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Ultra Petroleum (NYSE:UPL)

Q1 2012 Earnings Call

May 03, 2012 11:00 am ET

Executives

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

William R. Picquet - Senior Vice President of Operations

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

Douglas B. Selvius - Former Senior Vice President - Exploration

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

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Mario Barraza - Tuohy Brothers Investment Research, Inc.

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

Mark P. Hanson - Morningstar Inc., Research Division

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

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

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

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Operator

Good morning, ladies and gentlemen. Welcome to the Q1 Ultra Petroleum Corp. Earnings Conference Call. My name is Chris, and I will be your conference moderator for today. [Operator Instructions] And at this time, I would now like to turn the conference over to your presenter for today, Mr. Mike Watford, Chairman, President and CEO. Sir, you may proceed.

Michael D. Watford

Thank you, operator. Good morning, and thank you for joining us. With me today are Mark Smith, Senior Vice President and Chief Financial Officer; Bill Picquet, Senior Vice President of Operations; Brad Johnson, Vice President, 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 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 be -- may contain certain non-GAAP financial measures. Reconciliation and calculation schedules can be found on our website.

I begin our conversation today where we left off just a few short months ago. We outlined our plan to significantly reduce capital investments, seeing limited economic returns in the current natural gas price environment, which at the time was around $3 per Mcf for the 2012 strip. With the May contract having just rolled off, pricing for the balance of 2012 June through December is approximately $2.68 per Mcf. As such, we remain committed to limiting our investments to those projects with economic returns. We have seen a number of our peer companies announce capital reductions directed towards dry gas projects, and consistent with that, production growth has stopped.

Now let's take a look at our results for the quarter. We produced 68.8 Bcfe, which was above our quarterly guidance range of 64 to 66 Bcfe, with better than planned performance in Wyoming and Pennsylvania. Good volume growth both year-over-year and sequentially in both assets, with better overall well performance. We generated $185.7 million of cash flow and $49.6 million in adjusted net income during the first quarter.

Deteriorating natural gas prices continue to plague our business. Our hedged price for the quarter was $3.81 per Mcf. On an unhedged basis, our realized price was $2.87 per Mcf or 106% of Henry Hub. We have 84% of our remaining 2012 production hedged for the year, 184.1 Bcfe at a weighted average price of $4.43 per MMbtu.

Our all-in costs were $3.08 per Mcf, about the midpoint of our guidance range. Our cash costs were a low $1.40 per Mcf. We saw a step-up in gathering expense this quarter due to higher sales volumes and increased gathering rates in Pennsylvania. Our net income breakeven is now $3.20 per Mcfe, with cash flow breakeven of $1.30 per Mcfe.

In an effort to reduce capital expenditures in 2012, we released 4 rigs in Wyoming. The financial impact appears on the income statement under rig cancellation fees. We recognized $4.8 million in cancellation fees in the first quarter, which is over half of the amount we expect to incur this year.

In our February call, we announced the reduction of CapEx. We reduced the $1.5 billion we invested in 2011 to $925 million this year. Today, we are reducing it another $100 million to $825 million. This is not adjusted for a potential midstream asset sale. With monetization of our liquids gathering system, our net CapEx for the year is closer to $625 million. Our capital budget is front-end loaded, and we spent 35% of our capital forecast in the first quarter. We will not continue to invest at this pace, and our activity will slow.

The capital expenditure reduction is pretty evenly split between Wyoming and Pennsylvania, about $50 million each. In Wyoming, the reduction will come primarily from ultra-operated well completion deferrals. In Pennsylvania, our partners are reducing their activity in our joint venture areas, and we are continuing to not participate in uneconomic projects at today's gas prices. The economics of our completion deferral decision in Wyoming show that a mere $0.15 per Mcf increase in natural gas price allows one to differ completion for 12 months and achieve the same rate of return as completing today. For the capital reductions, we are maintaining our 2012 annual production guidance at 250, 260 Bcfe.

We have now accumulated over 136,000 net acres in the Niobrara as part of our grassroots new venture effort in Colorado targeting the oil shale opportunity. We have drilled 3 strategically chosen vertical locations to begin assessing the resource potential across our acreage position. In all 3 wells, we collected a substantial amount of geological and engineering data that includes full log suites, rotary sidewall cores and 475 feet of conventional core. Analysis of this data is currently underway, and we are initiating plans for our first horizontal test that will likely occur this summer. We look forward to providing you with continued updates of our progress.

Having been active in Pinedale for over a decade, our operations continue to run smoothly. As anticipated, we are now drilling in better parts of the field with individual wells testing as high as 70 million cubic feet per day. We continue to refine our operational efficiencies and are now drilling wells, on average, in 11.6 days compared to 13 days to drill a year ago. We continue to explore alternatives to improve asset performance, particularly in the completions area. We are investigating various frac designs to reduce well cost, and we'll likely pursue these projects more aggressively in a higher gas price environment.

Shifting to our Pennsylvania Marcellus asset. Well performance continues to consistently equal or exceed our type curve expectations. During the first quarter, a 4-well pad into Tioga County came online with average production rates of 8.9 million cubic feet per day, including one well with a 30-day average of 9.6 million cubic feet per day. In addition, another 4-well pad was brought online with average initial production rates of 7.3 million cubic feet per day.

Given how critically focused we are on allocating investment dollars to projects with the highest returns, we are relying on predictive tools like 3-D seismic to aid us in our investment decisions. We continue to delineate our Pennsylvania resource by overlaying seismic attributes with well performance data and -- then use this model to gain a better understanding of higher quality acreage areas.

We've mentioned before that sweet spot wells are, on average, 2.5x better than non-sweet spot wells. Our predictive model is consistently validated by additional well results that enables us to focus drilling and investments in these areas. We plan to continue refining this tool, and we'll use it to evaluate our new 3-D survey coming out this summer.

As projects -- as project economics continue to be challenged by low natural gas prices, both of our Marcellus Pennsylvania partners are in a flight quality mode, and reevaluating and reducing activity in our areas of mutual interest. In fact, Shell's planned activity on our joint venture area has changed significantly since it was initially defined last December. Their original plan called for just over 180 wells to be drilled in 2012. They have now reduced their original plan by 70 wells, about 40% and currently plan to drill 112 new wells this year.

Additionally, the majority of well reductions occurred in an area originally planned for heavy drilling before delivery of our new 3D survey. We are encouraged to see that Shell now plans to wait for the data and evaluate the results before implementing any significant additional drilling in that area. Since leasehold maintenance is not issue, this reduced pace of activity will allow us to -- us time to identify seismic sweet spots prior to moving the rigs in.

Anadarko is reducing rig count from 4 rigs to 1 in our AMI. From a well cost perspective, they are improving while drilling deeper and longer for the same cost as Shell. Currently, their well costs are below $7 million, and they are targeting $6.3 million to drill and complete their wells.

Another resource opportunity in Pennsylvania is the Geneseo. Today, Ultra has participated in 6 gross, 3.5 net Geneseo laterals with 2 currently producing. Other operators in the area are also evaluating the Geneseo, and those results continue to point towards significant potential under Ultra's acreage.

Recently released Pennsylvania production data shows the key Geneseo well offsetting our acreage in Lycoming County that averaged 5.3 million cubic feet per day during its first 140 days of production. This is a Marcellus-like well, and geologic analysis indicates similar reservoir conditions should extend under Ultra's Clinton and Lycoming County acreage. We have drilled 2 wells in this area, with initial results from the first well expected during the second quarter. In addition, another 4 wells are expected to come online this summer, which will help us have a better handle on the Geneseo by year end.

Going forward for the remainder of 2012, you will see our activity level slow, capital expenditures decline and production flatten. Given that we are a natural gas company, we think this is the prudent path. Unfortunately, given where natural gas prices are currently, we are forecasting an impairment charge on a non-cash ceiling test write-down in the second quarter.

We do think that natural gas prices have bottomed, and we see a few encouraging signs. Activity is decreasing rapidly. Natural gas horizontal rig count down 40% from a time. Rockies production per Bentek pipeline data is down 1 Bcf per day year-over-year, and the last few months of EIA data point to flattening if not slightly declining lower 48 production.

So the tide is beginning to turn, gradual at first and then picking up speed when we move forward in time. We see a correction in pricing coming. Until then, we are limiting our investments, preserving our balance sheet and developing a grassroots oil play. We continue to believe in the long-term quality of our assets and the future of a low-cost natural gas producer.

We would like to now open up the line for questions, operator.

Question-and-Answer Session

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

Can you talk a little bit more about the specific drivers of the reduction in CapEx relative to keeping production guidance flat? How much of that was related to a backlog reduction by your partners or broader cost reductions that may be more ongoing or other factors that may be the drivers?

Michael D. Watford

Well, Brian, I think it's more of the fact that we overspent in 2011 relative to the production we saw, and we had a large backlog of wells waiting to either be completed or put online in the Marcellus with our outside operators. I think that's where most of it is, and now, we're starting to see the benefit of that. So I don't think it's much about pricing reduction in terms of cost of wells.

Brian Singer - Goldman Sachs Group Inc., Research Division

And given the fall in the account in areas such as the Pinedale or even the Marcellus, do you see opportunities for renegotiations? Do you see the potential for well cost to fall? Or should we just expect that inflation -- a lack of inflation should keep prices flat or -- well cost flat?

William R. Picquet

I think one -- this is Bill, Brian. One of the things that we are seeing in Pennsylvania is with reduced activity, there's a surplus of equipment. Over time, that would equate to prices flattening and potentially being lower than negotiations, but we don't see that being a near-term impact as far as reduced costs are concerned. That'll be over a longer haul.

Brian Singer - Goldman Sachs Group Inc., Research Division

Great. And lastly, are you pursuing any other new ventures of note beyond the Niobrara that you've spoken about?

Michael D. Watford

Probably.

Brian Singer - Goldman Sachs Group Inc., Research Division

Are there any that you'd like to provide more color on?

Michael D. Watford

Not today, but thank you for allowing me the opportunity.

Operator

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

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

My question, about balance of '12 and '13. And strip prices remain here and how you're sort of looking at activity levels and CapEx savings going forward. And if you've sort of taken a look at -- I'll probably get the same answer as the new ventures question but how, if any, acquisitions play a role going forward.

Michael D. Watford

I think you're right. You'll probably get the same answer on the acquisitions, so we'll just kind of push that to the side. But 2013 I think is your question, what are we thinking?

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

Yes.

Michael D. Watford

Well, we've -- we're thinking all over the place. We've run a bunch of sensitivities on cases on lower capital, middle-level capital, high-end capital. By that, I mean, low capital, less than cash on the middle capital. Probably cash flow and higher capital levels above cash flow, where you incur a little extra debt. And when we're looking at 2013 gas prices, there's $3.50 now. And we think they're going to increase over time, get closer to $4. Then we're rolling all those through our model and sort of looking at it. We haven't set upon any path yet. We don't need to. Right now, we're enjoying the fact that our partners are making the right decisions in terms of the decreasing capital in this environment, and we want to see more of that before we worry about how much we spend next year. So we have lots of alternative cases, and we're prepared to execute on those. That give us sort of a range of production in cash flow and all within the tolerance of our debt requirements and whatnot. So I'm kind of talking around in circles, I know, but I don't really have a pointed answer to give you.

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

Okay. Then maybe something a little bit more near term. So the Wyoming plan right now is still to run the 2 rigs but defer completions. And so I'm trying to get a sense -- I assume, per well, deferring completion saves you $2.5 million, $3 million or something, and I suspect there was 35 or 40 net wells that are getting completed. So I'm trying to get an idea of how many wells you are going to defer. And if there's -- or are you baking in a rig drop in the Pinedale leg of this year?

C. Bradley Johnson

Yes. This is Brad. I can comment on that. First, on the completion side, the dollars you cited are right in range. And when we look at the economics, it was an economic decision. At this price environment, it takes very little of gas price uplift to actually create value by deferring a completion. So that uplift that Mike said earlier, about $0.15, is well below what we've seen for strips. So to us, it's sort of a slam-dunk economic decision. From an account standpoint, we're seeing relative to our original budget, it's about 35 gross wells and about 20 net wells completion wise that we're deferring for the remainder of the year. And it's about $45 million net capital attributable to the completion deferrals.

Michael D. Watford

Can we say that at least one of our partners there is going to start deferring completions in Wyoming as well?

C. Bradley Johnson

That's correct.

Michael D. Watford

So as Brad said, it's kind of a no-brainer from an economic standpoint.

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

Yes. Okay. Oh, so you got them in the same direction. All right. So that's a pretty big chunk of the Wyoming program. So I guess it's all that much better that your guidance remains pretty strong for Wyoming. Is that a fair claim there, that despite all these deferrals, that you'll be able to maintain -- or Pinedale volumes, you'll be able to sort of mitigate the decline curve?

C. Bradley Johnson

Certainly, there's mitigation. We -- production we posted in first quarter was related both to Wyoming over performance as well as Pennsylvania. So both of those 2 areas are going to mitigate decline. Obviously, completion deferrals has an impact, but everything else from a performance standpoint is tracking well, at or above previous forecast. So that's why the production guidance for the year is remaining the same.

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

Okay. And then in the Marcellus then, what is the rig count assumption? So one for Anadarko, and what was the number for Shell?

C. Bradley Johnson

Shell currently has 5 rigs in the AMI, and we see that going down to as low as 3 during the year.

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

All right. And if I toss this number out, do you see Marcellus production by year end sort of staying at the 200 a day range? Or do you expect it to incline materially from here?

C. Bradley Johnson

We'll see some modest increase just as a result of our completions working off the inventory in Pennsylvania. So the production will increase modestly throughout the year. I think we'll hit a peak rate higher than where we are now, quarter-over-quarter, relatively flat.

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

Okay. And one final one for me. The Geneseo potential, could you characterize that in terms of -- you might have done this on previous calls, but acreage and pervasiveness and how homogenous the zone might be throughout your acreage?

Douglas B. Selvius

Sure. This is Doug. I think on previous calls, I've indicated that we see 75% of our acreage perspective in the Geneseo. And we're going to be, as Mike indicated, acquiring a lot of data during the course of the year that will help us continue to assess that. But the well -- the one well mentioned offsetting us is a very strong well, and we have a substantial amount of acreage in that immediate area. And our geological data indicates, if nothing else, the rocks looking better as we move from that well onto our acreage position. Now this is down in Lycoming and Clinton Counties. Up to the North, in Tioga, we don't have a lot of production data yet, but we'll be getting that during the course of the year. All we can do is project what we're seeing on logs, and a good bid of that acreage also appears to be quite prospective at this point. Does that help?

Operator

[Operator Instructions] Our next question comes from the line of Leo Mariani with RBC.

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

You talked about your production in the Marcellus continuing to trend up during the year. Looking at your second quarter, production guidance is down a fair bit from 1Q. Is that just going to be Pinedale? Are we going to see Pinedale moving in the opposite direction during the year? And could you maybe just talk about how you see your overall company production trending sort of on a quarterly basis this year?

Michael D. Watford

I think we've directionally commented on that where we said that we're going to see decreases in activity in CapEx in production quarter-after-quarter as we proceed through to the year, so if that's the answer you're looking for.

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

Okay. And I guess with respect to the Niobrara, when do you folks plan to get some well results? Will that come in the second quarter earnings?

Douglas B. Selvius

Well results in terms of production tests and so forth?

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

Yes.

Douglas B. Selvius

Yes. That -- hopefully, we'll have something by then. Right now, our plans are -- we're evaluating the data that we're acquiring right now to design our first horizontal well, which we're projecting for mid-summer, maybe late summer.

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

Okay. But I think you guys were frac-ing some vertical wells. Are you planning on maybe releasing any of those results at some point?

Douglas B. Selvius

We really don't have anything to release at this point. It's just too early.

Michael D. Watford

And we have a competitive situation out there to where little tidbits of data we just did not release.

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

Okay. In terms of Pennsylvania, can you guys quantify maybe how many wells you guys have gone nonconsent on so far this year?

Michael D. Watford

No.

Operator

Our next question comes from the line of Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

The majority of my questions had been answered, but just wanted to clarify a comment you made earlier that you're wanting to see further CapEx reductions. I mean, if we see gas prices -- if we don't -- I mean, they've been up $0.40 for the past few weeks. But if they were to stay at this level, could you see a further CapEx reduction as the year progresses or into 2013?

Michael D. Watford

If...

Mario Barraza - Tuohy Brothers Investment Research, Inc.

I mean, if gas prices stayed where they were today, would you further curtail production going further?

Michael D. Watford

We're talking about the plus or minus $2 gas price? Or we're talking about...

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Say today, like $2.30, if we're to stay $2.35, where it is right now.

Michael D. Watford

If it stays at $2.30, will we cut CapEx more?

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Yes.

Michael D. Watford

No. I mean, we're assuming that we're going to be at this price range for the remainder of the year until we get back to winter, again have a chance to reset. So no, that wouldn't cause us to modify any more than we already have.

Operator

Our next question comes from the line of Ron Mills, Johnson Rice.

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

Just a question on -- if you have any update at all in the timing of the midstream asset sales. You once again referenced the net CapEx that still suggests a $200 million sales expectations. But what are we looking like in terms of timing?

Marshal D. Smith

Ron, we continue to evaluate a number of options. We're well advanced on the process relative to monetization. We have received indication of interest in financing in support of the transaction. We'll continue to test the alternative against other options we have, and we'll work toward an option that provides the most value to the company. And we're still some time away before we finally get that across the finish line.

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

Okay. And when you evaluated the well deferral versus the price increase, just were you doing that on versus strip? And were you comparing well deferrals versus, say, the second and third quarter versus the same respective periods in 2013? I guess I'm trying to get a sense as to how fluid those well deferrals could be in the instance that the gas prices do move higher over the second half of the year. How quickly would you potentially move to put those completions back in?

C. Bradley Johnson

Sure, Ron. This is Brad. What we did is we looked at average wells and average cost and simply looked at gas price environment. We looked from $2 to $5. But if you look at $3 and you simply defer the capital investment point of a completion by 12 months -- and that curve is not a very insensitive -- I mean, the curve is pretty flat. So you move it out 12 months, and it doesn't take a whole lot of gas price uplift to preserve value. So we looked at anywhere from 6 months to 18 months, at $2 price to $5 price. And the $0.15 in a sort of a $3 gas price environment pushed the completion out by 12 months, and your value neutral. So $0.15 relative to a $1 uplift from the strip, it's pretty compelling to us to wait. And I think the key thing too on the completion side is we can resume those operations pretty quickly and be very responsive to market as we monitor throughout the year.

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

Okay. Great. And then one last one. I know that both Shell and Anadarko are lowering their activities, but once again, you provide the time 0 charter for the well performance. And do you think, from a completion standpoint, both the operator -- both outside operators plus yourselves are pretty dialed in, in that kind of 5 to 7 Bcf range is depending on which area is probably the right number? Or do the wells -- do some of the wells still continue to outperform in each of those areas?

C. Bradley Johnson

I think we're dialed in from a resource standpoint with our partners pretty well. I think we have one partner who still remained very concerned about the cost and the economic decisions around the program. But go forward, completion wise, that's going to be the bulk of our activity go forward. We see those volumes there, and we see the well performance continue to meet or exceed expectations. And we're just looking forward to reduce drilling activity in this environment.

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

And what has Anadarko done in terms of getting get their well cost down from the mid to upper 7s down to 7% and hopefully, down another 10%?

C. Bradley Johnson

I think one of the key things, they have a very clear understanding of their cost. They track them very diligently. I think secondly is they've implemented efficiencies with the rig fleet. And I think third is they have water management programs up and running and the investments in those last year. We are now realizing the benefits of those cost reduction measures with handling water.

Operator

Our next question comes from the line of Mark Hanson, Morningstar.

Mark P. Hanson - Morningstar Inc., Research Division

You mentioned a possible ceiling test write-down in Q2. Just wondering if that triggers a redetermination of your borrowing base and how that might impact any debt covenant you have, tied to the NPV of your oil and gas properties.

Marshal D. Smith

Mark Smith here. We don't have the classic borrowing base redetermination that you think about with traditional E&P companies. What we have is a PV-9 covenant. It's tested once a year. We do the calculation and provide it to the banks and work to stay within that covenant level. So that's the longer answer. The shorter answer is that a ceiling test write-down non-cash charge wouldn't trigger anything out of that covenant.

Michael D. Watford

Yes, it's just noncash. Unfortunately, being of full cost accounting company, you don't get to write it back on when gas prices are $4. It's just a one-way calculation. So it's pretty meaningless effort.

Mark P. Hanson - Morningstar Inc., Research Division

Okay. And my follow-up, I think you had addressed this on last quarter's call. How much acreage, or if you want to quantify it, wellbores might be at risk from going nonconsent on some of the Marcellus joint venture positions?

Michael D. Watford

Well, let me -- let's do it this way. We've got some -- how many -- it's like 2,900 net wells drilled in the Marcellus is our number. Gross wells would be twice that, more or less. We're talking about maybe 50, 60 over the course of 12 months or so. So it's insignificant. It's not material in terms of the scale of the asset we control. And if we have a situation where someone's costs are too great, this pricing environment assumes to that view.

Operator

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

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

Sorry if you touched on this already, but with us maybe being at an inflection point for gas, have you -- are you having any different thinking about your hedging strategy right now?

Michael D. Watford

Oh, yes. We think that it's not the time to hedge for 2013, '14 if that's what you're asking. We think there's far more upside than downside. We agree that we're at an inflection point. And so with everyone withdrawing capital from it, people are making some of the correct economic decisions. And then I think we will get a supply response. It will just take a little bit. And with that, much like the forward curve moved down pretty dramatically since November, I think it can move up pretty dramatically. So no, we think that we'll get better time to lock in pricing going forward.

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

Okay. And I was thinking mainly about Pinedale, this question, but I guess the same could be said for the Marcellus. To the degree that you laid down some rigs in Pinedale, do you have any sense as to whether that equipment is staying in the area or whether it's moved down to another basin? I'm thinking about assuming that the point comes when you want to ramp back up again, whether it would be a situation of there being a long lead time to actually get equipment back.

William R. Picquet

This is Bill. As far as the equipment that we've released, it's all moving out of the area. It typically is going to the Williston. We don't anticipate that that's going to be easily undone. It's likely that those rigs will stay up there. So we'll have to come to solutions as far as timing is concerned knowing that one possibility would be entering into contracts for new rigs, and we'll just see what the market will yield at that point in time.

Michael D. Watford

But I think that's a good point you bring up, Noel, that's it's not going to be easy to turn the activity back on. There will be a delayed reaction, because people will be slow to commit to multiyear rig contracts in a $4 gas price environment.

So you have to feel comfortable it's going to be $5 or $6 before we do that. So I think the -- turning gas flight back on will take a little longer time than what people probably perceive.

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

So do you think the same is the case in the Marcellus? I don't know if rigs are that far heading to the Utica, which isn't -- not close but I guess not extremely far.

Michael D. Watford

I think that's the case. I think with Anadarko in particular, I think they're taking their rigs to Utica. So I -- yes.

Douglas B. Selvius

Shell.

Michael D. Watford

I think it's the same thing. Shell is going to do the same thing, Doug just said. So yes, it's going to be the same issue.

Operator

Our next question comes from the line of Brian Velie of Capital One.

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

I have one quick question, just a clarification on the 75% perspective number that we are talking about for the Geneseo earlier. That's on the Clinton-Lycoming area? Or is that over the whole Marcellus position?

William R. Picquet

That's the whole Marcellus position.

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

Okay. And then the -- Geneseo is kind of the Upper Devonian or within that Upper Devonian level, I suppose. Are you...

William R. Picquet

That's correct. It's about 900 to 1,000 feet above the Marcellus.

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

Okay. And others in different parts of Pennsylvania granite are perhaps expecting a good liquids component from wells in the Upper Devonian. Do you have any anticipation for what you might see?

William R. Picquet

No, we expect it to be dry gas.

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

Okay. So despite it being Upper Devonian on that side, on the eastern side, it's still going to be the dry gas. Okay.

Michael D. Watford

Yes.

Operator

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

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

You guys addressed this a little bit earlier. But if I think about the $0.15 number, how long would you have to stay at a -- whatever, a $3 or a $3.50 true up before you would add rigs back? Do you need to see that for 2 or 3 -- before you add the completion rigs, I guess. Would you have to see that for a 2- or 3-month timeframe? Or what -- or would it hedge that in? Or how should we think about, when that price goes up, how long would it have to stay there?

C. Bradley Johnson

I think the key takeaway -- what we did is -- it's a pretty simple model. We just deferred the completion event, assumed a flat gas price at some point in the future and then hone in on what the equivalent value would be. And I think the key thing is the $3 gas price environment versus $0.15 uplift, you're talking about a 5% change in pricing to justify deferred completions. So -- and of course, keep in mind we're talking about hyper-volatile decline wells, so it doesn't have to be sustained that long to get the revenue and the PV out nearly in time, performance of that well. So -- since it's not that sensitive to a price assumption, this demonstration is a $0.15, 5% uplift commands deferring completions.

Michael D. Watford

I mean, the real point here is as an industry, we should probably shut in all of our gas, because you go from $2 to $2.50 and sit on the sidelines for 6 months, you'd make a lot more money. And you have this production metric that you're going to fall behind, which is surely going to make more money for your shareholders.

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

Okay. That makes sense. And then my follow-up then to that -- to your second point, Mike. If -- obviously, if you're shutting down rigs or deferring completions and pulling back on the rig count this year, you and the non-op partners -- and I start to look at the production profile. I mean, '13 -- it seems hard to exit this year and still keep up production growth for '13 unless you see an uptick in prices. Is -- am I -- any comment on that? How do I think about '13 production, I guess, because I'm ...

Michael D. Watford

Let me -- I mean, we have -- I'm a little chagrined that we're having a production increase this year. I just did not have production increase. I don't think this the right pricing environment to have any increased production. But -- so production growth isn't the goal. Perhaps flat production is more the goal right now in this environment. We're looking for economic returns at whatever gas price is current that we can bring our production on into against our well cost. We want to have positive returns. That's what we're focused on more than production growth. But we have modeled, again, lots of different cases based on real low CapEx and modest CapEx and higher CapEx, and we have different production and cash flows. But the first thing for us is whether we make money or not, we're more interested in that than we are on production. So I'll just leave it at that.

Operator

Our next question comes from the line of Tim Rezvan with Sterne Agee.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

I was just hoping if you could quickly provide any color on where things stand with Banning-Lewis Ranch. I heard May was the month where we might hear some information. Do you have any update you can provide?

Michael D. Watford

What are you looking for?

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

And possibly ability to drill or kind of ruling some of that committee. Recent articles have talked about recommendation to the City Council in May, kind of how that could possibly drilling into the Niobrara there.

Michael D. Watford

Well, I mean, I think the Council is on schedule to have their commission report, their panel report, whatever they call it. I think they're going to allow outsiders to review it and make comments, we'll be one of the outsiders, before they officially decide what to do. So I think that's all on plan. And I'll note that we find the city pretty friendly to deal with these days, so we're optimistic as to what the outcome is going to be.

Timothy Rezvan - Sterne Agee & Leach Inc., Research Division

Okay. So no -- you don't have any kind of timeline you can provide on a possible...

Michael D. Watford

No, I would not -- I wouldn't get in front of them. I'll let them set the timeline.

Operator

[Operator Instructions] And our next question comes from the line of Andrew Coleman with Raymond James.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

I just had a question on -- just going back to the ceiling test. Did you -- will you list in your Q? Or can you tell us what the -- how much cushion you had at the end of the first quarter?

Michael D. Watford

I don't think it's in the Q, but it was -- our audit committee meeting on Monday afternoon, it was hundreds of millions of dollars. Off of the top of my head, it was $300 million. We can get that for you, Andrew.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

Okay. Cool. And then I guess from an accounting standpoint, is if you're drilling wells and not completing them today, do they go into the full cost pool? Or do they go stay in the unamortized acreage?

Michael D. Watford

They go to the full cost pool, and I get to write those puppies off.

Andrew Coleman - Raymond James & Associates, Inc., Research Division

All right. Sounds good. So kind of looking back in the financial statements, it looks like in 2009 when gas prices also fell and kind of the space took some write-downs. Your DD&A rate fell by about 20%. Do you think that might be an upper bound for what DD&A could improve if you end up taking an impairment in the second quarter?

Michael D. Watford

No, I don't see it as an upper bound. No. I think it'll -- Mark's doing some calculations. But he can get back to you separately, but I know I think we'd see it drop more than 20%.

Operator

And our next question comes from the line of Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Most of our questions were answered but just will ask what price gets you to commit to adding rigs back in the Pinedale.

Michael D. Watford

I don't know, somewhere north of $5, maybe closer to $6. No one's going to add rigs to dry gas at $4 gas. Whoever thinks that is misthinking.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. Well, if that's the thought process, what's 2013 CapEx look like if we sit here at under $4 then?

Michael D. Watford

We haven't decided that yet. So I mean I'm just not going to answer the question. It's not timely.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. All right. And you -- I apologize if you explained this at the beginning of the call. I jumped on a moment late. But the rationale for drilling but not completing a well versus just completely turning the rigs back, does that have to do with these rigs being a long-term contract? Or what's the thought process there?

William R. Picquet

This is Bill. It has to do mainly with just maintaining our efficiencies over the course of time and having a base to ramp up from. As you probably are aware of, over time, we've developed a really efficient operation as far as Pinedale drilling is concerned, and we think that's a good base level of activity to allow us to sustain those capabilities and keep current and continue to improve on how we approach our proficience. So it's mainly just sustaining a base level of capability.

Operator

Our next question comes from the line of David Tameron.

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

Just a follow-up just on Andrew's question about the DD&A. So your guidance is 170 to 180 for second quarter, which is up from first quarter. If you -- are you not projecting an impairment charge in there? And if you did take an impairment charge -- and what hits second quarter, right? Because that's an estimate of...

Marshal D. Smith

David, this is Mark. Just to clarify, the impairment charge is the last thing that we calculate for the quarter. So the DD&A rate will be what is for the second quarter, and then we would calculate the impairment charge based on what prices were. Where we -- just to be -- so...

Michael D. Watford

It had certain quarters where it hit.

Marshal D. Smith

Yes.

Michael D. Watford

Well, thank you.

Operator

And we have no further questions at this time. I would now like to turn the call back over to Mr. Mike Watford for any closing remarks.

Michael D. Watford

Well, thank you very much. We appreciate your time. And if you have follow-up questions, please give a call to our investment relations professionals, Mrs. Whitley and Ms. Danvers. Thank you.

Operator

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

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