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Ultra Petroleum (NYSE:UPL)

Q4 2011 Earnings Call

February 16, 2012 11:00 am ET

Executives

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

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

Analysts

Andre Benjamin - Goldman Sachs Group Inc., Research Division

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

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

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

Brian M. Corales - Howard Weil Incorporated, Research Division

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Unknown Analyst

Kevin Berents - Wells Fargo Securities, LLC, Research Division

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Harris Arch

Eli Kantor - Jefferies & Company, Inc., Research Division

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

Operator

Good day, ladies and gentlemen. Welcome to the Fourth Quarter 2011 Ultra Petroleum Corp. Earnings Conference Call. My name is Diana, and I'll be the operator for today. [Operator Instructions] As a reminder, today's conference is being recorded for replay purposes. I would now like to turn the call over to your host, Mr. Mike Watford, Chairman, President and CEO. Please 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, Operations; and Brad Johnson, Vice President, Reservoir Engineering and Development; and Doug Selvius, Vice President, Exploration.

I need 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 actual results or developments may differ materially. The SEC permits oil and gas companies in their filings to disclose proved reserves, probable reserves and possible reserves. References in this call to 3P reserves include estimates from each category of reserves are forward-looking statements. Investors can find the disclosure in our 10-K and other filings with the SEC available on our website.

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

Ultra Petroleum delivered solid results for the fourth quarter and full year 2011. We achieved double-digit growth in production, cash flow and earnings, and met or exceeded all of our targets for the year. We produced 245.3 Bcfe during 2011, a new company record, to achieve a 15% growth rate year-over-year. We also had a new production high of 616 million cubic feet per day in Wyoming and 188 million cubic feet per day in Pennsylvania, and are well on our way to exceeding 200 million a day in Pennsylvania.

Reaching these production milestones was particularly significant to us, given the operating challenges in the field we have worked to overcome this year. As you know, we have experienced longer than anticipated partner delays in getting production on in the Marcellus. Additionally, in December, a compressor station fire and subsequent extended outage in Pinedale, as well as a force majeure event on the Ruby pipeline caused by a blocked valve impacted volumes by approximately 1.6 Bcfe.

In spite of these events, our fourth quarter production rose 17% above our fourth quarter 2010 volumes. Our 2011 cash flow of $6.25 per share is an increase of 26% over the prior-year period, and our earnings of $2.52 per share is a 16% increase over the full year 2010.

We are focused on our cost structure particularly in this environment, recognizing that one of the keys to remaining profitable in a cyclical business such as ours is to maintain low-cost. Ultra's cash cost for the year were $1.47 per Mcfe, and the total cash and noncash costs was $2.88 per Mcfe. These low costs helped drive our low breakeven levels and superior returns.

Our net income breakeven is now $2.82 per Mcf, with cash flow breakeven of $1.15. Ultra generated a 73% cash flow margin, a 30% net income margin, a 31% return on equity and a 13% return on capital for 2011, all outstanding metrics regardless of the industry.

Our 2011 hedged price of $5.05 per Mcf was 125% of the average Henry Hub price for the year. We are approximately 180 Bs or 70% of production hits for 2011, which substantially insulated us from declining natural gas prices throughout the year.

Henry Hub prices decreased 20% throughout 2011, yet our $4.15 per Mcfe unhedged gas price was strengthened due to narrowing base of differentials in the West and increasing production in revenue for premium price marks in the Northeast. I should add that the corporate unhedged gas price represented 103% of Henry Hub for the year.

Just quickly looking at our 2 primary assets for a moment, in Wyoming, our fourth quarter Pinedale well results were in line with expectations, and year-to-date in 2012, we are receiving a benefit of moving to better areas of the field. The first 10 wells we have brought online so far averaged 9.4 million a day, with an average EUR in excess of 4.1 Bcfe.

Well performance in Pennsylvania continues to demonstrate strong results across our acreage position, 2 notable completions to point out are in central Tioga, a 3-well pad came online with 9.1 million a day of average production. And another 2 wells were brought online in northern Lycoming County, with an average per well rates of 8.4 million a day.

In addition, we successfully delineated 2 new areas in Marcellus in 2011, and in the northern and western portions of Lycoming County. The 25 wells brought online in these 2 areas had initial production rates averaging 7.4 million a day, all good news.

We are improving our skills and becoming more proficient using 3-D seismic data to model well performance in both assets, but let me focus on Marcellus for a moment. And a recent example, in one area we've worked, we found that wells drilled and seismically identified sweet spots have an average EUR of 5.7 Bcfe, while those drilled outside the seismically identified sweet spots have EURs averaging only 2.1 Bcfe. This type of predictive ability, especially when used to make drilling decisions, will significantly impact returns going forward and give us the ability to high grade our acreage.

Additionally, we continue to be encouraged by the potential for Geneseo development across our 260,000 net acreage position in Pennsylvania. In the fourth quarter, we drilled 2 gross, 1 net Geneseo wells for a total of 4 gross, 3 net wells for the year. We have plans to drill several more Geneseo wells in the first half of this year to gain additional information.

Now, let's discuss our oil and gas reserves, which are the primary determinant value for an E&P company. Ultra delivered another outstanding year of double-digit reserve growth and all-organic reserve replacement of 339%, and a drill bit F&D cost of $1.60 per Mcfe. All-in finding and development costs were $1.82 per Mcfe.

Our year-end 2011 proved reserves were just under 5 trillion cubic feet, an increase of 13% from year end 2010. The most significant growth in 2011 reserves was in the PDP category, increasing 17% year-over-year to over 2 Tcfe. Doubling the number of Marcellus wells online in 2011 contributed to the substantial reserve growth.

For 2011, our proved undeveloped reserves were approximately 2.9 Tcfe. Ultra's ratio of pud reserves to its proved and developed reserves is a low 0.59:1, which is a more conservative ratio than we reported in 2010.

The cost of developed or proved undeveloped reserves is an attractive $1.39 per Mcf. For measure of corporate asset value, I look at our 2P reserves since our probable category includes puds and pud-like locations. Year-end 2011 2P reserves at a $5 per Mcfe natural gas price totaled 10.6 Tcfe with an associated future development cap of $14.4 billion and a PV-10 value of $10.9 billion, almost double our current market value. Tremendous long-term value in long-term assets.

Looking at capital expenditures in 2011, we exceeded our plan of $1.35 billion by about $180 million primarily due to higher than anticipated efficiency gains and productivity improvements in Wyoming, which is good, and significantly higher well costs in Pennsylvania, which is not good. As of 2012 capital expenditures, we think a significant change, of course, is important. We see limited economic returns in the current natural gas pricing environment for new investments, and thus, see little reason to grow. So we plan to reduce our net CapEx by 50% in 2012 to $725 million.

On new investments, we are targeting those projects that have positive returns at $3 gas. We are being very conservative in our production forecast. Again, we don't see growing natural gas production as a goal in this environment. We will continue to fund the early time buildout of the gathering systems both for gas and water.

Separately, we're very excited about our oil shale opportunity with the expectations growing. So a couple of comments on the new ventures front. During the fourth quarter, we added to our acreage position and now have 131,000 net acres in the southern part of the DJ Basin, targeting the Niobrara shale. We expect to drill our first vertical test wells this March to assess all 3 Niobrara benches. Upon evaluation of these results, we plan to drill our first horizontal wells this summer.

With that, I will wrap up my comments and open up -- excuse me, open up the line for questions. Operator?

Question-and-Answer Session

Operator

[Operator Instructions] And the first question is from the line of Andre Benjamin, Goldman Sachs.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

First question, I was wondering, does your current drilling plan assume that prices stay at current spot levels, the strip or some other level? And how should we think about the rig count and production trajectory as we look, say the second half of the year and into 2013?

Michael D. Watford

Well, I think what I said is that we're targeting our investments for 2012 at $3 gas. We note -- and we've done a detailed opportunity rankings of the various areas we can drill wells, both in Wyoming and in Pennsylvania. And we note that the difference of returns between the $3 gas price and the $4 gas price is our 9% return in projects at $3 gas become 20% at $4 gas. And our 15% return in projects at $3 gas become a 29% at $4 gas, and our 23% return in projects at $3 gas become 47% at $4 gas. So we're inclined to wait for a $4 gas before we continue to develop the assets, which we'd largely control. So we don't have any acreage issues to speak of. It just is more prudent to us to make more money in the given assets than to accelerate development now.

So we're slowing things down and we're going to drop rigs in Wyoming. We're going to participate less in opportunities in Pennsylvania, and we wouldn't foresee our production growing over the course of 2012 on a quarterly basis.

Andre Benjamin - Goldman Sachs Group Inc., Research Division

And the follow-up would be, I think on the last call, you gave a few scenarios with some spending plans between $300 million and $1 billion, and I think for $550 million, you said you can get 2.65 to 2.70 Bcf in production, given you're guiding to a little bit more spending for a little less production now. Is the cause of that really just assuming that you work through less of the backlog on the Marcellus? And how should we think about that backlog? Have your partners indicated any plans for what they would need to see in order to accelerate or let it continue to build?

Michael D. Watford

I think there's a couple of causes, the largest is the higher well cost in Marcellus by one operator in particular. So that has really changed the capital component there and made many of those locations uneconomic at today's gas price. Number two is we have some residual issues in Wyoming due to the fire at the compressor station at the enterprise zones. They've done a marvelous job of bootstrapping access to additional compression elsewhere in the area, but we don't have the same operating environment, operating pressures, that we did before and we have more intermittent issues in the gathering system. So until that is all replicated as to where it was prior to the fire, we're going to have -- we have some problems there. So we have a little lower production in Wyoming due to that in our plan. We're trying to be conservative with that. And then secondly, we are seeing less production coming on for the higher costs in Pennsylvania, if that makes any sense. And we're purposely -- let's say this, we did some kind of sort of quick math and said, "Okay, if we produced another 20 Bs in this pricing environment at $2.50 gas with our low cost, our low cash cost, maybe the lowest in the industry, what do we create in terms of earnings and cash flow?" I know we're not creating any earnings. And cash flow is maybe $20 million, maybe high end $25 million of incremental cash for an incremental 20 Bs of production. So it just doesn't make any sense. It's not logical to want to produce additional gas in this pricing environment.

Operator

And the next question comes from the line of Subash Chandra, Jefferies.

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

So my clarity in the Marcellus. The first is as far as well cost, what are they averaging and what's the range? And with the seismic, do you have a sense yet how much of the acreage is in that sort of 6B versus 2B? And what's your partners' interpretation of it is consistent with yours or not? And as far as the partners drilling, are they going to, at this point forward, just basically target liquids and really not target production or EURs? And also, with you participating less in the Marcellus, comments on not consenting these wells.

Michael D. Watford

Subash, that's a long list of questions. You might have to remind us of what they were. Well, Brad, do you want to take it?

C. Bradley Johnson

I'll start with the Pennsylvania well cost, I believe it was the first item. In our Northern area with Shell, those costs have been averaging $6.7 million per well for 2011. And in the Anadarko AMI, we've been averaging $7.9 million. In the Anadarko AMI, we are seeing significant reduction trends in the last part of the year, so we're encouraged about those costs coming down.

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

Okay. But it's just a well cost issue?

Michael D. Watford

Well, except there's one other issue, that -- those Shell costs. We had AFP, they sent us that $4.3 million. The well cost came in at $6.9 million. So we're really disappointed in that outcome.

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

Yes. Understandable. Okay. And then the seismic question, if you have a sense of how much is in the 6 versus the 2?

C. Bradley Johnson

Yes, a couple of comments there. First, we have seismic in every one of our operating areas. But at this point, 40% of our acreage is covered. By the end of the year, 90% of it will be covered. So just a little preamble there. Of the areas we have data, 70% of it appears to be sweet spot-type acreage. So we're very encouraged by that, and you heard some numbers from Mike. Generally, what we're seeing, and we've looked at it in detail now, in 2 areas where we've got a significant amount of well control and in both of those areas, the difference between a sweet spot well and a non-sweet spot well is roughly two and half-fold. So a sweet spot well is going to be 2.5x the EUR, and really, 2.5x the IP in a lot of cases of a non-sweet spot well. But I think that answers your first question. The second question was how are our partners using this. And our 2 partners, as you know, are Shell and the Anadarko. Anadarko is doing similar studies parallel to us, and we are very much in alignment on what the value of the 3-D is and how it seems to delineate good versus less than good areas. Shell seems to see the same thing. They participate in some of these studies for us. They recognize the value. Whether they're utilizing it as much as we would like them to is another question, but they are definitely seeing it and we're trying to influence them in that way.

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

Okay. And will these partners just basically try to drill out liquids at this point and sort of -- and not chase EURs or IPs? And also if you're non-consenting in...

C. Bradley Johnson

And we just really don't have an opportunity for liquids in this play. It's a dry gas play for us across our entire position, so that's really not a factor for us.

Michael D. Watford

And we've seen Anadarko is responding correctly to the economics there and low gas prices and the well cost, and is decreasing activity. They sent us some recent -- excuse me, recent schedules where they are planning fewer rigs operating in the area and less wells and less investment. We haven't seen that for Shell yet.

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

Okay. And the nonconsent topic, is that -- depend? Is that sort of a protest on the well costs or is that commodity-driven or both?

Michael D. Watford

Oh, I think it's economically driven. We're all about economics here. We always have been. At a slightly less than $7 million well cost at $2.50 gas, the much of the Marcellus doesn't make sense. Part of it does, but much of it doesn't. So until those well costs come down or gas prices go up, we're just not going to participate in those investments. And again, we're going to allocate our capital to those projects that have positive returns at $3 gas.

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

Okay. I know I've taken -- asked a lot of questions, just one final one. The Marcellus realizations versus Pinedale, what were they? This is non-hedged.

Michael D. Watford

Now I don't remember those the top of my head, but I know this morning, looking at spot prices, 103% of Henry Hub for Marcellus and 100% of Henry Hub for Opal, Wyoming.

C. Bradley Johnson

This is a lot of stuff to trend that we've seen for some time now. We've seen a flattening of bases across the country. And actually, we've seen our 2 primary hubs, Opal and Dominion South, trading at premiums to Henry Hub for some time.

Operator

And the next question comes from the line of Leo Mariani, RBC.

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

I just want to queue up, I'll follow up on a couple of things here. In terms of potentially non-consenting on some of the wells, how does that impact your acreage position? Do you just potentially lose that wellbore, much lose a section? Can you give us some color around that?

Michael D. Watford

Generally, if we non-consent wells and it's typically a pad, we will be out of that unit, which is typically 640 acres.

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

Okay. In terms of your plan, roughly $400 million in Appalachian CapEx here in 2012, how many wells do you all expect to get done with that cash?

C. Bradley Johnson

We'll talk about the Pennsylvania activity. And I know there was an earlier question about backlog or do you want to focus on -- of the $400 million of earmark for Appalachian, nearly 1/3 of that is earmarked toward working off the backlog of wells that we're waiting on completion, waiting on the pipeline. So we do expect the inventory of those wells to be reduced through the course of 2012. For total activity, we're looking at about 110 wells to be drilled. And we're looking at about 150 wells to be put online over the course of 2012.

Michael D. Watford

That's the gross number.

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

Okay. That must be gross wells on the 110 there.

C. Bradley Johnson

That's correct.

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

Do You have a net number for that?

C. Bradley Johnson

Yes, I do. On a net basis, it's about 50 drilled. And on a net basis for online, 69.

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

Okay. And could you guys quantify what you're seeing in terms of downtime in the Pinedale right now? Obviously, you talked about losing 1.5 Bs or so in December. Where do you think that's kind of impacting you in terms of quantifying that here in the -- as we roll into the first quarter?

C. Bradley Johnson

Sure, absolutely. In Pinedale, prior to the Falcon incident, we were running about 97.5% run time. And after the fire, we are actually back up at prefire rates and pressures. But going forward, we've forecasted an additional 2.5%. So the run time would be 95% go-forward.

Operator

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

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

Just a couple of things. I noticed long-term debt was up a good chunk, I guess about $1.9 billion at the end of the year versus about $1.6 billion at third quarter. Can you refresh my memory, is there some transaction or some other item in there that caused that?

C. Bradley Johnson

No, Noel, it was driven by our capital spending through the year.

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

Okay. Was there anything sort of back-end weighted about that in the quarter?

Michael D. Watford

Well, I think clearly, we paid some bills to one company in particular that were beyond what we anticipated so our debt load went up. But overall, we spent $1.5 billion and our cash flow was $900 million to $1 billion. So we increased debt to the tune of almost $500 million over the course of the year, or will. We may not have yet, there's still -- they were flowing in, so. We outspent cash flow and we don't intend to do that in 2012 in this gas price environment.

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

Got you. And I did see a reference in the press release about asset monetization. I believe it implied it was on the midstream side. Can you just talk some more about that?

C. Bradley Johnson

Sure, Noel. You'll recall that given our broad portfolio of investments, we -- excuse me, tongue-tied. We routinely evaluate the performance of returns of our investments, as Mike alluded to in his comments, and we continue to evaluate how we might monetize or free-up capital associated with our lower returning investments to redeploy them in higher returning opportunities. So we continue to look at opportunities as it relates to our gathering and infrastructure assets, and we're looking at those opportunities that might monetize those assets in the range of about $200 million.

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

Great. And do you have a timeframe on when that might be accomplished?

C. Bradley Johnson

I don't want to put any kind of timeframe on it right now. Maybe late -- perhaps very late, the first quarter into the second quarter.

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Can you talk about the Pinedale, kind of how many rigs you're running, and when and how many you plan to drop?

Michael D. Watford

We are in the process of reducing rig count right now. We started the year with 6, and we plan to go to 2. And those rigs are coming off as a complete drilling on wells that's on right now. So we'll go to 2 in a relatively short time period.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then, Mike, I guess more of a big picture. I mean, obviously, you're reacting to the commodity price. And I mean, is the ultimate goal just to try to stay as best you can within cash flows, try and keep production flat until we see an improvement in price? Is that kind of the big picture goal?

Michael D. Watford

Sure. I mean it's probably better stated than when I attempted earlier. We just -- it doesn't make any sense. Yes. It doesn't make any sense for us to accelerate development of these assets. I mean we're very comfortable with the assets we have in Wyoming and Pennsylvania. And at a mid-cycle gas price, they're worth far more than market value today, so why go faster in this environment? Why incur any additional debt? We're better just to sit back and just proceed to take care of our business as is and wait for product prices to improve, which they will. And I think this morning's 2013, '14, '15 strip is $4.11, $4.13, something like that. We have a very profitable business at $4 and $5 gas, in a $2.50 gas, we don't. And we just don't understand why anyone would accelerate drilling gas wells in this environment. It just makes way more sense to sit back and wait.

Brian M. Corales - Howard Weil Incorporated, Research Division

And just a kind of follow-on on the same thought is, so I mean if we look at fast forward to 2013 and it's kind of strip pricing, can we assume that, that capital budget will be similar to your development drilling or the $650 million you plan to spend on the drilling portion for 2013 in a similar environment?

Michael D. Watford

Well, I mean, we're not really focused on 2013 yet. We need to see if our exploration efforts in the Niobrara pan out. Because if that pans out, then you'll probably see us drill no gas wells in 2013 or far fewer. I mean, again, we're going to -- whatever -- whatever the gas prices are available, we're going to look at our opportunity set and see where we can make the most money by investing our capital. And so, I just -- I guess I don't have much to say about 2013 right now. We're trying to adjust 2012. We're trying to adjust to the significant reduction in gas prices over the last 60 days and be prudent about it.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. And then, I mean if -- I guess, all in all, you're just hunkering down and trying to wait for the brighter day. I mean is that price $4, is it $4.50 or we'll wait and see?

Michael D. Watford

Oh, at $4, we have a very healthy business. Again, I'm looking at my list of my opportunity rankings of 1 through 16 of the areas we drill wells in. And for $4 gas, I've got $1 billion of opportunities at a high rate of return. At $3 gas, not so much.

Operator

Your next question will come from the line of Andrew Coleman, Raymond James.

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

Have you guys given any thought to share buyback?

Michael D. Watford

Given thought to it, but I'm not going to borrow money to buy back stock right now, so we just need to -- the reality is, the situation, we have some commitments that carry out from 2011 and 2012. And I don't know if Brad spoke to that or not, but we've got a fair amount of capital committed to wells that aren't on yet or wells that aren't completed yet, and et cetera. So we need to take care of those commitments and we still want to have an operated program in Wyoming, so we're going to decrease the size of that but maintain that. And then we'll get to mid-2012 and see what makes sense, but...

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

Okay. And then I guess thinking about the production profile, I mean, for you to model as Brian was asking, the last question there on kind of keeping CapEx and cash flow kind of in line. What do you think the, I guess, on the slower activity this year, what would your, I guess, underlying decline rate kind of fall to from a hyperbolic sense from a year of slower drilling when you look at 2013 activity, perhaps?

Michael D. Watford

Why don't you give us a few more months and we'll give you a number. I mean we're still coming down from the aggressive spend in 2011 to a half spend for developmental capital in 2012. So let us assimilate some of that before we give you a number, but yes. But our decline rate, corporate decline rate, is going to come down dramatically.

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

Okay, great. And then if I could just slip one more in here. On your Niobrara verticals, I guess, could you just lay out again which -- are they all going to be de-benched in Codell or are you going to test some of the other zones down there?

Michael D. Watford

We will -- the vertical wells will go through everything. We're going to see all 3 benches and, we'll also take them all down to see the Fort Hays, Codell, Greenhorn and so forth. Our real focus is the Niobrara, and we will take a look at what we see and we will pick a couple, 1 or 2, at least, probably in each wellbore just to test them and see if we can flow out of them. That's the benches I'm talking about.

C. Bradley Johnson

But our expectation is that we'll have Niobrara in all 3 benches.

Michael D. Watford

Correct. Depending on what area, some benches look better than in other areas, but we plan to -- we'll be looking at all 3 of them in the wells we drill.

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

Okay. And as you think about the horizontal well, there's been some operators starting to look at longer horizontals. I'd imagine for your first one, you're going to go there 4,000 or 5,000-foot, but...

Michael D. Watford

That's exactly right. We're setting up to drill 5,000-foot laterals out there for our initial tests.

Operator

And the next question comes from the line of Mike Kelly, Global Hunter.

Michael Kelly - Global Hunter Securities, LLC, Research Division

In the Niobrara, when do you think you'll have gathered enough intel to make the call to move to a development drilling program there?

Michael D. Watford

That's probably not going to happen until next year. We'll be drilling -- we hope to drill our horizontal wells later this summer. It's going to take -- we'll want to put those wells on production and watch them for a while -- next year, at the earliest.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And then the inventory of wells waiting on completion in the Marcellus, you may have mentioned this, but can you give me that figure where it stands today and what you think that will be at the end of 2012?

C. Bradley Johnson

Yes, I can speak to that. All in Pennsylvania are net wells waiting on completion in pipeline is 52.9 year-end 2011. On a net basis, we expect that to be reduced to 34.7 at year-end 2012.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And the number of net wells that is going to be drilled in 2012 in the Pinedale, what -- do you have a figure for that?

C. Bradley Johnson

Yes, I do. So in Pinedale, we see 57.6 net wells in 2012 .

Operator

And the next question comes from the line of Don Crist, Johnson Rice.

Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division

All my questions have been answered.

Operator

And the next question comes from the line of Ray Deacon, Brean Murray.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Mike, I was wondering in terms of gathering and facilities, how does that trend look in 2013, assuming sort of a kind of flat, modestly up CapEx budget?

Michael D. Watford

I would think that we would have most, if not all, of it in Pennsylvania where we're spending money in '11 and '12. We would have it all behind us. That's all pretty much front-end loaded.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Okay, got it. Then with the exploration budget you laid out for '12, is that all assumed to be in the Niobrara? And is there any acreage purchases assumed in there?

Michael D. Watford

The exploration budget is all drilling in Niobrara and there is a separately land budget.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Got it. Okay, great. And I know you tend to do kind of global services contracts in the Pinedale. What I was just wondering is, do some of those roll over for rigs or completions? And what kind of numbers do you think you'll have on well costs in '12?

C. Bradley Johnson

The service contracts are about flat as far as the ones that we've renegotiated this year.

Raymond J. Deacon - Brean Murray, Carret & Co., LLC, Research Division

Okay. And that's roughly the same on rigs and completion costs or...

C. Bradley Johnson

Yes.

Operator

And the next question comes from the line of Nick Pope, Dahlman Rose.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

And just going through the reserves release, I was curious with the pud bookings that were shown in the table. It shows 1,650 wells, I guess, in the pud category. I was wondering if that's a gross or net number. And is that primarily Pinedale and Marcellus wells in that grouping?

C. Bradley Johnson

Yes, that's correct. That 1,646 is a gross number and it is dominated by Wyoming Pinedale, specifically.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Okay. I was just -- kind of as you go forward and you just start to think about kind of some of the limitations that you have on kind of timing on puds and just the current pace of drilling in Pinedale, I guess, what the thoughts are there in terms of if there's any kind of at risk and seeing reserves kind of move out of that category and into just kind of the higher-risk categories, I guess.

C. Bradley Johnson

I would say going forward that our -- the risk of our pud pool has actually diminished. The quality of our wells as we move and elevate locations from possible to probable pud improve, methodically. Those continue to get de-risked. You also note that our pud ratio is actually down a little bit from last year. But we've been consistent with our pud methodology, staying on the conservative side for sure and leaving a lot of additional locations on the shelf for future years.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Okay. So I guess as I look at it, it shows 1,650 wells. What I'm assuming -- so I guess the puds are pretty heavily de-risked individual wells as they're kind of shown in the reserve report. Is that right? Like from where, I guess, normal, they're not booked fully relative to where the PDPs are, I guess. Is that right?

C. Bradley Johnson

Well, I'm not sure. I can speak to ratios of puds to PDPs and volumes and locations, and certainly, the pud locations that we've booked are very conservative when you weigh it on against those ratios. For example, in Wyoming, our pud ratio on a volume basis is about 0.8 -- excuse me, on a location basis is 0.8:1. And in Pennsylvania, our pud ratio is 0.39:1 when you relate pud locations to proved developed locations. And certainly, those locations on the pud pool are all within the SEC guidelines with respect to where they are in proximity to existing wells.

Nicholas P. Pope - Dahlman Rose & Company, LLC, Research Division

Okay, that's helpful. And I was also curious, just kind of back to what you all talked about with what you're all seeing for seismic in the Marcellus, where you said 70% appears to be on the sweet spot. I don't know if it was possible, but just when you look at the northern and southern portions of the Marcellus, like is it -- what the sweet spot, I guess, is in each play or is it pretty comparable? Are they pretty comparable in kind of percentage basis?

C. Bradley Johnson

A couple of comments there. All of our -- of our 315 square miles of 3-D, the bulk of it's up in the northern part. There is 130-square mile 3-D in the southern part. So most of my comments are really based on what we're seeing up in the northern area. Now that 30-square mile 3-D down to the south in Lycoming shows the exact same thing the wells we have on it. We see one well drilled in a sweet spot and one well drilled in a non-sweet spot. And it validates the model. Now what I would tack on to that is down south of Lycoming, well performance is astoundingly consistent. I mean just everywhere we have been drilling wells, the performance is very consistent. So when we get that seismic data in later this year, I'm expecting it to at least be 70% sweet on the seismic.

Operator

The next question will come from the line of Adula Merdi [ph], CBP.

Unknown Analyst

I'm wondering in terms of the $400 million you'll be spending in the Appalachian, how much of that is spending that's tied to Shell or Anadarko that would be, if it were up to you, you'll probably say, I don't want to do it?

Michael D. Watford

Oh, interesting question. 2/3? What do you think, Brad, 2/3?

C. Bradley Johnson

Well, it's 2/3 Shell and 1/3 Anadarko. And probably the Anadarko AMI has the better returns.

Michael D. Watford

Much better. So, yes.

C. Bradley Johnson

We invest there first. And then secondly, behind that would be Shell. So that's the 2/3, 1/3 breakout between areas, and then again, 1/3 of that, $400 million, is earmarked toward working off inventory, which -- that really, the first thing we do is work off the inventory back while the well's already drilled. So that's the best returns, and that's where the bulk of our capital is earmarked toward.

Unknown Analyst

Well if I think about the math properly, if it were completely up to you, and you could do things exactly the way you want to do it, instead of spending about $400 million, you'd probably be spending more like $150 million or something like that.

Michael D. Watford

We got $130 million or so on getting wells online, so that's completing it for online. And we get another $150 million or so in the Anadarko AMI. You add those 2, you get $300 million and then the rest is...

Michael D. Watford

If we're going to rank it based on returns, that's what we do.

Unknown Analyst

So otherwise, if -- otherwise, there is probably about, call it between $100 million and $150 million that you'll be spending this year that, if it were up to you, you'd prefer not to do it.

Michael D. Watford

That's probably a fair comment.

Operator

And the next question comes from the line of Kevin Berents, Wells Fargo Securities.

Kevin Berents - Wells Fargo Securities, LLC, Research Division

Just had a quick question. I'm trying to get my head around the Pinedale and understand you're laying down rigs. And I guess as soon as the wells are drilled, should we expect to see any production shut-in this year?

Michael D. Watford

No.

Kevin Berents - Wells Fargo Securities, LLC, Research Division

Okay, that answers that.

Michael D. Watford

Yes.

Operator

And the next question comes from the line of Mike Scialla, Stifel, Nicolaus.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I don't know if I missed it, but what are your well costs now at Pinedale?

Michael D. Watford

4.8 on the Opal's operated wells.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Sum of 4.8, okay. And have you done any hedging for 2013 or can you share any thoughts on that?

Michael D. Watford

No, Mike, we have not. We decided we aren't going to hedge at much south of $5, and we haven't.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

So that's kind of your threshold for...

Michael D. Watford

That was the threshold 18 months ago. I'm not sure it's the threshold now. But that's why we don't have any in 2013. And right now where 2013 is trading, we just do not hedge there. So as we get up north of $4, we'll consider it. We think the answer right now is for folks not to grow supply. It just doesn't make any sense to grow supply in this environment, so.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

I guess, if you look at maybe the risk of a lot of the associated gas with all of these liquids plays, does that tempt to lock in some base to protect your cash flow for '13 or not so much?

Michael D. Watford

Not so much. I think much more is made of that than will be real. I think much of your growth in gas production, that's why it's been in the dry gas area, so.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. In terms of the sweet spots that you see in the Marcellus, can you talk at all as to what controls that? Is it the thickness of the lower zone in the Marcellus or can you share that?

C. Bradley Johnson

Well, what I think is driving this is rock quality, petrophysical parameters, and those could be things such as porosity, fracture systems, gas saturations, things like that.

Michael Scialla - Stifel, Nicolaus & Co., Inc., Research Division

Okay. And can you talk at all about the results you saw in those Geneseo wells that were completed in the fourth quarter? Or you said drilled. I don't know. Were they completed?

C. Bradley Johnson

Yes. Let me give you a little update there. We've drilled 4 wells to date. One of them is online and we've talked about that. It's our Bergey [ph] well in the marshlands area. And that well's been online for about 8 months now, and it's producing 700 Mcf a day and it's got an EUR in the 1 to 1.5 Bcf range. That's really the only well we have online. Now we've got 6 wells that will come online between April, and say, August, September time period. So we've got one drilling now and 3 more planned in the first quarter in the next few months. And those will come online during the course of the year.

Operator

The next question comes from the line of Marshall Carver, Capital One Southcoast.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

I have a couple of questions. Has Shell outlined their plans for the year in terms of number of wells they want to drill? Just trying to get a feel for how many wells you'd be going non-consent on and how much acreage is at risk by doing that. And is there any chance you'd be losing the sweet spot acreage or is it more the non-sweet spot?

Michael D. Watford

I don't -- I mean Shell's program is limited to our AMI of 150 horizontal wells per year. So that's the high end. We're still working through what we're going to participate and not participate in there, and we're doing it based on economics. The -- I don't know how I'd get into some of this stuff. It -- with their well costs and their inefficient rig fleet and their desire to down space early on in a low gas price environment when they're not at optimal efficiency just doesn't make much sense to us. So I don't guess we're too concerned about what we might miss out on because it's all going to be uneconomic. So we just don't understand why you want to destroy capital. I'm trying to be kind here. So I'm -- to the extent we sit out some acreage and sit out some wells until things improve with product prices and costs, and that's okay. It's the right decision. But the wrong decision is to accelerate in a low gas price environment when your effort's pretty inefficient.

Marshall H. Carver - Capital One Southcoast, Inc., Research Division

Yes. And a quick question on your guidance for this year. What is the -- what are the sort of assumed pace of working through the drilled but uncompleted well inventory? If that gets worked through earlier, is there a considerable upside to that guidance or how would you sort of classify that? How should we think about that?

C. Bradley Johnson

Barring the Pennsylvania backlog, it is, it tends to be more front-loaded for the year. So there is certainly upside with respect to those activities. We've seen well performance, once they're online, actually outpace our predrill predictions. So there's definitely upside there. And then it's subject to timing and timing of when those wells actually come online per the schedule.

Michael D. Watford

So Brad's pretty cryptic, but fair. I mean there's like 10 to 15 Bs of upside. But -- and I know I said this earlier and I'm not saying it very eloquently, but we just don't care to produce it. I mean if it comes on, it comes on, fine. Because they're just not -- we don't make any money with it. We don't create any significant cash. So if it came on 2013 at higher gas prices, that would be a better answer. So we're really -- we think the whole idea of production growth, natural gas production growth is just the wrong -- is counterproductive. So yes, there is upside. There's clear upside. In fact, I would bet that there's more upside than downside in our production volume forecast. We were attempting to be ultraconservative, I guess, is the term.

Operator

And the next question comes from the line of Harris Arch, DuPont.

Harris Arch

Just had a quick follow-on about your hedges for 2013. You mentioned that you're not hedged for 2013 and there's really, given where the strip prices are, no desire to layer in hedges there. If the current commodity price environment continues at where it's at, CapEx for 2013, if we're still in kind of the cyclical downcycle, are you still thinking about spending within CapEx will be -- cash flow will cover CapEx, you won't outspend cash flow? Could you talk -- I know it's a little bit early 2013, but just want to get a sense of if this persists for longer than we think, that CapEx will be within cash flow.

Michael D. Watford

Well, let me address it differently. We said that we're all about returns. We've always been about returns first and growth, second. If we don't have significant returns with our investment dollars, then we choose not to make those investments. So it's only going to be about what the available returns are in our portfolio. So it's -- I'm not even thinking about the CapEx type, the cash flow per se if we don't have -- if we're at $2.50 gas 2013, then we'll spend less in cash flow.

Operator

The next question comes from the line of Eli Kantor, Jefferies & Company.

Eli Kantor - Jefferies & Company, Inc., Research Division

Had a quick question on Pinedale activity. On the last conference call, you talked about how EUR is where you expected to increase as you shift development from DA4 to DA3 area. Can you give us a sense of how big the DA3 opportunity set is, either in terms of number of undeveloped locations or years of development?

C. Bradley Johnson

Yes, certainly. In DA3, as we move north out of Boulder and Warbonnet where we are now, we expect the EURs to be 4.5 to 6 Bs. And we're already seeing some benefit of that year-to-date. Mike mentioned the first 10 wells were brought online as we moved into this area, the IPs are 9.4 and the EUR is up over 4. So as we enter in the DA3, we expect that trend to continue.

Eli Kantor - Jefferies & Company, Inc., Research Division

And how big is that opportunity set? I mean how many locations are we talking about?

C. Bradley Johnson

There's hundreds, several years of activity.

Eli Kantor - Jefferies & Company, Inc., Research Division

Okay. The second question is on Q4 average, Pinedale IPs, I think I read 2 different numbers for Ultra-operated average IP rates in the fourth quarter, 7.8 and 7.4. Just wanted to know what the difference was between the 2.

C. Bradley Johnson

7.4 would be dry gas and then 7.8 is on equivalent basis.

Eli Kantor - Jefferies & Company, Inc., Research Division

Okay. And then the last question is, just on activity levels, at what price you guys start increasing the Pinedale rig count?

Michael D. Watford

It just depends on opportunity set. We have 47% returns in the Anadarko operated area of Marcellus. We may not crank back up in Pinedale for a long time. If we have successful Niobrara oil opportunities, which earns above that at $7 oil, then we may not crank it back up. There's just no timeline.

Eli Kantor - Jefferies & Company, Inc., Research Division

What about specifically for the Anadarko-operated Marcellus acreage? That's your highest return acreage currently.

Michael D. Watford

It is, yes, yes. At $5 gas, we have 80% returns there on much of that.

Operator

And the next question comes from the line of Leo Mariani, RBC.

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

I had a couple of follow-ups here for you. Could you tell us what percentage of your Marcellus acreage is Anadarko-operated and what percentage is Shell-operated?

C. Bradley Johnson

Yes.

Michael D. Watford

Well, I'm sitting here, looking at -- we'd pretty -- we'll just make it simple math here. In 260,000 acres, about 90,000 is Anadarko and 110,000 is Shell.

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

Okay. In terms of your transportation expense, it looks like it was about $0.24 per Mcf in the fourth quarter of '11. You guys are guiding that to go up to $0.31 to $0.33 in the first quarter of '12. Can you kind of walk us through the change there?

C. Bradley Johnson

It's largely driven by incremental REX transportation charges. We picked up $50 million of the incremental capacity on REX.

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

Okay. And in terms of the Marcellus, what was your average pud EUR that you guys booked at year-end '11?

C. Bradley Johnson

I'm looking at it right now. Our puds range from 3.95 to 5.52 in Pennsylvania.

Operator

[Operator Instructions] The next question will come from the line of Don Crist, Johnson Rice.

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

Mike, it's Ron. One quick question. I didn't get in earlier on time. In -- when you go in non-consent on some of these Shell wells, how was the JOA structured in terms of what sort of penalty do you have? Is it just for that particular wellbore? Is it for -- does it cover a particular unit? Is there a -- what's the risk to acreage numbers by going nonconsent? Or is it fairly benign from your standpoint?

Michael D. Watford

It's actually fairly benign. When we non-consent a well, we're out of that wellbore.

C. Bradley Johnson

There's a penalty where you could potentially get back in, but it's a 300% penalty.

Michael D. Watford

But it's unlikely we'd get back in at the costs and prices we're talking about.

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

Right. But the key is, you're -- it's only that particular wellbore. You wouldn't lose future wellbores in a development mode in that particular section or unit?

Michael D. Watford

Correct, correct.

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

Okay, great. And Leo just asked a question on the transportation expense. What -- I mean when you look at the AFEs versus the actual well cost on the Shell wells, what's been driving their higher well cost? And is that part of the delta between the comments you made on your last conference call about various levels of CapEx, what your production levels could be? It sounds like because the Shell wells are costing more that those numbers have shifted around a bit. But is it on the drilling side, is it on the completion side? Or what's causing that higher well cost?

C. Bradley Johnson

Yes, those well costs are higher on all fronts, from the drilling side, driven mostly by not having fit for purpose rigs. And then on the completion side, not leveraging some of the water-handling systems. They're still being put in place. So moving quickly and drilling ahead of allowing some of those efficiencies to be implemented is what's keeping those costs from dropping. They will drop in time, but they have not dropped yet.

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

Okay. And then lastly, you look at the well profiles on the chart in your press release, and is there anything going on with the Anadarko wells in terms of the way they're bringing them on? Or if they're bringing them on at somewhat restrained rates, and that is what's allowing them to start to outpace that 7 Bcf curve? And it would even suggest the curves that even in the Shell area, would look like that they're starting to at least outpace or be towards the top end of the range of what you all had talked about. So in spite of timing and/or well cost, actual well performance, is it fair to say that they've been better-than-expected or outpacing your plans in both areas or is it more heavily weighted towards Anadarko?

C. Bradley Johnson

No, I think if you look at that plot, both those curves are demonstrating, and that's why we had it in there, is to support and demonstrate that the wells are outperforming our expectations. You do have to get beyond the early time. And I would say generally speaking, on the upper curve, which is the Anadarko AMI, that is deliberate curtailment of conservative flow pack protocol that Anadarko makes. On the Shell side, it's really reduced run times on the wells for lead time.

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

Okay. Do you have any lease expiration issues in -- I don't think you have much in the Shell, but in the Anadarko, I'm assuming that they would still maintain enough activity to keep you going through maintain lease expirations.

Michael D. Watford

We're in great shape across the board on our lease position. Anadarko, we're 80-plus percent HBP out there. In 2012, we got next to no explorations and what few we have, about 5,000 with Shell. 5,000 acres, most of that's going to be managed by drilling. We don't really have a problem with acreage expirations until 2014 and beyond.

Operator

And this concludes the question-and-answer portion for today's conference. I would now like to turn the call back to Mr. Mike Watford for closing remarks.

Michael D. Watford

Thank you, operator. I want to thank everybody on the phone this morning as we appreciate your support and attention. Should anyone still have questions, please call one of the members of the Investor Relations group. Thank you.

Operator

And ladies and gentlemen, thank you again for your participation. You may now disconnect, and have a great day.

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