Coterra Energy - Earnings Call - Q4 2011

Transcript

Speaker 3

Good day and welcome to the Coterra Energy Fourth Quarter and Year-End 2011 Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Dan Dinges, Chairman, President, and CEO of Coterra Energy. Please go ahead.

Speaker 0

Thank you, Valerie. I appreciate everybody joining us for this call. I have with me today Scott Schroeder, our CFO; Jeffrey Hutton, VP of Marketing; Steve Lindeman, our VP of Engineering and Technology; Matt Reid, our VP and Regional Manager; and Todd Liebel, 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. 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 Coterra Energy, 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 into the details of these topics, let me give you a couple of clip notes of the 2011 for the company. We grew production 43.5%. We grew reserves 12% absolute for 22% pro forma taken in consideration of 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 approved reserves associated with liquids. In 2010 Marcellus wells, we revised up to 11 BCF from 10 BCF. Undrilled 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. Our debt levels were reduced year over year. On financial results, Coterra Energy 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 Coterra Energy. In terms of full-year production, the company posted a 43.5% growth rate in 2011 compared to 2010. 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, Coterra Energy had another stellar year, adding reserves to surpass the 3 TCF mark, just two years after reaching the 2 TCF mark. Our oil and liquids reserve bookings contributed by doubling between 2010 and 2011. 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, including released last week by Pennsylvania, eight of the top 10 for cumulative production during the last six 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 Coterra Energy did book a couple of wells with EURs in excess of 20 BCF, creating a high water mark for Coterra Energy 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 a result, and as mentioned, our undrilled PUD reserves account for 36% of the totals, with another 5% drilled but not yet fracked. 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. Considering the oil liquids effort by the company, the $1.21 per MCF offsource number is also very competitive. You're aware the oil dollars are converted six to one. Let me also recap with our 2011 program what we were 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 a competitive finding cost and a debt-reducing program. Obviously, 2011 being a good program, the question quickly moved to what are we going to do in 2012 as an encore to 2011?

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. One's guess is as good as another on the short-term, mid-term effects on supply and the result 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 nil. Some companies have elected to allow fringe acreage to expire instead of burning capital. Virtually every company now discusses its desire to allocate capital through liquids-rich plays, and Coterra Energy is no exception to that. However, Coterra does have a large acreage position area in the Marcellus that continues to yield excellent returns at the current market rates, as evidenced by the most recent release by the PA Environmental Protection on well data. It remains evident that Coterra 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, taking 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. Though 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 a 55% increase in our oil production in 2012. 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 Coterra 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, results in Susquehanna continue to excel. During the fourth quarter, we achieved a new daily production record of 606 million cubic feet per day, which is 370 million cubic feet per day greater than year-end 2010 and a nine-fold 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. Coterra Energy added a new build rig, which brings us to a total of five rigs operating in Susquehanna. Two of the five 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, Coterra Energy completed 904 frack stages, which is an increase of 71% from 2010. In the fourth quarter, we signed a new frack contract, which I've mentioned previously, which reduced our frack cost by more than 30%, with even further reductions on all stages after 60 stages are accomplished in a given month. In the initial two 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.

With no price improvement, we will reduce our rig count to three rigs in the Marcellus by the end of the year. Additionally, we will attempt to maximize our frack 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 infrastructure build-out for us. During the year, we added significant capacity with the final completion of the Lathrop station, the TEAL station upgrade, and the initiation of volumes into Laser pipeline. In early 2012, we commenced deliveries into the Springville line, completing our initial plan 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 2012 will be focused on completing our current plan for additional takeaway projects we have previously recorded. Although these projects are classified as work in progress, there have been continual changes, some positive, some negative, as the planned completion dates move around. Let me be clear. The environment surrounding infrastructure build-out is both dynamic and challenging with ever-changing rulebook and policy changes. We do intend to update you on new compressor stations, new pipelines, 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 also reported this morning a joint venture with Williams Partners LP to develop and construct a new high-pressure pipeline to serve both New York and New England markets through their Transco affiliate. Coterra Energy 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 we're sure that Coterra Energy'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 Eriquore Gas Transmission and on to 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 Coterra Energy. Coterra Energy 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 2014 and 2015. On 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 what we'll call the Laser or northern portion. If you recall, during the last two months of 2011, the Laser pipeline was placed in service only to be shut in with a miscellaneous startup and 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 feet 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 fracks to the entire length of the lateral. Though it is 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 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, Coterra Energy commissioned a third party to determine, among other things, the optimal well development spacing for the Marcellus in our Susquehanna County 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. The study evaluated log information, core data, microseismic data, reservoir pressure data, and well production volumes and flowing pressures. Once that physical model was generated, the resultant data was subsequently input into a 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 results 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. Coterra Energy is currently drilling a pilot program to test the simulation results. The wells will be TD'd and completed by the end of the second quarter. However, six months to a year of production and fresher 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 Percel wells.

Also, with a little over 100 wells producing today, there remains tremendous upside, and many years of inventory 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 in the Eagle Ford. The company has drilled a total of 28 wells. Each well is a 100% working interest well, and the area lies in Frio, LaSalle, and Atascosa counties. 27 of these wells are on production, with one well waiting on completion and one well drilling. As we gather information and 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 drilled, a 23% increase in our maximum peak production rate, and a near seven-fold increase in gross oil production from the Eagle Ford. Recent well highlights include the last seven wells, all in the fourth quarter. Average 24-hour peak rate was 861 BOE per day, with these three wells over 1,000 BOE. Excuse me. The 24-hour rate was 861 BOE, with the three 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 nine wells presently on production in this 18,000-acre area, with the last three wells testing at peak rates that average over 1,000 BOE per day.

Gross production from both areas in Eagle Ford is approximately 7,600 BOE per day. Coterra Energy intends to drill or participate in approximately 25 to 30 net Eagle Ford wells in 2012, as was highlighted last week by Pierre and several pairs, in fact. In our operations release, Coterra Energy is testing downspacing in the Eagle Ford down to 50 acres at this time. In the Marmaton, Coterra Energy's progress in the Marmaton-Beaver County Oklahoma oil play continues with three operated wells on production, with an average 24-hour production rate of 429 BOE per day. Our fourth operated well is flowing back after frack, with our fifth operated well completing and a sixth well drilling. Also, Coterra Energy has participated in 12 non-operated wells, of which nine are producing, two are drilling, and one 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 two 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. Our 2020 plans in closing, Coterra Energy'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.

Speaker 3

We will now begin the question and answer session. To ask a question, you may press star, then one on your touch-tone phone. If you're using a speaker phone, please pick up your handset before pressing the keys. To withdraw your question, please press star, then two. Our first question comes from Brian Lively of Tudor Pickering and Holt.

Speaker 6

Good morning. 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?

Speaker 0

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

Speaker 6

Okay. I think that's what's loaded in the simulation work. What are the key history match variables?

Speaker 0

I'll let Steve Lindeman answer that.

Speaker 4

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

Speaker 6

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

Speaker 4

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. We applied that to the production history, again, to validate the model.

Speaker 6

Okay. That's helpful. Just the 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?

Speaker 4

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

Speaker 6

Hey, 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?

Speaker 0

Oh, that's a good question. You know 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%. With that being said, we're comfortable in delivering that program. If it looks like, more in a macro sense, that the market has corrected itself in a way that will not create volatilities, 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 until we see some macro improvements in the market.

Speaker 4

Okay, thank you.

Speaker 3

The next question comes from Joseph Allman of JPMorgan.

Speaker 1

Hi. Good morning, everyone. This is Janine Wei. I just had a quick question on your lowest muckover. I know you said that you're just flowing 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.

Speaker 0

We have not gone into that at this stage. As soon as we come up with some well results and all, we'll be able to come out with more detailed information.

Speaker 1

Okay. Great. 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?

Speaker 4

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 had the opportunity to flow into a lower line pressure. Again, I think they're pretty consistent through from well to well, and we see a pretty good decline that's consistent.

Speaker 1

Okay, great. Thank you very much, guys.

Speaker 0

Thank you.

Speaker 3

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

Speaker 6

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

Speaker 0

We had those at $6.50.

Speaker 6

million for also 10 stages?

Speaker 0

Yes, that was, again, 10 stages, correct.

Speaker 6

Okay. The 2010s were how many stages?

Speaker 0

They.

Speaker 6

2010 TDPs?

Speaker 0

Yeah, go ahead, Scott.

Speaker 4

Gil, 2010 TDPs, we assume 14 stages.

Speaker 6

Okay. The 2011 was, you said, was 11.

Speaker 0

13 stages, but 11 Bcf?

Speaker 6

Yes.

Speaker 0

That's correct.

Speaker 6

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

Speaker 0

We're at just slightly below or right at one to one.

Speaker 6

Okay, is that going to change anytime soon?

Speaker 0

We're comfortable with that. We've been managing our PUD book, as you're aware, in light of the NCC five-year rule. 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. We're comfortable with our PUD booking at this stage.

Speaker 6

Okay. How much lower, you know, 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 four rigs for this year, and you can only drop to three later in the year, or what kind of limitations do you have in terms of additional changes to your budget?

Speaker 0

There are 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. The greatest gain of efficiency is when we can drill multiple wells from a pad site. That gets drained a little bit as we have to incorporate the development of our acreage out there. To reduce capital further creates somewhat additional inefficiencies if we have more rig moves. In my opinion, it'd be difficult 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 one and a half rigs for the entire year versus two and a half or two rigs, but we don't anticipate doing that.

Speaker 6

All right. Great. Just the last question. What's the current total backlog of wells that are at some stage of not producing? What do you expect it to be by the end of the year?

Speaker 0

Are you talking about in the Marcellus?

Speaker 6

In the Marcellus, how many frack stages are not yet producing and some stage of being completed or waiting on pipeline?

Speaker 4

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

Speaker 6

Where is that going to go by the end of the year?

Speaker 0

The simple math is even if you drill just, say, one and a half well 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 two months of 82 and 92 stages for the frack crew, assume you know 70, 80 stages a month by the frack crew. That's, you know, you can do some good math with that.

Speaker 6

Okay, thank you.

Speaker 0

Thank you, Gil.

Speaker 3

The next question comes from Pierce Hammond of Simmons & Company.

Speaker 2

Good morning.

Speaker 0

Hey, Pierce.

Speaker 2

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

Speaker 0

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 gains 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.

Speaker 2

Now, I know you've already signed your frack contract, that 13-month frack contract. Do you see on other services potential for lower costs that would flow through to your wells?

Speaker 0

This is a little bit of speculating right now, Pierce, 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.

Speaker 2

Great. 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?

Speaker 0

No. We're right now, we have completing, as our '11 program indicated, about 15 stages per well. 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 2012. What we did in moving up in the north area, we recognized certainly with our seismic that it was a little bit more complex at the very northern end of our acreage into additional faulting. We went up there and fracked a couple of our early wells. We did set up our microseismic work. As we were fracking the early wells, we just kind of went through the fracks.

After we integrated the microseismic work and we started looking at the microseismic, we determined that the efficiency of some of the fracks along the lateral, if they get off into a fault, we're not getting good efficiencies in those frack stages. In fact, through our microseismic work in the northern end, when we started pumping, if we 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 fracks on those wells and said, "We're just not going to pump that stage and move to the next stage." That's how we monitored the fracking up there with microseismic.

That's why I made the statement that as we place these laterals up in the 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 frack stages.

Speaker 2

Thanks so much, Dan.

Speaker 0

Thank you, Pierce.

Speaker 3

The next question comes from Bijul Perin Shirley of Jefferies.

Speaker 6

Hey, good morning. Dan, a couple of questions. Just going back to 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?

Speaker 0

We have about nine wells producing right now.

Speaker 6

Okay. How many of those wells had issues with, you know, didn't have an ineffective assimilation?

Speaker 0

At least half of those wells had issues with, you know, what we would deem getting effective frack stages put away.

Speaker 6

Okay. Do you have a number on the wells that didn't have an issue, what those wells are producing now?

Speaker 0

I don't know.

Speaker 4

No, that group, that pad site just went in line, so it's very early. Because it was right on the pipeline, we limited our flow back and we're cleaning these up in the line. We believe that early indications are that they're performing a lot better than the first pad site.

Speaker 6

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

Speaker 4

Bijul, this is Scott. The first one kind of rolls off in the July time period.

Speaker 6

Okay.

Speaker 4

The second one is late third quarter, early fourth quarter. 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.

Speaker 6

Got it. If you do end up going to three rigs, how do you think about your program the next few years from an HVP requirement standpoint? What kind of rig actually do you need?

Speaker 0

Yeah. We have every expectation of maintaining our acreage. Again, we balanced our 2012 program, and I realize it's kind of a snapshot. With the efficiency we have in drilling up 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. Certainly, our intent is to stay ahead of the frack crew.

Speaker 6

Okay. On the oil side, if I look at your first quarter guidance, if I look at the midpoint, your guidance was a placeholder decline. Is that just from conservatives involved in the guidance? It didn't look like you changed it from the last time you updated it. Is there something from a completion schedule that could cause that?

Speaker 0

We just are relatively conservative with our guidance. We think the range of 5,000 to 6,000 barrels is okay at this time. Once we get deeper in the year, we'll look at both our gas and oil. I think certainly our oil is anticipated to increase.

Speaker 6

Okay. Perfect. Thank you. That's all I had.

Speaker 4

Speed in.

Speaker 3

As a reminder, to ask a question, please press star, then one. Our next question comes from Jack Aiden of KeyBank Capital Markets.

Speaker 5

Hey, guys.

Speaker 6

Hey, Jack.

Speaker 5

You're back. A question for you guys. How quickly could you respond to changing the prices, and what is the price inflection that you might get 50%+ ROR?

Speaker 0

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

Speaker 4

Hey, 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 a kind 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. 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.

Speaker 5

The next question I have is basically when you look at 3,000 locations and you simulation and everything, what % of those locations is going to be Percel or Upper Devonian? Do you have a number there?

Speaker 0

Oh, 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 Upper Marcellus.

Speaker 5

Okay, thanks a lot.

Speaker 0

Thank you.

Speaker 3

The next question comes from Joe Stewart of Citigroup.

Speaker 4

Hey, good morning, everybody.

Speaker 0

Morning, Joe.

Speaker 4

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

Speaker 0

On 2011 wells, Joe?

Speaker 4

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

Speaker 0

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

Speaker 4

Okay. Got it. The cum production is probably going to be pretty close to in line with what you had pointed out in a couple of your presentations, about 2.75 Bcf in the first year. Does that sound right?

Speaker 0

That's going to be fairly close.

Speaker 4

We're modeling about 22.5% in the first year in terms of what the cums would be. Okay. Got it. 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?

Speaker 0

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

Speaker 4

Great. Plus or minus $6 million versus an average of about $6.75 million before, right?

Speaker 0

Yes.

Speaker 4

Okay. That should get your pre-tax 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?

Speaker 0

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

Speaker 4

Okay. All right. Great. The PUDs in the Marcellus, how many PUDs do you have booked now?

Speaker 0

We have about 150 undrilled PUDs.

Speaker 4

150. Okay. Great. Okay, guys. Thanks a lot. I appreciate it.

Speaker 0

Thanks, Joe.

Speaker 3

The next question comes from Andrew Coleman of Raymond James.

Speaker 6

Hey guys. Sorry about that. I'm just kind of stuffing my throat there. I had a question about BTU content or the Marcellus, I guess. What range of BTU contents have you seen?

Speaker 0

We've seen 1,020.

Speaker 6

Okay. Do you have any CO2 or nitrogen up in that for you produce?

Speaker 0

No, we do not.

Speaker 6

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

Speaker 0

800 what?

Speaker 6

800 BTU per SCF.

Speaker 0

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

Speaker 6

Right. Okay.

Speaker 4

Across the state, have you seen that? I don't know. I haven't looked at that.

Speaker 0

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

Speaker 6

Okay. The 1020, what you guys have in that, that's great. Thank you.

Speaker 0

Thank you.

Speaker 3

To ask a question, please press star, then one. We have a follow-up question from Bijul Perin Shirley from Jefferies.

Speaker 6

Hi. 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?

Speaker 4

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

Speaker 6

Okay. Great. Thank you.

Speaker 3

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

Speaker 0

Thank you, 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 five 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're 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.

With the end year in 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. Our balance sheet is going to be very strong moving into 2013. Thank you for your interest in Coterra Energy. Goodbye.

Speaker 3

The conference is now concluded. Thank you for attending today's presentation.