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Ultra Petroleum (NYSE:UPL)

Q3 2011 Earnings Call

November 04, 2011 11:00 am ET

Executives

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

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

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

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

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

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

Joseph D. Allman - JP Morgan Chase & Co, Research Division

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

Robert S. Morris - Citigroup Inc, Research Division

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Third 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. Michael Watford, Chairman, President and CEO. Please proceed, sir.

Michael D. Watford

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

Ultra Petroleum had very good results for the third quarter of 2011. We delivered double-digit growth in production, cash flow and earnings. The 63.4 Bcfe or 689 million cubic feet equivalents per day of production for the quarter is a new company record and 14% above year-ago numbers.

Not only did we achieve a production record corporately, but we hit new production highs in both of our assets, and we are very near a positive inflection point in our Marcellus production growth. Our cash flow of $1.67 per share is an increase of 29% over prior year period, and our earnings of $0.72 per share is a 20% increase over 2010 third quarter.

One of the keys to our financial performance is our cost structure. Ultra's cash cost for the quarter were at $1.43 per Mcfe, and the total of cash and noncash costs was $2.78 per Mcfe. The low cost helped drive our low breakeven levels and superior returns. Our net income breakeven is now $2.70 per Mcfe, with cash flow breakeven of $1.10 per Mcfe. Ultra generated a 74% cash flow margin, a 32% net income margin, a 32% return on equity and a 14% return on capital for the quarter, all outstanding metrics in any industry.

Turning to natural gas prices. Our unhedged price increased 5% year-over-year to $4.29 per Mcf or 102% of Henry Hub for the period. We see higher year-over-year prices, currently up 16% at Opal and 9% at Dominion South, with an overall leveling of prices across the country. For example, Opal is currently trading at 103% of Henry Hub and Dominion South is trading at 103%. Pipeline capacity additions and changing supply is revising historical pricing patterns. Bottlenecks may develop for short periods of time. For example, the recent 300 -- recent Tennessee 300 situation. But with additional capacity bought into service, prices normalized quickly.

Glancing at our CapEx program, we spent $399.4 million during the quarter. Year-to-date, we have invested $1.1 billion of our planned $1.35 billion program. Conscious of spending levels, we are reducing expenditures in the fourth quarter for our plan, by releasing 2 rigs in Wyoming and by a little slower drilling pace in Pennsylvania.

Our balance sheet remains strong. At the end of the third quarter, we had $12.3 million of cash and cash equivalents on hand and $278 million borrowed on our bank facility. Deciding to refinance our bank debt in advance of its maturity next year, we recently closed a $1 billion credit facility in October. The new facility preserves our financial flexibility and increases our total debt capacity to over $3 billion, providing us with roughly $1.2 billion in unused debt capacity.

Now let me talk about our 2 assets in our portfolio.

In Wyoming, our net production averaged 564 million cubic feet equivalents per day. We achieved a new peak, a net production record of 589 million cubic feet equivalents per day during the third quarter and since then, have hit 599 per day.

We drilled 61 wells in the third quarter and brought 83 online. Year-to-date, we have drilled 190 wells and brought 222 new wells online. As the numbers illustrate, we are reducing our inventory of drilled but not yet completed and online wells. We exited 2010 with 70 wells in our backlog, and now through efficiency gains, expect to end the year with 25 wells in our project inventory. Excellent execution.

With these efficiency gains, we continue to set new standards in our operational performance. The 52 operated wells we drilled in the third quarter matched our all-time high for wells drilled in a 3-month period, previously set in the second quarter of this year. We established a new record for drill time of 7.5 days to drill 13,500 feet. Our entire rig fleet is consistently drilling more efficiently, averaging just less than 12 days to spud for the operated wells during the quarter. This is another quarterly record for our Pinedale program, and we see continued improvements in early fourth quarter performance.

98% of our wells are drilled in less than 15 days by the TD in the third quarter, and we are finding new ways to push the limits on drill times. We are delivering more wells with fewer rigs. To put this in context, 3 years ago, we drilled 156 wells with 14 operated rigs. This year, we expect to drill and case 190 wells with 8 operated rigs. Continuous improvement is key to our business, with these new standards raising the bar for future operations.

Let me talk about well sizes in Wyoming for a moment. Our acreage is largely federally-owned and as such, the plan of development is a joint process between the federal regulatory agencies in the state of Wyoming and the producers. We, Ultra, are not the sole decision-maker in choosing where we drill wells in the field, so we don't necessarily gets to drill the best wells first. In fact, our average well sizes changes over time, as we are active in different parts of the field. For example, in 2006, we averaged EURs slightly in excess of 5 Bcfe per well; 2007, a little larger than 4 Bcfe; in 2008, over 3.5 Bcfe; 2009, back up to 5 Bcfe; 2010, 4.5 Bcfe; and this year, with more flank and 5-acre wells, about 3.6 Bcfe.

A simple 5-year average of reserve sizes is 4.5 Bcfe, which happens to match the average reserve size for the field. In 2012 and 2013, we move to parts of the field where expected EURs will range between 4.5 to 6 Bcfe. We have participated in approximately 1,700 wells so far in the field, with an undeveloped inventory 3x that number, over 5,000 locations yet to go. So the variability of well sizes, over time, is not significant.

Let me mention a few notable completions in our Wyoming operations this quarter that go to the issue of where we are drilling in the field. A Boulder well was brought online with an initial production rate of 10.4 million cubic feet per day, and a Warbonnet well is brought online with an initial production rate of 10 million cubic feet a day. Both of these wells are located in development area 4, DA 4, which is in the southern part of the Pinedale field.

At the end of the quarter, 6 of the 8 drilling rigs were operating in this area. Looking ahead the expectations for the fourth quarter. We plan to drill 52 wells and bring online 67 wells for a total of 242 wells drilled and 289 wells online for 2011.

In Pennsylvania, our Marcellus production averaged 126 million cubic feet equivalent per day. This represents 18% of our total company production and a 155% increase over the third quarter of 2010. On a sequential quarterly basis, we grew our Marcellus volumes 20% over the second quarter of 2011 and achieved a new production record of 140 million cubic feet equivalents per day. Our year-end exit rate is estimated to be 160 million cubic feet equivalents per day but could be as high as 220 million cubic feet a day based on year-end well connect timing.

We drilled 48 wells during the quarter and brought online 26 wells. The new well startups are almost twice the number of wells placed on production in the first 6 month of the year, underscoring the anticipated increased pace of activity. Year-to-date, we have drilled 129 wells. We placed 59 wells on production thus far, 45% of which occurred in the third quarter.

At quarter's end, there were 10 horizontal rigs working on our acreage and 4 frac crews. Currently, with a bit of drilling slowdown in the fourth quarter, there are 6 horizontal drilling rigs and 4 frac crews active. We expect this count to increase in 2012, approaching 9 rigs throughout next year.

As to the accelerating activity, we anticipate another doubling of wells online to occur in the fourth quarter. Plans are to bring 47 wells online, while only drilling 40 during the fourth quarter. For the year, a total of 169 wells will be drilled and 106 wells brought online. While we have tempered our original online forecast for 2011, we expect to exceed our production target from Pennsylvania due to flatter production declines and stronger wells.

Beyond the Texas Creek wells mentioned in the press release, we brought online several wells in eastern Tioga County, across our [ph] area, with excellent results, 3 of these individually tested over 15 million cubic feet per day. On our second quarter call, we discussed our evaluation of the Geneseo potential on our acreage.

As a reminder this an Upper Devonian shale we think is prospective across 75% of our land position. We acquired core samples from 2 vertical wells during the third quarter, encouraged by ongoing exploration effort. We will be collecting more data, in fact, drilling 4 more wells in the fourth quarter.

Through our G&G efforts, a 3-D seismic continues to add value in delineating Marcellus sweet spots, as we are seeing positive correlations between seismic character and observed well results. We currently have 315 square miles of 3-D and are now adding 140 square miles of new data that will increase our total 3-D coverage to 455 square miles. Early next year, we will have 3-D data over 50% of our land position. By end of 2012, we expect to have seismic data across 90% of our 260,000 net acreage position.

Well performance in our Marcellus development area affirms that longer laterals lead to better EURs. On average, we produced 1.1 Bcf for every 1,000 feet of lateral we drill and complete. In one area though, early data indicates we are producing 1.6 Bcf per 1,000 feet of lateral. As you may recall, we started out drilling 3,500-foot laterals 2 years ago. Today, our average lateral length is 5,500 feet in Clinton and Lycoming counties. Out to the north, our laterals averaged 4,100 feet in Potter-Tioga counties. We're striving to drill the longest lateral as possible in both of our areas.

Another area we're working to optimize our investment dollars in completions. Data from initial pilot study indicates that fluid volumes are more important to frac effectiveness than proppant volumes, and it may be possible to reduce proppant without materially impacting the well performance. We think this will help reduce completion cost, and we have additional studies planned in the next quarters to further our understanding.

At the end of 2010, we have 62 wells in our backlog and expect to exit 2011 with 125 wells in our project inventory. Not the best execution, but the good news is that well performance continues to exceed our expectation, allowing us to achieve production targets.

The better news is what's happening now in the fourth quarter and the impact on 2012 production. We are at a positive inflection point in our Pennsylvania production with an easy doubling of production plan for 2012, from 40 Bcfe to 80 Bcfe, if not 90 Bcfe, and possibly, at the high-end even 100 Bcfe. Evidence of this coming growth is 26 new wells online on the third quarter, 47 in the fourth quarter, and early plans for 2012 are for more than 250 wells online, well more than a doubling of activity over the 106 wells online in 2011.

Describing our year-end 2011 Marcellus backlog in another way, the 125 wells represent roughly 1,875 frac stages. Assuming a conservative average of 430 Mcf per frac stage, there is over 800 million cubic feet per day of initial production tied to these wells. We own half.

And then there's the upcoming 2012 drilling plan. So the simple story in 2012 is the only way we don't exceed 290 Bcfe of total production is if the Pennsylvania backlog remains the same or grows, not likely. While this year's execution will land us at the lower end of our production guidance, it will be very difficult for us to not grow production in excess of 290 Bcfe next year. Let's talk more about 2012 including capital expenditure thoughts.

As stated earlier, we believe we are at an inflection point in Pennsylvania. We are on the front end of clearing the backlog of wells and on the cost of seeing the benefits of transitioning to development mode in much of our Pennsylvania acreage. We believe this has a meaningful impact on our production expectations for 2012. Let's look at this in a little more detail, particularly with respect to varying levels of CapEx.

For approximately $300 million of drilling and completion capital, we see 245 to 250 Bcfe of production in 2012, basically flat to 2011 production levels. With another roughly $250 million or approximately $550 million in total, we see production in the range of 265 to 270 Bcfe or 8% growth. And for an additional roughly $450 million or just over $1 billion in total, we see a wider range of 290 to 300 Bcfe in production for the year, 18% to 30% growth.

So I think the take away is we can deliver reasonable production growth in 2012 for about half of our cash flow and much larger growth by merely spending our internally-generated cash flow. We see 290 Bcfe of 2012 production as a floor with meaningful upside, based solely on execution not resource risk or access to capital.

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

Question-and-Answer Session

Operator

[Operator Instructions] And the first question will come from the line of Subash Chandra, Jefferies.

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

A question on -- are we to infer then that the 2012 CapEx is $1 billion?

Michael D. Watford

Subash, we don't even take our capital program for approval to our board on our February board meeting. So these are just preliminary numbers, preliminary thoughts. I think, our drilling and completion capital and what we're trying to do is just sort of peel back the onion a bit and give you a taste or smell of what we can do based on the options. I think, I mean, I think, we'll spend every bit of our cash flow in 2012, how we elect to do this is still we have an open issue right now. But clearly by spending only half of the cash flow we can grow 8%. By spending all of it, we can grow anywhere between 18% to 30%, so it gives us some flexibility as to perhaps if we wanted to do something else with our capital.

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

Okay. So the maintenance capital is $300 million?

Michael D. Watford

For 2012, it is. And I think that's a reflection of probably the overinvestment in 2011 being very candid. We spent money in Marcellus that we really haven't repeat the production uplift on. Yet, we're going to get that in 2012.

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

Okay. And losing count of my follow-ups here, but in Pinedale, what type of growth do you see? I guess, saw a drop here. Are you going to 6 rigs immediately, and is that the average for 2012? And is that enough to grow volumes in the Pinedale?

C. Bradley Johnson

Yes. This is Brad. We're actually at 6 rigs right now. We expect that to be the run rate for 2012. And with those 6 rigs, we do expect growth out of Wyoming.

Michael D. Watford

Let me correct him. We actually have a plan that goes from 6 to 4 rigs throughout 2012.

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

Okay. So an average of, say, 5 rigs, you plan on growing Pinedale next year?

Michael D. Watford

Yes.

Operator

And the next question will come from the line of Brian Singer, Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

In the Marcellus, can you talk to the backlog of Ultra-operated wells versus Anadarko-operated wells versus Shell-operated wells, which ones are moving now and which ones do you think are -- poised to move first here, potentially by the end of the year and how you're taking about where you're positioning your rigs or participating in others' rig as you're looking at 2012?

Michael D. Watford

Let me do it more generically, and Brad can help. There's only one reason we have backlog from Pennsylvannia, and that's nothing to do with Ultra or Anadarko. Our backlog came down, and Anadarko's came down. The other unnamed partner is the one with the big growth. So that's where we need to see better execution. And they promise better execution.

Brian Singer - Goldman Sachs Group Inc., Research Division

And it sounds like you feel less poised to happen here very near term?

Michael D. Watford

I think so. I think they're all over it. I think they're embarrassed.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then can you talk to plans in the DJ Basin and how are your other new ventures are proceeding and whether you see yourself adding acreage in and at what significant sum in the next year?

Douglas B. Selvius

Sure. This is Doug. In the DJ, last quarter, we reported 100,000 net acreage. We're now just over 110,000 net acres, and we expect by the end of year that number will grow to 130,000 to 135,000 net acres. We filed permits for 3 wells. We're preparing for 3 vertical wells, and we're preparing permits for 2 additional wells. So we anticipate 3 to maybe 4 vertical wells, with initial spuds taking place in January. And we'll assess those and see how it drives us for the horizontal program. In terms of other new ventures' plays, we're looking at the number of things. I mean, we're seeing opportunity in plays all across the country, but we prefer not to get too specific at this time.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. I guess, do you anticipate a more meaningful budget dedicated towards those plays that you are not specifying, either be a drilling or acreage acquisition in 2012?

Douglas B. Selvius

Meaning for the relative term, I mean, if we can generate the opportunities, I think there'll be money available for them. I think that's part of the message as to rate of growth in 2012, how we choose to spend the cash flow.

Operator

The next question will come from the line of Joe Allman, JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Just in terms of the Pinedale EUR, that you spoke about earlier. So I mean, is there -- would you think you've exhausted the best locations? Or...

Michael D. Watford

Absolutely not, absolutely not.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. And so did you think that what's remaining, is it proportionate with what you've drilled already? I mean, have you...

Michael D. Watford

Joe, what I think is the 2006 to 2010 average is 4.5 Bs per well. You saw it go up to 5 Bs per well, down to 3.5 Bs per well. If you look at the remaining wells in our inventory to drill over the next 20 years, they averaged per [indiscernible] 4.5 Bs, and we're going to flow it up and down around that 4.5 Bs for the next 20 years.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Okay. That's very helpful. And then on the Marcellus, what's the evidence right now that your partner is going to be moving quicker in terms of the drilling and completion? And then also, I think, in the second quarter you talked about the cost on the Anadarko-operated acreage being higher than you had planned. Has there been an adjustment there?

Michael D. Watford

Well, on the one part, it's a bit underperformed for their own target numbers. I mean, they spent a lot of money to get active in this area, and they have some acquisition economics. I'm sure they have some return hurdles. So they have every incentive to improve the execution. They have the capability of doing that. They have the intent to do that. So there's no reason for us to not think they're going to do it better each and every day going forward. So on Anadarko well cost, you want to get that one, Brad?

C. Bradley Johnson

Right. Well costs in Pennsylvania are flat quarter-to-quarter. In the Anadarko and our southern area, those costs are $7.5 million. And then up north, in the northern area, part of Tioga, $4.8 million per well.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Is that where you would expect them to be at this point? Or do you think there's still room to adjust? I mean, are you recommending doing things differently that would help those costs?

C. Bradley Johnson

Sure. We're holding those costs flat for now but we do anticipate those to go down over time. We're already seeing efficiencies in both areas with respect to cycle time. And we're also starting to see the early benefits of our water management programs that reduce the costs to get water to our operations. So I would expect those to decrease over time. We are still remaining -- we are still investing in some of our product programs and gathering additional data to optimize our development, so that will be mixed into the plans going forward. But I do expect the costs to go down.

Operator

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

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

Just had a couple of things. In the scenario where you talked about just spending just half of your cash flow for production next into 2012. How long do you think you could produce at a rate of activity that low before you'd really get to a point that you, just out of necessity, you'd have to ramp activity back up to sustain your growth? Because as you said, kind of overinvested for now. And I mean, would it be 2012 alone? Would you have the option of, say, going into 2013 similarly conservative?

Michael D. Watford

Right. I mean, what we're trying to show is that what most of us understand is most of the capital you spend, and particularly in the second half of any year, really benefits you the subsequent period, not the current period. So the folks are concerned when CapEx goes up at the end of the year and reflect on no positive production impact over that current period, it's -- well, I mean, the positive production effect is going to be in the subsequent period. So we're trying to show that if we're not driven for double-digit growth in the 2013, '14, '15 timeframes, then there wouldn't be any reason to spend that at $1 billion level that we could spend very usefully spend at $500 million or $600 million level have reasonable growth for 2012 and position ourselves for, I don't know exactly what, but for some sort of level of growth in 2013 and '14. So that most of the differential between $500 million and $600 million and $1 billion is all about what level of growth we want for 2013 and '14. So it's sort of supercharges the numbers for '13 and '14, and we're just trying to lay it out there to give you a sense of what our portfolio allows us to do. And also, if we decide that 8% growth in 2012 is enough, we'd rather spend that $600 million on something else that we have that option, we still have growth. That's what we're trying to share with you.

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

Great. That helps a lot. And more or less housekeeping balance sheet question. Looking at your credit line, the balance at the end of third quarter compared to second quarter, if my numbers are right, it looks like it went up about $125 million. And I was just -- is that just -- what was the source of spending? Is it what we're talking about, extra spending for next year? Or is that some of the cost inflation that you're talking about on the last quarter?

Marshal D. Smith

It's Mark here. As we talked, we saw our capital spending up. We're more efficient in the field, so we're spending -- we're drilling more wells in a shorter period of time. So we had some of that, and we also have some cost inflation wells drilled over in Pennsylvania. So as a result, we were spending -- we ought to spend cash flow a bit in that period. So you see the incremental borrowings.

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

So this wasn't like land acquisition alone or anything like that?

Marshal D. Smith

No, no, that's correct.

Operator

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

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

It's Ron here. Question on the tech curves you provided on your presentation or your press release today, it looks like both the Anadarko continues to outperform. And I think you were talking in the past about the shale properties outperforming in some of which even approaching levels of how some of the Anadarko wells had performed. Can you layout, especially as you look at that Potter-Tioga area with shale, what you're seeing that they could lead to the upside on those EURs?

Douglas B. Selvius

Certainly. Those -- the graph you recite is updated data. And in both areas, they are outperforming, and it's the flatter declines over time. As we continue to update our reserve estimates, with more and more production data, we continue to see the EURs trend up. So I think go-forward upside would include longer laterals, optimized completions and then as we drive costs down, the economics will only get better from that point forward.

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

Okay. And then when you look at your plan of development out in the Pinedale, can you help a little bit in terms of how that development process works? For instance, you're in development area 4 right now, which appears to be one of the better areas. How long do your rigs stay in each of these development areas before they move on to other areas via that plan of development? Is it -- will they remain in this more -- area with the higher EURs for 18 months or will it be 3 years?

Douglas B. Selvius

Sure. Simplify, we look at all the opportunities at the pad level. We rank those best to worst. And then we take that schedule and compare that against the access that's available to us by the stakeholders. Right now, we're in DA 4. We actually expect to move some rigs in the DA 3 in 2012. It's only better -- it gets only better from here.

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

And is that DA 4 versus DA 3 -- I haven't seen the map, where you talk about those. Is 3 better than 4 and 1 better than -- or 2 better than 3? Is that how you ranked it and you're just moving back towards those areas over time?

Douglas B. Selvius

We expect -- based on the geology we're seeing and the seismic character, we expect DA 3 to be better than DA 4. Now if your question is do we rank DA 1 as best and DA 4 or DA 5 is worst, no that's not the way it works. We do expect -- based on the geology we're seeing, we expect improved results in DA 3.

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

And that should last for the next couple of years at least?

Douglas B. Selvius

Yes.

Operator

And the next question will come from the line of Bob Morris, Citigroup.

Robert S. Morris - Citigroup Inc, Research Division

Mike, just 2 simple questions. Did I hear you say that you're slowing down your spending in the fourth quarter, that effectively you'll spend $250 million and hit the $1.35 billion budget for the full year?

Michael D. Watford

I think we're going to be close. I mean, we're planning on soft landing here. We've dropped the 2 rigs in Wyoming to help with that. There is less drilling activity in Marcellus and Pennsylvania in fourth quarter with fewer rigs, same frac crews working the fewer rigs. And we also -- in some of the wells in the fourth quarter in Pennsylvania, we have smaller working interest. We don't have a 50% working interest. We have a very small interest in the numbers of wells. So all of that's going to play into a fourth quarter CapEx run rate -- I mean, a CapEx rate of, I mean, to say $250 million to $300 million. We may still tap out over the $1.350 billion, but not by much.

Robert S. Morris - Citigroup Inc, Research Division

Okay. And then in 2012, if we take the scenario where your cash flow is $1 billion to $1.2 billion, and you spend all of that, and there's nothing new there. Sure, I could calculate it, but what would be the breakout between $1 billion and $1.2 billion for the Marcellus and for the Pinedale?

Michael D. Watford

It's going to be more Marcellus in 2012. It will be plus or minus $600 million in Marcellus versus plus or minus $500 million in Wyoming and Pinedale. We could spend the $1.5 billion to $1.1 billion that we have kind of put into our models right now, if that's what we end up doing.

Robert S. Morris - Citigroup Inc, Research Division

And in that scenario, is that just keeping 6 rigs running in the Pinedale, $500 million plus or minus?

Michael D. Watford

That's 6 going to 4.

Robert S. Morris - Citigroup Inc, Research Division

So $500 million plus or minus in the Pinedale, you're still going 6 to 4?

Michael D. Watford

Now the challenge we have is our drilling folks are doing such a darn good job that we keep drilling faster and the completion people are up to some new tricks now too. We're saving some money there, that we'll talk about next quarter and some efficiency that rig count -- if we stay at flat rig count, we end up spending more money year-over-year even at same relative well cost, that we're having to reduce rigs to stay within some sort of target capital program.

Operator

[Operator Instructions] The next question, will come from the line of Andrew Coleman, Raymond James.

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

I had a question for you on the new ventures. I guess, is your bias still as you look at kind of adding acreage and potential new plays to operate everything? Or are you interested in also considering JV opportunities?

Michael D. Watford

I'm not going to say we wouldn't consider JV opportunities, but we've been beat up pretty good about having too much non-operated Marcellus. And so I'm a slow learner, but I learned. I mean, if we still had the opportunity like we do at Anadarko and Marcellus, well that was the best acreage we saw in the area available, and I'm sure we would opt to make more money by investing in the best resource. And if that then was outside our operated, it's outside operated. But absent that clarity or that relative certainess, then I think we're going to opt for operations, and let the skills of our team go to work. It's quite pleasant every quarter when we have our board meeting, when you talk about the additional efficiencies we're gaining in our operated Areas. So we'd like to extend those to other geographic areas.

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

Okay. And then with the potential of various COA to be reversed here next year, and Keystone is elevated, [ph] do you feel that, I guess, the oil base is picture for the Rockies and possibly the Niobrara is improving here and could be a good kind of tailwind for you heading into your program in 2012

Michael D. Watford

I actually haven't thought about that. Yes, I think it's good omen for us. But we run our economics, our exploration economics on pretty conservative commodity prices based, in this case in the oil side. So if we have what we think we have and in the Niobrara, we're doing really well in terms making money, you're going to have sort of more modest oil prices.

Operator

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

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

Just a couple of quick follow-ups here. In terms of some of the new venture plays that you guys are focused on, I guess moving yourselves to oil on that, are you also looking at potentially gassy plays?

Michael D. Watford

We'll look at anything that makes money. The stuff we're focused on right now happens to be oily, but if we see good gas opportunity, we're going to evaluate it.

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

Okay. In terms of the Marcellus area, are you guys operating any operated rigs for Ultra at this point? And do you plan to do so next year as part of your budget?

Michael D. Watford

Right now, we don't have an operated rig in our area. We're comfortable with the exposure we're getting through the 6 rigs going right now in our non-op programs. We're still evaluating our acreage. And if at some point it makes sense to bring a rig in there, we'll do it.

Marshal D. Smith

It's about how much capital we want to spend there. So we had a rig the first part of the year, and contract termed out, and we said, "Okay, we'll just continue to evaluate and learn on $0.50, as opposed to $1.00. And we've had, for most of this time, we've had 10 operated rigs in the joint properties, that's 5, and that's pretty strong level of capital.

Douglas B. Selvius

I would add that our acreage is in great shape. We're not compelled to bring a rig back in to preserve acreage.

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

Okay. So I guess, in terms of some of your thoughts on spending next year, it sounded like you guys were kind of saying maybe nearly 60% in the Marcellus and of course, a lower amount in the Pinedale. And if you had discussions with your partners, kind of around that budget and if those kind of numbers that they've sort of blessed at this point, and you just kind of looking at maybe a longer plan that you may have put in place in the past?

Douglas B. Selvius

We have discussions with our partners every week on plans, and those plans extended to 2012. Budgets have not been formalized. We think we have a good handle on what's going to happen in 2012 in both areas.

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

Okay. I guess, in terms of DJ, any other kind of recent G&G work you guys may have done since last quarter that kind of makes you feel better about the opportunity? It sounds like Mike, you had some positive comments there just a moment ago.

Douglas B. Selvius

We continue to add to our database, and we've expanded our regional mapping. We feel good about it. Do I have something materially different than I had last quarter from log record data or some standpoint? Not really. We're very encouraged by results we're seeing. We see the activity is actually moving in our direction, as you may have noticed. We're still very optimistic and bullish on what we've got down there.

Operator

And the next question will come from the line of David Heikkinen, Tudor, Pickering, Holt.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Guys, I had a quick question just thinking about your Pinedale CapEx. At what gas price would you increase your spending?

Michael D. Watford

David, I don't think it's tied to gas prices, as much as it's tied to allocation of dollars from returns, principally due to the fact that the state of Wyoming has a 12% severance tax, and the state of Pennsylvania still has nothing. They're moving towards an impact. They will see what that ends up being. Principally due to that, we have higher returns and then anything that we do in Wyoming on an investor dollar capital. So that tends to push our meter towards that direction in terms of spending more money.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then your partner, Shell, that has wanted to kind of hold an option in the Marcellus and wait for higher gas prices and is really drilling to hold acreage. It seems like maybe some of their strategy. How do you gain confidence that even at a potentially lower gas price next year that they won't just continue that strategy?

Michael D. Watford

I think you've misread their strategy. They wanted to drill 250 wells in 2012, and we went with them.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

How many of it did they put on production, Mike?

Michael D. Watford

Well, I mean -- I don't think they have any interest in holding production. I think they have every interest in getting the wells on. I think they have targets associated with their acquisition that they want to perform against. So if anything, they would like to go faster than we would.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Do you expect them to complete all their wells if they drill next year?

Michael D. Watford

Well, I'm not saying that every well they drill in 2012 they will get completed in 2012. I wouldn't suggest that to you, no. I do suggest -- I mean, they've given us sort of a preliminary number of what they think they're going to do in terms of working down their backlog and getting online a good number of 2012 wells.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then Anadarko, it seems like they’re having incredible results. Is there any way for you to allocate capital or drive capital there? Or is it just their ramp in their expectation and you'll just ride with them?

Michael D. Watford

No, we’ll just be riding with them. I mean, at the outside you always have the opportunity to submit your own AFPs if you want to. But there's -- we're happy with what they're doing. They costs are a little higher than what we'd like. But we think they'll get those down. But even with their cost structure rate the way it is, the returns in the wells are wonderful.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And on the marketing side, do you market your own gas? And how do you -- do you secure you own firm transportation? Or is that along with your partners as well?

Marshal D. Smith

David, this is Mark. We market our own gas, and we maintain relationships with firm markets in the Northeast.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

How much firm transportation capacity do you have in the Marcellus and the Northeast?

Marshal D. Smith

How much firm capacity do we have in the Northeast?

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes, because of the retrofit contract [ph] .

Marshal D. Smith

Let me put it in context for you, and I'll start in the field. We've got 7 interconnection in Pennsylvania totaling over 1 Bcf per day at capacity in the major pipelines taking our gas in the major markets in the Northeast. As I said, we continue to maintain relationships with those firm markets on those pipelines. And we experienced a bit of a bump in October on the Tennessee 300 line, where some of our gas with Shell is sold. But as a result of those relationships we had, only about 6% of our gas was exposed to daily pricing during the month of October. Now as we saw an additional $550 million a day of capacity was brought in the service effective November 1 on the Tennessee 300 line and as expected, those prices have normalized and serving to further mitigate concerns about price volatility. Going forward, as we see it and as other analysts have published their similar views an aggregate of roughly 2 Bcf a day of additional capacity is going to come into service in this area of the Northeast alone in the fourth quarter. In 2012, we see another roughly 1.2 Bcf a day, expected to come into service a total of 3 Bcf a day by year-end 2012. So if anything, we think the area is going to be oversupply or there's going to be overcapacity, and as a result, we're maintaining relationships with those firm markets and opting not to own firm capacity.

Operator

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

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

How many wells have you completed in the Marcellus so far this quarter?

Michael D. Watford

I think the number was 29, if I recall.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

For the quarter? And then that's a gross number, I assume, obviously.

Michael D. Watford

Yes. We can provide a net number if you want that.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

Sure.

Michael D. Watford

It would be half of it.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

Fair enough. And then for 2012, for new ventures...

Michael D. Watford

It was 26 during the quarter. I spoke 26.

Michael J. McAllister - Sterne Agee & Leach Inc., Research Division

26, okay. For new ventures for 2012 CapEx, is it okay for us to model something around $50 million to $100 million?

Marshal D. Smith

Yes.

Operator

And the next question is a follow-up question from the line of Subash Chandra, Jefferies.

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

I think that just got answered, how you would finance new ventures, it would be out of cash flows?

Michael D. Watford

I mean, right now, is out of cash flow. We're also looking at some opportunities to monetize some extreme assets, and Mark wants to talk about that.

Marshal D. Smith

Sure, Subash, we're always -- we consider that we have a portfolio of investment, and we're always looking at our portfolio to look at the returns that they're generating and other ways to free up capital associated with that and redeploy elsewhere in the portfolio that generate higher returns. As we do that, we think we've got some midstream assets, but maybe more available to others than to ourselves. And so we're looking at potential form of transactions to free up some capital associated with, initially, our liquids gathering system in Pinedale. And we think those proceeds could amount to approaching $200 million.

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

Okay. What's the timeline for that? Is that sort of under initial review?

Marshal D. Smith

It's under initial review, Subash. I hate to put a timeline on it.

Operator

And there are no more questions at this time. I would now like to turn the call back to Mr. Michael Watford, Chairman, President and CEO for any closing remarks.

Michael D. Watford

Thank you. We appreciate everyone's participation today. We look forward to sharing updates with many of you over the coming months. In the meantime, we'll continue to work hard to deliver positive results. We hope you have a great day. Thanks.

Operator

And ladies and gentlemen, this concludes today's conference. Thank you once again for your participation. You may now disconnect, and have a great day.

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