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Cabot Oil & Gas (NYSE:COG)

Q4 2011 Earnings Call

February 21, 2012 9:30 am ET

Executives

Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Steven W. Lindeman - Vice President of Engineering & Technology

Scott C. Schroeder - Chief Financial Officer, Vice President and Treasurer

Unknown Executive -

Analysts

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jeanine Wai - JP Morgan Chase & Co, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Pearce W. Hammond - Simmons & Company International, Research Division

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

Unknown Analyst

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

Operator

Good day, and welcome to the Cabot Oil & Gas Corporation Fourth Quarter and Year End 2011 Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President and CEO of Cabot Oil & Gas. Please go ahead.

Dan O. Dinges

Thank you, Valerie. I appreciate everybody joining us for this call. I have with me today, Scott Schroeder, our CFO; Jeff Hutton, VP of Marketing; Steven Lindeman, our VP of Engineering and Technology; Matt Reid, our VP and Regional Manager; and Todd Liebl, our newly appointed VP of Land and Business Development. Before I start, let me say that the forward-looking statements included in our press releases do apply to my comments today.

All right. At this time, we have many things to cover and expand on, particularly the press releases that were issued last night. I will briefly cover full year financial results, the results of our year end reserve analysis. I will discuss our outlook for Cabot, followed by a discussion of our operations in Pennsylvania, Oklahoma and Texas, including a brand-new takeaway project that we announced in the Marcellus. Before I go on the details of these topics, let me give you a couple of cliff notes of the 2011 for the company.

We grew production 43.5%; grew reserves 12% absolute or 22% pro forma taken in consideration asset sales. All-in company-wide finding costs of $1.21 per Mcf, including an all-in $0.65 per Mcf Marcellus finding cost figure. We had doubled the level of proved reserves associated with liquids. 2010 Marcellus wells, we revised up to 11 Bcf from 10 Bcf. Undrilled cut [ph] percentage is 36%, flat with 2010. Net income exceeded $100 million for the seventh consecutive year even with the lowest natural gas price realized in that same timeframe. And our debt levels were reduced year-over-year.

On the financial results. Cabot reported for 2011 clean earnings of $139 million with discretionary cash flow of about $549 million. The year experienced the lowest natural gas price since 2004. Fortunately, this was offset by the highest production growth recorded by Cabot. In terms of full year production, the company posted a 43.5% growth rate in 2011 compared to '10. This was driven by a 42.5% expansion in natural gas volumes, which was driven entirely by the Marcellus and a 68% growth in oil and liquid volumes.

From our organic program and net of asset sales, Cabot had another stellar year adding reserves to surpass 3 Tcf mark, just 2 years after reaching the 2 Tcf mark. Our oil and liquids reserve bookings contributed by doubling between 2010 and '11. However, the main driver of this growth was the Marcellus effort and the continued strength of this drilling program. As we have highlighted in previous presentations, we have wells that rank as the top performers, included -- including released last week by Pennsylvania, 8 of the top 10 for cumulative production during the last 6 months of 2011.

For 2011, the typical 15-stage well has been booked at 11 Bcf, while the 2010 Marcellus program EUR average was raised to 11 Bcf from 10 Bcf. Also of note is Cabot did book a couple of wells with EURs in excess of 20 Bcf, creating a high watermark for Cabot and, most likely, the industry.

At the end of 2011, we adjusted our PUD portfolio removing the EUR in the Marcellus, moving the EUR in the Marcellus slightly higher to 7.5 Bcf for the representative 10-stage well. We also, once again, removed legacy PUD bookings throughout our portfolio, which were not in the queue for drilling, totaling 190 Bcfe. As result and as mentioned, our undrilled PUD reserves account for 36% of the totals with another 5% drilled but not yet frac-ed, and we have a 59% proved developed percent.

In terms of economics, the Marcellus finding cost of $0.65 per Mcf is a standout for the 2011 program. And considering the oil and liquids efforts by the company, the $1.21 per Mcf oil source number is also very competitive. As you're aware, the oil dollars are converted 6:1. Let me also recap with our 2011 program, what we are able to deliver.

Net of asset sales, legacy PUD removal and record production, which was about 600 Bcf, we had double-digit reserve growth, we had competitive finding cost and a debt-reducing program. Obviously, '11 being a good program, the question quickly moves to what are we going to do in '12 as an encore to '11?

Before I go into the operations report, I think it would be beneficial to review our thoughts on the macro environment and also discuss our rationale for capital allocation decisions. We are all aware of the supply-demand imbalance that exists today for natural gas. Our industry is starting to make adjustments by laying down rigs, reducing capital allocated to natural gas plays and throttling back on production growth expectations. Once gas is as good as another on the short-term, midterm effects on supply and the resolved effects of value per Mcf. Regarding demand, we continue to see evidence of natural gas increases in use in power generation, transportation considerations with ongoing expectations and applications for export opportunity. We experienced a no-show for the winter this year, which has left storage at a historic high and lingering concerns for 2012 prices. The industry has made a statement that current market prices will not yield sufficient returns for further capital allocation. Active leasing for natural gas plays is virtually 0. Some companies have elected to allow fringe acreage to expire instead of burning capital. Virtually every company now discusses its desire to allocate capital to liquid-rich plays, and Cabot is no exception to that. However, Cabot does have a large acreage position area in the Marcellus that continues to yield excellent returns at the current market rate. As evidenced by the most recent release by the PA environmental protection on well data, it remains evident that Cabot has the most robust position in the Marcellus. In fact, our internal rate of return exceeds many areas in the Permian, Bakken and Eagle Ford. Even with these results taken in consideration the efficiencies we have gained in our drilling and completion operations and the fact that we continue to manage our primary term acreage, we are able to reduce our capital allocation to the Marcellus by about 15% to 20% or $100 million and still maintain a top-tier growth program of 35% to 50%. Again, I will mention that we are going to maintain our acreage -- all our acreage in the Marcellus. We've taken our foot off the pedal somewhat. Our value-added growth allows us to maintain financial discipline and our cash flow. This will have the effect of bringing our investment to within $50 million to $75 million of anticipated cash. I might add, we do feel the market correction for the price of natural gas has begun. With that said though, the pace of recovery is uncertain. And our 2012 program will be allocating 40% to 45% of our capital to our liquids plays. It is not insignificant that we increased our oil production by 68% last year, and we expect to yet again experience greater than 55% increase in our oil production in '12. Though we're in a soft market for natural gas, as I mentioned, we do feel the floor has been found. As natural gas continues to increase its share of energy demand across the U.S. and the world, I do like our position and expect Cabot to regain the returns it has recently lost in the market.

In regard to hedging, the company added new oil hedges. Since our last report, the company has 31 contracts for 2012 production, including 27 contracts for gas at $5.22 and 4 contracts for oil at $99.30 and 7 contracts in 2013, 5 gas and 2 oil.

In the Marcellus, our results in Susquehanna continue to excel. During the fourth quarter, we achieved a new daily production record of 606 million cubic foot per day, which is 370 million cubic foot per day greater than year end 2010 and a ninefold increase from 2009 exit rates. The well results in Susquehanna continue to show why they're in a class of their own as we have highlighted in our release. Cabot added a new build rig, which brings us to a total of 5 rigs operating in Susquehanna. 2 of the 5 rigs are equipped with the latest technology and can run on natural gas as a fuel source. This is a system we will install and utilize when our CNG station becomes operational in May.

For the year, Cabot completed 904 frac stages, which is an increase of 71% from 2010. In the fourth quarter, we signed a new frac contract, which I mentioned previously, which will reduce our frac cost by more than 30% with even further reductions on all stages after 60 stages are accomplished in a given month. In the initial 2 months of operations, this new crew has completed 82 stages and 92 stages, respectively. Currently, we have 198 stages completing, cleaning up or waiting to be turned in line and an additional 326 stages waiting to be completed.

To help manage capital, our plan is to reduce our well count in the Marcellus by approximately 10 wells, and with no price improvement, we will reduce our rig count to 3 rigs in the Marcellus by the end of the year. Additionally, we will attempt to maximize our frac completion level to take advantage of the most efficient dollars from our new contract, working off our backlog and completing newly drilled wells. Again, I will mention that we do plan on maintaining all of our acreage.

2011 was a tremendous year in terms of the infrastructure buildout for us. During the year, we added significant capacity with the final completion of the Lathrop station to Teel station upgrade and the initiation of volumes into Laser Pipeline. In early '12, we commenced deliveries into the Springville line, completing our initial plans for flexibility and diversification of our markets. In fact today, approximately 50% of our volumes are currently flowing into Transco, 10% of our volumes are flowing into Millennium and 40% are flowing into Tennessee. The remainder of '12 will be focused on completing our current plan for additional takeaway projects we have previously reported.

Our lead projects are classified as work-in-progress. There have been continual changes, some positive, some negative as the planned completion date move around. Let me be clear, the environment surrounding infrastructure buildout is both dynamic and challenging with ever-changing rule book and policy changes. We do intend to update you on new compressor stations, new pipeline and upgrades to existing facilities throughout the year as we place them into service. However, as of right now, the plan for exiting 2012 with approximately 1.5 Bcf of takeaway capacity remains our expectation. That said, we will -- we also reported this morning, a joint venture with Williams Partners LP to develop and construct a new high-pressured pipeline to serve both New York and New England markets through their Transco affiliate. Cabot will own 500 million per day capacity on the new constitution pipeline. This pipeline for the future is our next major step for development of our Marcellus resource and will ensure that Cabot's production will reach the most constrained demand area in the country. We expect the market to be fully supportive of this new link between the Marcellus and our customers' operating area throughout the Northeast. Specifically, the pipeline will move gas from our central compressor station in Susquehanna County to Iroquois Gas Transmission and onto the Tennessee Gas Pipeline 200 line.

Although the in-service date is anticipated early in 2015, we feel this timing is ideal as we internally plan for the future growth of Cabot. Cabot will be an investor in this project for a 25% equity interest valued at $175 million to $200 million. Again, most of this expense will be coming in years '14 and '15. The northern part of our acreage where we've done some drilling, our reserve report has limited information included as it relates to the wells drilled in the, what we'll call, the Laser or northern portion. If you recall during the last 2 months of '11, the Laser Pipeline was placed in service only to be shut-in with miscellaneous startup in operational challenges. Those challenges were partly due to some water production that made its way into the system by other operators. As we have stated before, the northernmost area of our acreage position gets slightly shallower and begins to thin from the top of the section down. This thinning is relative, however, as the section is still over 200-foot thick. Additionally, several large traverse faults go across this area. About 10% to 12% of our acreage falls in this more complex geology. We think this area is going to require greater attention to our lateral placements than the area to the south in order for us to deliver more efficient fracs to the entire length of lateral. Though it's still early in our drilling and completion efforts in the northern part, we do feel the wells in this area will yield similar to the performance we reported by other operators in other portions of the state. Moving south from this complex fault area, you quickly get away from the concern of lateral placements and any issues.

In regard to spacing, Cabot commissioned a third party to determine, among other things, the optimal well development spacing for the Marcellus in our Susquehanna area. This team was selected based on their experience completing similar studies for the major North American shale plays, in addition to their experience in the Marcellus. This study evaluated log information, core data, micro size data, reservoir pressure data and well production volumes and flowing pressures. In fact, physical model was generated, the resulted data was subsequently input into a stimulation -- in simulation model and a history match was generated based on wells producing in the study area. Once validated, multiple simulations were generated to determine the optimum well spacing. The result of this analysis determined that wells in the lower Marcellus may be optimally spaced at a distance of approximately 1,000 feet between laterals, which will allow for an upper Marcellus well to be drilled at a distance of 500 feet away from each lower Marcellus lateral in an inverted V pattern. Cabot is currently drilling a pilot program to test the simulation results. The wells will be TD-ed and completed by the end of the second quarter. However, 6 months to 1 year of production in pressure data will be required to determine if the effectiveness of the pilot program is working and evaluate all the study results. The total number of locations, based on this study, is about 3,000 Marcellus and Purcell wells. Also with a little over 100 wells producing today, there remains tremendous upside and many years of inventory to contribute to our existing and planned takeaway projects, including, of course, our new pipeline to the Northeast.

Now let me move to the South area, in our Buckhorn area and the Eagle Ford. The company has drilled a total of 28 wells. Each well is 100% working interest well and the area lies in Frio, La Salle and Atascosa Counties. 27 of these wells are in production with one well waiting on completion and one well drilling. As we gather information results, we realize how much additional running room we have. Some of the positives from our ongoing study are a 26% increase in booked EURs in our 2011 program versus our 2010 program, a 34% increase in EUR per foot of lateral drill, a 23% increase in our maximum peak production rate and near sevenfold increase in gross oil production from the Eagle Ford. Recent well highlights include the last 7 wells, all in the fourth quarter, averaged 24-hour peak rate was 861 BOE per day with these 3 wells over 1,000 BOE -- excuse me, the 24-hour rate was 861 BOE, with the 3 wells being over 1,000 BOE. The 30-day average of all these wells was 566 BOE. In our AMI area with EOG, there are 9 wells presently on production in this 18,000-acre area with the last 3 wells testing at peak rates that averaged over 1,000 BOE per day. Gross production from both areas in the Eagle Ford is approximately 7,600 BOE per day. Cabot intends to drill or participate in approximately 25 to 30 net Eagle Ford wells in 2012. As was highlighted last week by peer in several pairs, in fact, and in our operations release, Cabot is testing downspacing in the Eagle Ford down to 50 acres at this time.

In the Marmaton, Cabot's progress in the Marmaton, Beaver County, Oklahoma oil play continues with 3 operated wells on production with an average 24-hour production rate of 429 BOE per day. Our fourth operated well is flowing back after frac, with our fifth operated well completing and a sixth well drilling. Also Cabot has participated in 12 non-operated wells, of which 9 are producing, 2 are drilling and 1 is completing. Our average working interest in these wells is 15.3% with an average NRI of 12.1%. With the limited capital plan we have this year and the enhanced results we're seeing in the Eagle Ford, we are planning to use 2 rigs in the Eagle Ford and move the Marmaton rig south, while we schedule and permit additional wells in the areas we are seeing the most extensive fracturing in our Marmaton play. Just a quick comment on the Brown Dense, we have just begun flowing back our well there and have no additional information than that.

2,000 plans in closing, Cabot's operations remain fairly simple. We will continue to focus our gas efforts solely in the Marcellus and allocate dollars in the oil window of the Eagle Ford, which will drive our double-digit growth in reserves and production year-over-year, and all still within 5% to 10% of anticipated cash flow. Valerie, with that executive summary, I'll stop and be happy to answer any questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from Brian Lively of Tudor, Pickering, Holt.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a few questions on the -- Dan, your comments on the Marcellus simulation model. Just curious, what is the assumed EURs for the upper and lower Marcellus?

Dan O. Dinges

Let me see, well, in the lower Marcellus, we have 11 Bcf as our assumed EUR, which is what we have been drilling today, Brian. And the assumed EUR in the Purcell, upper Marcellus as we stagger these wells, we kind of used what our PUD number is right now at 7.5 Bcf until we get further information.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And that's -- I assume that's what's loaded in the simulation work. So what key -- what are the key history match variables?

Dan O. Dinges

I'll let Steve Lindeman answer that.

Steven W. Lindeman

Brian, the key history match variables are really the production rate and pressure that we've seen on the 2 offsetting wells that we have modeled, and then, obviously, as we get an in-fill well, we will then look at that similar information to see how it matches our model.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Then I'm curious too just because the wells have been so productive as you guys have history matched, I guess, some of the production pressure data so far, what type of permeabilities are you guys able to match to?

Dan O. Dinges

Well, Brian, I'll have to get back with you. I don't remember exactly what the permeability numbers were in the model. I was more concerned about the match and how it corresponded to the history. What they did is took the petrophysical data that they had from the logs and then correlated that back to what core data we had to then get a permeability match. And that matched extremely well and then we applied that to the production history, again, to validate the model.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, that's helpful. Just a last question on the simulation work. Are you guys integrating the downhole with the surface conditions? Meaning do you have a long-term forecast of compression and pressures and that sort of thing?

Dan O. Dinges

Yes. The initial modeling that we did was at the -- a higher line pressure but the really, the ultimate model when we looked at our NPV analysis, we looked at a lower line pressure.

Brian Lively - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. Dan, on the $100 million of lower CapEx, the question, I think, is probably out there for everyone is at what gas price would you guys add that $100 million back?

Dan O. Dinges

That's a good question. What we see and what we're able to accomplish with this $100 million reduction, we're able to maintain our acreage, we're able to deliver still double-digit production growth, we're within the $50 million, $75 million of cash flow. We have a production growth of 35% to 50%. And with that being said, we're comfortable in delivering that program, and if it looks like that more on a macro sense, that the market has corrected itself in a way that will not create volatilities, then we would probably start adding additional capital. If it's just kind of a near-term spike in prices or something like that, we'll probably stay the course that we've outlined and until we see some macro improvements in the market.

Operator

And the next question comes from Joseph Allman of JPMorgan.

Jeanine Wai - JP Morgan Chase & Co, Research Division

This is Jeanine Wai. I just had a quick question on your lower Smackover. I know you said that you're just slowing back the first well. But I was just wondering if you could give a little more clarity around the acreage position you have and where it's located.

Dan O. Dinges

No, we have not gone into that at this stage, but as soon as we come up with some well results and all, we'll be able to come out with more detailed information.

Jeanine Wai - JP Morgan Chase & Co, Research Division

Okay, great. And then the second question, as far as your decline curves in the Marcellus, are they really representative, or are the production curves kind of flatter because of the physical constraints that are going on right now?

Dan O. Dinges

I would say that because we're producing into a higher line pressure, they're a little bit flatter than what we would see if we have the opportunity to flow into a lower line pressure. But again, I think, they're pretty consistent through from well to well, and we see a pretty good decline that's consistent.

Operator

The next question comes from Gil Yang of Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

Dan, you said that the PUDs were moved to 7.5 Bcf for 10-stage well. What were they booked at before?

Dan O. Dinges

We had those at 6.5.

Gil Yang - BofA Merrill Lynch, Research Division

6.5 for all the 10 stages?

Dan O. Dinges

Yes. That was again 10 stages, correct.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And the 2010s were how many stages?

Dan O. Dinges

Yes 20 -- go ahead, Scott.

Scott C. Schroeder

Gil, 2010 PDPs, we assumed 14 stages.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And the 2011 was, you said, was 11 -- 15 stages but 11 Bcf?

Dan O. Dinges

That's correct.

Gil Yang - BofA Merrill Lynch, Research Division

Can you talk about how many PUDs per PDP you've been booking?

Dan O. Dinges

We're at just slightly below or right at 1:1.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. Is that going to change anytime soon?

Dan O. Dinges

We're comfortable with that. We've been managing our PUD book, as you're aware, in light of the SEC 5-year rule and in the last couple of years, we've been managing that PUD book. We probably have just a handful of PUDs still that we'll continue to manage into next year and that will be taken care of. But we're comfortable with our PUD booking at this stage.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. How much lower -- could you cut more capital and still maintain your acreage? Or what kinds of resistance to cutting additional capital would there be in your program? Are you obligated to the 4 rigs for this year, and you're going up to 3 later in the year? Or what kind of limitations do you have in terms of additional changes to your budget?

Dan O. Dinges

Well, there's a number of things that balance in making a decision to cut capital. We're still trying to retain as much efficiency in our program as we can, and the greatest gain of efficiency is when we can drill multiple wells from a pad site. That gets strained a little bit as we have to incorporate the development of our acreage out there. And to reduce capital further, create somewhat additional inefficiencies if we have more rig moves. And it'd be difficult, in my opinion, to reduce capital much further than we are right now in the Marcellus. Obviously, we could still reduce some spending in the Eagle Ford by maybe only having 1.5 rigs for the entire year versus 2.5 -- versus 2 rigs. But we don't anticipate doing that.

Gil Yang - BofA Merrill Lynch, Research Division

All right, great. And just a last question. What's your -- what's the current total backlog of wells that are, at some stages, not being -- not producing? What do you expect it to be by the end of the year?

Dan O. Dinges

Are you talking about in the Marcellus?

Gil Yang - BofA Merrill Lynch, Research Division

In the Marcellus, how many frac stages are not yet producing in some stages being completed or waiting on pipeline?

Unknown Executive

Yes. Gil, in the speech, we said we've got 198 stages completing, cleaning up or waiting to turn in line and an additional 326 stages waiting to be completed.

Gil Yang - BofA Merrill Lynch, Research Division

And where is that going to go by the end of the year?

Dan O. Dinges

Well, the simple math is even if you drill just, say, 1.5 wells per month with the rigs and assume a 15 Bcf -- excuse me, a 15-stage completion and averaged somewhere between -- even though they've done really good on the first 2 months of 82 and 92 stages for the frac crew, assume 70, 80 stages a month by the frac crew, that's -- you can do some good math with that.

Operator

The next question comes from Pearce Hammond on Simmons & Company.

Pearce W. Hammond - Simmons & Company International, Research Division

You guys had a lot of success last year of reducing your well cost in the Marcellus. I'm just curious how you see that trending this year.

Dan O. Dinges

Well, this year with the program that we've announced and having a number of rig moves as opposed to just parking on a location and drilling out that particular location, we anticipate the efficiency gain to be relatively flat from the gains that we have to date. We don't anticipate gaining a great deal more just because of the nature of how we're having to conduct our operations.

Pearce W. Hammond - Simmons & Company International, Research Division

Now I know you've already signed your frac-ing contract, the 13-month frac-ing contract. Do you see on other services potential for lower cost that would flow through to your walls?

Dan O. Dinges

On the -- and this is a little bit of speculating right now, Pearce, but on the vendors that we pick up on a spot basis and the announcement made by a number of companies that they would be reducing their rig count whether it's because of natural gas or whether it's a result of the Pennsylvania impact fee that has been imposed, I could see where spot vendors and that type of service could be coming down as some would desire to keep their crews or services busy.

Pearce W. Hammond - Simmons & Company International, Research Division

Great. And then on a leading-edge basis, how many stages are you completing per well right now? And is there a difference between the North and the South within Susquehanna County?

Dan O. Dinges

No. We're -- right now, we have -- are completing, as our '11 program indicated, about 15 stages per well. And when you move to the -- and do we hope to be able to get that a little bit higher? We would hope to be 16 to 17 for our total program in '12. And what we did in moving up in the North area, we recognized certainly with our size that it was a little bit more complex at the very northern end of our acreage and to additional faulting, and we went out there and frac-ed a couple of our early wells and -- but we did set up our micro-size work and as we were frac-ing the early wells, we just kind of went through the fracs. And then after we integrated the micro-size work, and we started looking at the micro size, we determined that the efficiency of some of the fracs along the line drill, if they get off into a fault, we're not getting good efficiencies in those frac stages and in fact, through our micro-size work in the northern end when we started pumping, if we had -- did not get to the pump pressures we wanted to see and felt like we were losing efficiency, we just shut down a couple of the fracs on those wells and said we're just not going to pump that stage and move to the next stage. And that's how we monitored the frac-ing up there with micro size. And that's why I made the statement that as we place these laterals up in this faulted area, we're going to have to just be a little bit more selective on not only where we lay the laterals but how we pick the frac stages.

Operator

And the next question comes from Biju Perincheril of Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Dan, a couple of questions. Just going back to those -- the northern wells. How many do you have now producing there? And do you have a number on what the average well is up there?

Dan O. Dinges

We have about 9 wells producing right now.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then how many of those wells had issues, didn't have -- had an ineffective assimilation?

Dan O. Dinges

Well, we had -- at least half of those wells had issues with what we would deem getting effective frac stages put away.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then do you have a number on the well frac, did it have an issue what those wells are producing now?

Dan O. Dinges

I don't know.

Unknown Executive

That group, that path just went online, so it's very early. And because it was right on the pipeline, Biju, we limited our flow back and we're cleaning these up in the line. But we believe that early indications are that they are performing a lot better than the first pad sites.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Got it. Okay. And then I think you mentioned you're going to go 3 rigs by the end of the year. What is sort of the timeline from going to 5 to 3? When is that first and second rig's going to come off?

Scott C. Schroeder

Biju, this is Scott. The first one kind of rolls off in the July time period, and the next one late third quarter or early fourth quarter. So again back to the earlier question, if we do see some positive changes in the macro that Dan talked about, we could change that decision at that time.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. Got it. So if you do end up going to 3 rigs, then how do you think about your program the next few years from an HBP requirement standpoint, like what kind of rig activity do you need?

Dan O. Dinges

We have every expectation of maintaining our acreage and, again, we balanced our '12 program and I realize it's kind of a snapshot. But with the efficiency we have in drilling out there, I think we can maintain our pace if we look at the horizon and see optimism, we can maintain our pace and catch up fairly quick. And certainly our intent is to stay ahead of the frac rate.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

Okay. And then on the oil side, if I look at your first quarter guidance, if I look at the midpoint, you're guiding to a sequential decline. Is that just some conservatism bolt into the guidance? It doesn't look like you changed it from the last time you updated it. Or is there something from a completion schedule that could cause that?

Dan O. Dinges

No, we're just -- we just are relatively conservative with our guidance. We think the range of 5,000 to 6,000 barrels is okay at this time. And again, once we get deeper in the year, then we'll look at both our gas and oil, and, I think, certainly our oil is anticipated to increase.

Operator

[Operator Instructions] Our next question comes from Jack Aydin of KeyBanc Capital markets.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

A question for you guys. How quickly could you respond to change in prices and what is the price inflection that you might get 50% plus ROR?

Dan O. Dinges

Well, I'll let Scott visit about the ROR a little bit because he's been in a lot of work on that, but as far as the price change, Jack, again I'm not trying to dodge the question, but it is going to be more of a fuel of the overall market and the strength of the overall market and make sure that we have some support and that we feel like that the supply-demand function is in fairly close balance. And as far as the ROR, I'll let Scott visit about that.

Scott C. Schroeder

Jack, as we highlighted in our press release back in January when we announced the exit rate for the Marcellus and reinforced the rate of return, and that was on account of a $3.18 when we telegraphed the realizations for the fourth quarter, at $3 we're still modeling a 50% for tax rate of return. And so these things, as Dan alluded to in his speech, are still highly economic even at this $3 strip that we're hanging around at this point in time.

Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division

The next question I have is basically when you look at 3,000 locations and you -- the simulation and everything, what percentage of those locations is going to be Purcell or upper [indiscernible]? Do you have a number there?

Dan O. Dinges

No, I haven't looked at it exactly, Jack. I think it'll probably be 25% to 30% would be in the -- maybe 40% would be in the Purcell, upper Marcellus.

Operator

And then next question comes from Joe Stewart [ph] of Citigroup.

Unknown Analyst

On the 2011 Marcellus wells, what's the average 24 IP in those?

Dan O. Dinges

On 2011 wells, Joe?

Unknown Analyst

Yes, 2010 was 16.4 million a day if I remember correctly.

Dan O. Dinges

Well, I think it's going to be similar to that. It's going to be 15 million to 16 million cubic foot a day.

Unknown Analyst

Okay, got it. So the cume [ph] production, that's probably going to be pretty close to in line with what you had pointed out in a couple of your presentations about 2.75 Bs in the first year, does that sound right?

Dan O. Dinges

That's going to be...

Unknown Executive

We're modeling about 22.5% in the first year in terms of what the cumes [ph] would be.

Unknown Analyst

Okay, got it. And then you kind of hinted to it a little bit earlier but on the absolute well cost in 2012, with the 30% reduction in the completions, aren't you still expecting a decrease in the total well cost?

Dan O. Dinges

Yes. We're looking at plus or minus $6 million for a 15-stage well.

Unknown Analyst

Okay, great. So plus or minus $6 million versus average of about $6.75 million before right?

Dan O. Dinges

Yes.

Unknown Analyst

Okay. So really that should get your pretax IRR to something closer to 70% at $3 gas if everything else stays the same but you have the 11 Bcf EUR now versus the 2010, right?

Scott C. Schroeder

Yes. I don't know that I'd go as high as 70%, but I know the number would be above 50%, maybe somewhere in the 60% range.

Unknown Analyst

Okay. All right, great. And then -- so the PUDs in the Marcellus, how many PUDs do you have booked now?

Dan O. Dinges

We have about 150 undrilled PUDs.

Unknown Analyst

150, okay. Great.

Operator

And the next question comes from Andrew Coleman of Raymond James.

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

I had a question on Btu content for the Marcellus, I guess, what range of Btu content have you seen in...

Dan O. Dinges

We've seen 1,020.

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

Okay. And, I guess, what sort of -- do you have any CO2 or nitrogen up in that -- up where you produce?

Dan O. Dinges

No, we do not.

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

Okay. And, I guess, how low down -- I mean, I've heard folks talk about ranges throughout the state as low as 800. I mean, is that consistent with what you've seen in your analysis of the state?

Dan O. Dinges

800 what?

Unknown Analyst

800 Btu per Mcf.

Dan O. Dinges

No, where we are, we're at 1,020.

Unknown Executive

[indiscernible] have you seen that? We haven't looked at that.

Dan O. Dinges

No, I'm sorry, Andrew. I have not looked at that across the state.

Operator

[Operator Instructions] We do have a follow-up question from Biju Perincheril of Jefferies.

Biju Z. Perincheril - Jefferies & Company, Inc., Research Division

A quick question, Dan. You mentioned $1.4 billion future development costs. Is that for the wells that are undrilled only? Or does that include the wells that are waiting on completion?

Dan O. Dinges

That's all-inclusive. That is -- is for reserve report capital.

Operator

This concludes our question-and-answer session. I would like to turn the conference back over to Dan Dinges for any closing remarks.

Dan O. Dinges

Well, thanks, Valerie. I appreciate everybody's interest in the program, and I hope everybody appreciates a little bit more of the adjustments that we've made to the program and some of the reasons why we did. Kind of the top 5 takeaway is that certainly we have top-tier Marcellus production and that's evidenced by the most recent DEP release on all the wells in the Marcellus. We have a new catalyst and a new pipeline coming, the constitution pipeline, which we think is setting the stage for a very opportune time that we see out on the horizon for the natural gas market. We have seen some 20 Bcf wells in our area, and we are excited about how they perform. Our cash flow focused investment program even at the current strip price, I think, is going to yield very, very good returns, both in production and in reserves. And with the year end 2012, I think, we're going to be able to mimic what we've done in 2011, and that's have a double-digit growth in both production and reserves and our balance sheet is going to be very strong moving into '13. Thank you for your interest in Cabot. Goodbye.

Operator

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.

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