to your host for today, Mr. Mike Watford, Chairman, President and Chief Executive Officer. Please proceed, sir.

Michael D. Watford

Thank you, operator. Good morning, and thank you all for joining us today. With me today are Mark Smith, Senior Vice President, Chief Financial Officer; Bill Picquet, Senior Vice President of Operations; 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 sections 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 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.

Before we talk about the quarterly results, let's take a moment and talk about what we're trying to achieve in 2012 or better stated, the thoughts behind our actions. We entered 2012 having spent $1.5 billion in capital in 2011, frankly more than we intended.

We are a natural gas company, having resolved that our assets return more at $4 gas than most oil plays do at $80 oil. We didn't foresee an environment with $2 gas and $100 oil. We've always said that we are focused on profitable growth with profits being the keyword. And even with our low cost, probably the lowest in the industry, there were no profits at $2 gas.

So we chose the rational economic path of withdrawing capital from the business. We were earlier and more aggressive than most, but almost all have followed suit, where we spent $1.5 billion in 2011, we started 2012 with a $925 million capital budget. We terminated rig contracts and non-consented uneconomic well proposals from partners. We don't believe in cash flow growth or production growth without economic returns.

We were recently able to further reduce our estimated 2012 capital expenditures to $800 million. And with the expected sale of a midstream asset for $200 million to a net 2012 CapEx of $600 million.

We want to be cash flow positive in this environment. We want to under invest. And we didn't think with natural gas at $2 and oil at $100 that it made sense to aggressively pursue oil projects, given our view that natural gas would rapidly climb to $4, and oil would drop to $80.

So where are we at the end of the third quarter? While it's taken longer to slow things down than one would think, we spent 88% of our capital budget with a dramatic slowing of third quarter and more so in the fourth. We were cash flow positive in the third quarter, which is continuing into the fourth.

For those who question the natural gas rig count reduction, from 900 rigs to 400 rigs, without any associated production impacts, we can look at ourselves to see the lag. We exited 2011 with monthly production of about 22 Bcfe. With a 50% cut in capital for 2012, first quarter production grew to 23 Bcfe a month, second quarter, 22 Bcfe a month and third quarter, 21 Bcfe a month. Production lags CapEx on the downside, as well as on the upside.

So industry-wide, you are just beginning to see natural gas production rollover. Once it begins, it will accelerate, then I think we are looking at a 2-year window of monthly reductions in domestic natural gas supply.

So it's taken us, and the industry some time, to react to the market signals, but we have and we won't be quick to over invest in the coming years. And we've seen natural gas prices respond positively, but they are a long, long way away from levels that will attract capital.

Now let's talk about the quarter. Our production of 63.1 Bcfe, which was above our quarterly guidance range, benefited from strong initial production rates on new wells and higher base production performance due to lower gathering pressures. We had over 85% of our production hedged during the third quarter, resulting in a realized price of $4.13 per Mcf. Without the effect of our hedges, our average realized price was $2.77 per Mcf. We generated $187.5 million in cash flow or $1.23 per diluted share, and $97.5 million or $0.64 per diluted share in adjusted net income during the third quarter.

We indicated in our last quarterly conference call that reduced trailing 12-month natural gas prices could prompt a subsequent ceiling test write-down, a quarterly calculation required for full cost accounting companies.

As you've read today, we reported a $606.8 million reduction in the carrying value of our natural gas and oil properties. The third quarter 2012 impairment test was calculated using a $2.83 gas price in comparison to the second quarter ceiling test calculation using a $3.15 [indiscernible] gas price.

The second quarter ceiling test write-down -- or the third quarter ceiling test write-down caused book value of our properties to fall below the tax basis, which reversed our deferred tax liability and created a deferred tax asset. As a result, our financial statement presentation does not include any deferred tax expense, which we expect will occur for several years going forward, the new normal.

For the quarter, our all-in costs were $2.88 per Mcf, about the midpoint of our guidance range. Our industry low cash costs were $1 per Mcf, resulting in a cash flow breakeven of a remarkable $1.37 per Mcfe. Our long-term focus on low cost is critical to having positive margin throughout the low period of commodity price cycle. For the third quarter, our cash flow margin was a healthy 67%, and our net income margin was 35%.

Looking at our capital investments through 3 quarters of this year, we've invested $705 million of our revised downward step $800 million budget, which is about 88%. Adjusted for the expected midstream asset sale, our net CapEx for the year is $600 million. In response to natural gas prices, our activity and capital spend rate slowed during the year, but more significantly in the third quarter and continues to decelerate as we preferentially defer development of our long-life, low-cost natural gas asset base. But it takes time to unwind the spending.

To illustrate this point, our capital expenditures for the month of June totaled over $100 million. In July, it narrowed to $43.7 million, a 56% decrease. Our total capital investments for the third quarter were $144.2 million as compared to cash flow for the period of $187.5 million. We were cash flow positive each and every month during the quarter.

Let's review our operational highlights for the quarter. In Wyoming, we appropriately reduced our activity pace in the third quarter, drilling 14 operated wells compared to 52 operated wells during the third quarter of 2011. We continue to challenge ourselves or further reduced drilling times, which directly affects costs. All 14 of our operated wells were drilled in less than 15 days, with an average of 10.5 days spud to TD. These increased efficiencies translated to significant cost savings. Our third quarter drilling costs averaged $2.2 million per well compared to an average of $2.7 million during the second quarter, a 19% decrease.

These cost reductions are evidenced in our total well costs, which decreased quarter-over-quarter from $4.8 million to an estimate of less than $4.6 million.

To enhance returns, we made the decision to suspend our Wyoming completions program in April. Natural gas prices were less than $2 per Mcf. The economics of a 12-month deferral decision suggested that we would only need a $0.15 per Mcf uplift in gas prices to achieve comparable returns. In only 6 months, we have surpassed this hurdle and seen nearly a doubling of natural gas prices to an indicated $3.70 for December or $1.80 per Mcf increase from April pricing.

Due to better economic returns, we will resume completions in mid-November, targeting 20 wells by year end.

To briefly update you on our Niobrara progress, the analysis of core taken from our 3 vertical wells, and DJ Basin is nearly complete. The results are mixed. The critical next step in assessing Niobrara potential is a horizontal well, which is planned for this winter.

In Pennsylvania, our horizontal Marcellus program continues to deliver strong wells and benefit from cost efficiencies. We brought 22 wells online during the third quarter at an average initial production rate of 7.1 million cubic feet per day. Through the end of the third quarter, we brought online a total of 101 wells, averaging 6.9 million a day. These results are consistent across our entire leasehold position.

Our drilling activity slowed significantly during the quarter for the reasons I cited earlier. Our partner, Anadarko, shares our view and stopped all drilling in our joint operating area in the third quarter. Overall, we participated in drilling only 8 horizontal wells, those projects we deemed economic.

With 66 total wells drilled and 101 wells online for the year, we've substantially reduced our inventory of wells waiting on completion and pipeline connection by 35 to a total of 65 wells currently waiting.

While the average IP rates in EUR metrics per 1,000 feet of lateral are quite comparable between our 2 Marcellus Joint Venture areas, no similarities in there.

In our Anadarko joint venture, a typical well has a measured depth of nearly 14,500 feet, with lateral lengths averaging just over 5,800 feet. A typical drill dip to our Marcellus target area is 8,400 feet. On average, these wells costs about the $6.2 million to drill and complete, a decrease from $7.5 million at the beginning of the year.

Two key changes that Anadarko implemented to reduce costs are increasing stage length and adjusting the lower Marcellus target interval. These benefits are sustainable going forward because they are independent of service-related costs, which are trending down.

By comparison, a typical well on our Shell joint venture area has a measured depth of 10,500 feet with a lateral length just under 4,500 feet. Our Marcellus target zone in this area is a relatively shallow drill depth at 5,600 feet. However, this well cost $7.8 million to drill and complete. In other words, Shell's wells are 4,000 feet shallower, have comparable -- have completable laterals, 1,300 feet shorter and are drilled with target depths of 2,800 feet shallower, but are 25% more expensive than Anadarko's wells. More work needs to be done here.

We are continuing to evaluate the potential for Geneseo development across our leasehold position. We brought online 2 new Geneseo horizontal wells during the third quarter, bringing our total online total 4 wells with a fifth well flow testing. These wells, coupled with well data from 9 other horizontals in the area, are helping to paint a good picture of the resource.

We see a majority of our acreage position as highly prospective for the Geneseo with a potential to exceed our Marcellus EUR in some areas. We've identified more than 1,000 net locations in our prospective acreage with an estimated net resource conservatively estimated at more than 3 trillion cubic feet. These wells have the added economic advantage of sharing locations, roads and infrastructure costs with our Marcellus development.

While we see improving price signals for 2013, we want to continue to under invest and generate free cash. Directionally for 2013, we are looking at a further reduction in capital to plus or minus $450 million and production of plus or minus 240 Bcfe, which is right about our last 3 years average annual production.

Capital would be fairly evenly divided between the Wyoming tight gas assets and the Pennsylvania shale gas assets. We want to see natural gas prices closer to $5 before we fully invest cash flow.

And now, operator, I'd like to pause and take some questions.

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from line of David Tameron with Wells Fargo.

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

I may have missed this, but can you update us on the midstream and where that [indiscernible]position process currently is?

Marshal D. Smith

David, this is Mark here. The transactions we're working on involve the sale leaseback with a REIT, which by definition can't operate. As a result there's a complex, somewhat innovative transaction, and which we would continue to operate the asset, it's -- as a result, it's taken a good amount of time to pull all the ends together and wrap up everything. We've reached agreement on all the major business points. We're in the process of putting all the documentation together, and we currently anticipate the transaction will be a fourth quarter event.

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

All right. So it will be completed and announced in the fourth quarter, is that what you're saying, Mark?

Marshal D. Smith

That's what we currently anticipate.

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

Okay. Let me -- Mike, let me jump over to some of the pricing commentary that you had. For 2013, you guys are still unhedged?

Michael D. Watford

Yes.

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

If you got what you're looking for as far as the $4. And as you have been consistent about that and saying how much better the economics are, with the uplift, why not go ahead and lock in some hedges for '14 today and secure that CapEx budget?

Michael D. Watford

Well, because I think the upside is greater. I think it's limited downside and there's more upside. I don't think people are properly forecasting gas supply reductions.

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

All right. But no -- I guess, I'm looking at -- obviously, you're running the company, you're making decisions, but why double down at this point? You've got the gas price rebound you're looking for and why not take some that risk off the table?

Michael D. Watford

Again, because the upside looks greater. I mean, we still have bottom, but we're nowhere near bouncing back up to where we need to be. There's just not going to be any significant investment in dry natural gas wells at $4 gas, not going happen. So I think we're probably in a 2-year window here before we get gas prices back at $5 plus to where you growth and investment I think you're going to continue to see industry-wide investment decrease in 2013 and '14.

Operator

And your next question comes from line of Brian Singer with Ultra.

Brian Singer - Goldman Sachs Group Inc., Research Division

Wanted to just follow up on year Geneseo comments. You mentioned 1,000 potential locations, 3 Tcf, the potential for some of the locations to exceed your EURs in the Marcellus. And ostensibly you have greater control over the Geneseo as well in terms of operatorship, though I think you probably comment on that. Can you just talk to what that means in terms of the prioritization from a capital allocation and asset perspective? Do you -- at what point do you start to shift to more meaningful drilling program toward the Geneseo and away from either completions or drilling in the Pinedale or even in the Marcellus as well? And what does that mean for your non -- the strategic nature of your non-operated Marcellus assets?

Michael D. Watford

A number of questions there. First, we're not anticipating spending any capital in the Geneseo next year and in the same areas, we're not anticipating investing in the Marcellus for the most part either. In terms of the resource and the locations and so forth, you mentioned, it's split pretty well between operated and non-operated in terms of where we see the value. I think part of your question is how does it look on your operated acreage where we control our own destiny. And when we talk about the majority of our acreage being perspective, that is one area. We like the Geneseo at a certain price in our own Marshlands leasehold. It also looks very attractive to us down south as well. But like I said, no intent right now to drill Geneseo wells in 2013. Your other question is, would it ever supersede a Marcellus development in some areas. And it's conceivable we're really not in a position to answer that question very intelligently right now. We just need some more information in that particular area. We need some more information on the Marcellus to see how it compares to the Geneseo. But both look good in some of those areas, and which we'd end up winning out, I'm not sure right now. Does that answer your question.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes thank you it does. And then on the new ventures side, I think you mentioned the results in Niobrara were mixed. Can you just talk more specifically? And what your plans are?

Marshal D. Smith

Sure. What we mean by mixed results from the Niobrara core is that we saw some things we liked and other things that we wished had looked better. The good news is we got hydrocarbon saturation averaging 60% plus in all 3 Niobrara ventures. That was really encouraging and comparable to what you see up in Wattenberg field. We also saw porosities and total organic carbon that were much in line with our expectations and from a porosity standpoint somewhat better than Wattenberg. On the other hand, thermal maturities were not as high as we had hoped. The wrap was not as mature as we were hoping it would be getting into this play. And we really need a horizontal well to tell us if we've gotten over the threshold or not. So we are now collaborating with another large adjacent leaseholder out there to get a horizontal well drilled. And as Mike mentioned, that's going to happen in the next couple of months.

Operator

And your next question comes from the line of Brian Velie with Capital One Southcoast.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Quick question on the CapEx decline from $825 million to $800 million. With the 20 completions coming on, not sure what those would cost you, but is that decline able to occur even in the face of additional completions maybe because you've got a little bit more of line of sight in what partners are doing in the Marcellus? Or I guess, could you walk me through how you're able to do that?

William R. Picquet

Yes, this is Bill. It's a combination of efficiencies as far as cost improvements are concerned, as well as just the activity levels, reducing elsewhere, offsetting the capital expenditure for the 20 completions. So we're confident that we can achieve those levels.

Brian T. Velie - Capital One Southcoast, Inc., Research Division

Okay. And is -- the 20 completions, is there a round number you might figure those would cost you?

William R. Picquet

Essentially the same as our completion costs have been running in Pinedale. So...

Michael D. Watford

On a net basis, like $2 million a well, a little less than there on a net basis.

Operator

And your next question comes from the line of Brian Corales, Howard Weil.

Brian M. Corales - Howard Weil Incorporated, Research Division

A question regarding just the company's decline rate because I mean, spinning, I guess, cutting your capital budget almost in half and keeping production relatively flat, I mean, are you all surprised about maybe how resilient or flat the production decline curves are? Are there things you're doing to maybe optimize production?

William R. Picquet

This is Bill again. One of the things that has been a bit of a plus for us has been the lower line pressures in Pinedale. And so we benefited from the fact that lower line pressures our base well component has performed better than we anticipated.

Michael D. Watford

And I think the other issue is the majority of the production we have is from Wyoming from the Pinedale Field. And we've been drilling wells there since '99, 2000. So the recent wells, the recent capital program has the higher declines, but the wells that have been in production for 5, 6, 7, 8 years had very modest declines so you're seeing as we move forward in time and as current period CapEx is less, you're seeing our overall decline rate decrease.

Brian M. Corales - Howard Weil Incorporated, Research Division

Mike, maybe I will just ask you. Are you a little bit surprised at how well the response is from the production side?

Michael D. Watford

Well, I mean, we've got nice pickup with the decrease in gathering system pressures in Pinedale. We have the opposite occur to us last year, when they ran up with a big fire and explosion. So -- enough of that. But no, I think we have some analysis that says Wyoming alone for the next 3 years, for -- let me just find my piece of paper before I misquote something, which I'm known to do a lot. For $250 million, $260 million a year, we can maintain that production that 165, 170 a year in Wyoming. So that's pretty flat, that's pretty modest CapEx. That's just where we are [indiscernible].

Operator

Your next question comes from the line of Ron Mills with Johnson Rice.

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

Just a little follow-up on the line pressures in Wyoming. Is that something that you guys think is going to continue given the fact that a lot of production is still declining and/or even get better? And then a corollary to that is, as you look at your resource potential that you've talked about in Wyoming and that driving a better-than-expected decline rate, any potential on that having any upwards impact on your overall resource potential out there?

William R. Picquet

This is Bill again. As far as the line pressures are concerned, we think that, that's going to continue. You're seeing declining production in the area as the resources in the area have slowed down from a drilling perspective, they're going to continue to decline, so we're benefiting from that. As far as the resource is concerned, I don't think there's much change from what we've predicted. It's pretty much performing as we anticipate.

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

Okay. And from a CapEx standpoint, you talked about being fairly evenly split between the 2 areas. Do you also think it'll be pretty evenly split throughout the year? And just to confirm, Bill, did you say that, that CapEx in Appalachian Basin next year does not anticipate any additional Geneseo wells?

William R. Picquet

I'll answer the last one first. We don't anticipate any additional Geneseo wells in 2013. And as far as the splits are concerned, we're still waiting to see final plans from other programs,ours is pretty well set in Pinedale as far as the 2 rig program is concerned, I think you heard yesterday QEP talking about 3 rigs in Pinedale for next year. And so that level of activity is going to be pretty predictable and pretty stable. And we'll have to wait and see what wells are proposed as far as Shell's program in Pennsylvania is concerned and how we view the economics of those wells and how their cost performance proceeds go forward for the year.

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

Right. And then lastly, just on the completions in Wyoming that you plan on doing here in the first quarter and presumably continue going forward with the kind of gas prices. Is there any particular area that these completions are focused in? I know from a development plan standpoint, you've kind of moved through the basin in an orderly fashion, just trying to get a sense were they are, which are the projects these completions are coming up in?

William R. Picquet

Those are going to be almost exclusively in the Boulder area, which is the area we talked quite a bit in the past being a better area of the field that has been relatively lightly drilled up to this point in time. And so we expect those to be really nice wells.

Devin Geoghegan

And is that where you think most of your drilling activity will be focused as well?

William R. Picquet

Yes.

Operator

And your next question comes from the line of Noel Parks with Ladenburg Thalmann.

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

Just a couple of things. On the updated type curves for the Marcellus that you provided with the release, I was just taking a look at the upper one, the southern Bcf curve, and I noticed in the 90 days or so it's been pushed out since the last one, it seems like there's a bit of an uptick on the well production kind of heading more back up towards around 2 million a day. I just wondered what was kind of behind that phenomenon?

Douglas B. Selvius

We're seeing -- this Doug again, we're seeing not just in that upper type curve you're looking at, but also the lower. When we're seeing flatter declines pretty much across the board in our Marcellus program out there, in all areas, the decline curves are just flattening out more and there has even been a little bit of an uptick, some of that related to infrastructure in the Marcellus. So we haven't made any official adjustments to our type curve quarter or the model yet, but we'll watch it closely.

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

Great. And back in Wyoming, I -- sorry, back in Wyoming, I also wanted to ask about the completions. What actually is the typical completion cost you're expecting going forward? Separate from the drilling costs?

Douglas B. Selvius

Well, I think the number, as Mike mentioned earlier, are accurate as far as our nets are concerned. You've probably noticed in the press release that we forecast $4.6 million for total cost, that's based upon an estimate of forward completion cost because as you know, we haven't been completing lately, but I think Mike is going to be pretty disappointed in me and my operations folks if we don't come in lower than that number. So seeing things that are very encouraging as far as continued efficiencies are concerned on the drilling side. And we'll see what happens on the completion side, but it will be going back with the same crews that we've had previously, and we're anticipating that performance will continue to be at least as good as it has been in the past and possibly continue to improve. So those numbers are conservative at the $4.6 million level.

Operator

And your next question comes from the line of Mark Hanson of MorningStar.

Mark P. Hanson - Morningstar Inc., Research Division

I want to go to the Pinedale. Anything specific that you guys could share on drivers of efficiency gains there? Aside from lower cost, obviously it looks like you guys continue to improve rig release to rig release times and anything you could share would be helpful? And then I have one follow-up.

William R. Picquet

This is Bill. There are a few things. I mean, we continue to experiment with different bits and so bit design and efficiencies continue to improve. We've also done a few things that -- I'm not going to share a lot of detail on the mud side, but we've changed some things as far as our mud recipe is concerned that are helping us as far as penetration rates go as well. So on the drilling side, the -- we've just continue to tweak things, and we look at what's possible there. And we see an 8-day well as being kind of the perfect well right now. We've done that before, and we continue to see our overall well count continue to increase as far as number of wells that we're drilling below 10 days. And so it's consistency, it's being better in areas that have been more challenging in the past. We're drilling in an area that in the past was very challenging and having much better results as far as efficiencies are concerned in that area. So it's consistency.

Mark P. Hanson - Morningstar Inc., Research Division

Sure. And then relatedly, how much of that is a function of, you think, about drilling day rates and lower costs on the pressure pumping side of things? How much is really a function more of efficiency in the operating side versus just an overall industry-wide cost reduction?

William R. Picquet

Pinedale is all on the efficiency side. We haven't had a change until recently as far as rig rates are concerned. So the numbers that we're talking about are pre any downward pressure on rig rates, although we have recently seen that benefit as well, but it's not in the number you've seen so far. And cost of services in general in our operations in Wyoming have not dropped as much as cost of services in Pennsylvania have dropped. As you've seen the activity levels reduced in Pennsylvania, the entire industry is benefiting from reduced cost of services and that's continuing. But in the West, it's not nearly at that rate. But for instance, we just -- we negotiated a rig contact and the day rate dropped about 15%. So those opportunities will be there as well, we're anticipating.

Mark P. Hanson - Morningstar Inc., Research Division

Great. And my follow-up will be, have you had discussions with Shell and Anadarko? And I know it's for 2013 and beyond, but at what point do you think they start to ramp back up in the Marcellus? And is there a floor at which you'd choose the non-consent versus participating there?

Michael D. Watford

I won't speak for Shell, but I think Anadarko doesn't have any intentions of ramping back up probably until you get closer to $5 gas price. So I think 2013 and certainly 0 activity and depending on where the 2014 gas prices look, when you're at this time next year, will dictate what happens then. And that's my point about I think for a 3-year window here of decreasing supply because I think majority of the folks have drastically cut back going through the budget cycle in 2013. And those cutbacks are going to continue or be worse. I mean you've seen them average through the course of 2012. You're going to see them at a very low level for 2013. And then when you get into budgeting cycle for 2014, if gas prices aren't $5 or above for '14 you'll see that continue. If they are, and they start to spend back up, you don't even get a production increases based on the capital spend uplift in 2014 until the late third quarter or fourth quarter of 2014. So I think we've got 24 months of maybe we have another couple of months of flat production. But after that, it starts coming down, and it keeps coming down for the next 2 years.

Operator

And your next question comes from the line of Leo Mariani with RBC Capital Markets.

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

Just I know you were just asked about kind of 2013, and what Shell might do. Talk about spending $250 million to $260 million in the Pinedale and kind of a plus or minus $450 million budget. I guess, should we just assume that the plug and the difference in those numbers is kind of your assumption for Shell activity in 2013 in the Marcellus?

William R. Picquet

Yes, that's a good assumption.

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

Okay. And I guess, the $250 million to $260 million at Pinedale, is that just Ultra-operated activity or does that include non-op from QEP and others as well?

William R. Picquet

That's all in.

Operator

And your next question comes from the line [ph] of capital.

Unknown Analyst

As I recall, Mike, on your second quarter call, I think you referenced taking a look or at least considering acquisitions of some type of magnitude. I'm wondering if you -- given you're now looking your view in terms of 2013 CapEx and the way the gas market is evolving, from your point of view, can you kind of revisit your comments from the second quarter and how you're thinking about that now?

Michael D. Watford

Well, I mean, I think clearly, we want to create more dry powder for opportunities whatever commodity they might be. And by understanding cash flow in 2012, although it was hard to get there and continue that in 2013, we'll have more free cash to spend. We also have more debt capacity. Because one can easily argue that our debt capacity is going to go up next year given that our PDPs are going to go up and the bank price deck for gas is going to go up. So with free cash generated this year, approximately $700 million and more debt capacity makes it easier for us to execute some sort of asset or corporate acquisition that would add a third or fourth leg to us. So yes, we're very sensitive to that and we're looking at it hard.

Unknown Analyst

So I mean, just so if we want to try to zip code the factors that you enumerated there, should we be thinking that you would be -- you're thinking dry powders somewhere in the net like $1 billion area? Or how should we think about that?

Michael D. Watford

No, I think that's a good area.

Operator

[Operator Instructions] And your next question comes from line of Matt Portillo with Tudor, Pickering, Holt.

Matthew Portillo

Just a few questions for me. Just to start off, I may have missed it at the beginning. But I was just curious if you've provided any guidance on your net well completions in the Pinedale for Q4?

Michael D. Watford

I don't think we did. We can pull it up for you, but we don't have that in front of us right now.

Matthew Portillo

Just trying to understand a little bit better, I guess, the movement in well completions as you bring forward some of these completions?

Michael D. Watford

In Q4? Doug is going to look up in his table and see if he has it for you.

Douglas B. Selvius

Yes, got it for you.

Michael D. Watford

What else do you have?

Matthew Portillo

And then just in the Marcellus, just want to get an update. I think you mentioned obviously Shell's well costs are significantly above where you'd like to see them today, and I was curious, are you currently going non consent on those wells? And do you see at the $7.8 million well cost are those meeting your economic threshold?

Michael D. Watford

We're only participating in the wells that meet economic threshold. I think there's -- Shell has drilled plus or minus 90 wells or plans to drill plus or minus 90 wells in 2012. We plan to participate in about 1/2 of those because only 1/2 of those will be positive economics at current gas prices and their well costs. So fully 1/2 of their wills we have set out because they're uneconomic. And that's where we're trying to stop make the point today we've seen significant progress on the Anadarko side, and from $7.5 million to $6.2 million. Part of that can be achieved by Shell with [indiscernible] provider distribution system in place, but other progress has to be made so they could get closer to these numbers so that we can unlock all of these resources in an economic fashion. So yes, we have non-consented 1/2 their proposals this year. So they are spending their capital at present.

Douglas B. Selvius

The net well count you requested for Pinedale was 17.4 in the quarter.

Matthew Portillo

Okay, great. And then just in terms of the -- just trying to dial in the CapEx that you mentioned. I think you give us a July figure of about $44 million. I was curious if you could give us a number that's a little more recent maybe September, October kind of where you're run rating at the moment on drilling and completion?

Michael D. Watford

Well, we're talking about less than $100 million of capital for the fourth quarter. Is that what you're asking, Ben?

Matthew Portillo

Yes, just trying to get a sense of maybe where you're exit was during the Q3 numbers.

Michael D. Watford

No, I think September was about $45 million, something like that. It continues to come down.

Douglas B. Selvius

The rig count continues to come down. [indiscernible].

Michael D. Watford

September was right at $47 million. Free cash flow for the month was about $63 million so again, positive cash.

Matthew Portillo

Okay, perfect. And then just finally, on the LOE side. Noticing a slight uptick on LOE costs in Q4. Is that a function of volumes declining a bit? And then as we think about 2013, could you give us any color on kind of directionally where that may trend for your 2013 numbers?

William R. Picquet

I think a big driver of that LOE costs in the fourth quarter is us beginning to layer in, in the latter portion of the year the effects of the monetization of the liquids gathering system. We think once that transaction is completed, we're looking in the neighborhood of an incremental $0.07 to $0.08 in Mcf in terms of lease operating expenses.

Operator

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

Michael D. Watford

I thank everyone for participating today. Should you have additional questions, please contact the Investor Relations group, and we look forward to visiting with you next quarter. Bye.

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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