Seeking Alpha
We cover over 5K calls/quarter
Profile| Send Message|
( followers)  

Cimarex Energy (NYSE:XEC)

Q1 2014 Earnings Call

May 07, 2014 1:00 pm ET

Executives

Mark Burford - Director of Capital Markets

Thomas E. Jorden - Chairman, Chief Executive Officer and President

John A. Lambuth - Vice President of Exploration

Joseph R. Albi - Chief Operating Officer, Executive Vice President and Director

Analysts

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Brian D. Gamble - Simmons & Company International, Research Division

Jason Smith - BofA Merrill Lynch, Research Division

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

Andrew Venker - Morgan Stanley, Research Division

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

John C. Nelson - Citigroup Inc, Research Division

Michael A. Hall - Heikkinen Energy Advisors, LLC

Joseph Bachmann - Howard Weil Incorporated, Research Division

Nicholas P. Pope - Cowen and Company, LLC, Research Division

Operator

Good afternoon, and welcome to the Cimarex Energy First Quarter 2014 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Mark Burford, Vice President of Capital Markets and Planning. Please go ahead, sir.

Mark Burford

Thank you very much, Marie, and thank you, everyone, for joining us today on our first quarter conference call. Speaking today will be Tom Jorden, President and CEO; Joe Albi, EVP and COO; John Lambuth, Vice President -- and John Lambuth, Vice President, Exploration. We also have Paul Korus, CFO; and Karen Acierno, on hand here today as well.

We issued our financial and operating results release this morning and also a release regarding a new acquisition that we announced yesterday after the close. And a copy of the news releases can be found on our website, along with the latest presentation, which we may refer to from time to time today on today's call.

I need to remind you that today's discussion will contain forward-looking statements. A number of factors could cause the actual results to differ materially from what we discuss. You should read and -- you should read our disclosures on forward-looking statements in our latest 10-K, other filings and news releases for risks factors associated with our business.

So we have a lot of to cover today, so I'll go ahead and get the call turned over to Tom.

Thomas E. Jorden

Thank you, Mark, and thanks to all of you for participating in today's conference. We sincerely appreciate your interest in Cimarex.

I'd like to take a few minutes to touch on some highlights for the quarter, before turning it over to John and Joe for a more detailed update. Our success in the quarter, I think, is best described with one word, and that's innovation. Innovation resulted in dramatically improved results in our Cana-Woodford play, which led to record production of 740 million cubic feet equivalent during the quarter, up 12% over last year, but more importantly, up 13% sequentially, which was well ahead of our guidance. This extraordinary success in Cana came from the implementation of upsized completions and some better-than-expected results from a workover program.

These results were a key driver in our decision to purchase additional Cana assets, a transaction we announced yesterday. Upon closing, we'll have spent approximately $250 million for 140 Bcf-equivalent approved reserves and, more importantly, 50,000 net acres, of which 30,000 are in our Cana focus area. With this transaction, we were able to increase our position in the field where we are a dominant player at a time when we are rediscovering its potential. We're experiencing significant uplift to our returns in Cana from an upsized frac, returns that compete with those in the Permian. In addition, we see additional upside in this acreage, including the Merrimack potential.

As you know, we, at Cimarex, seek a return on investment capital, and we're somewhat agnostic as to whether those returns come from oil projects or gas projects. We think it's to our advantage to be a multi-basin company with a portfolio of opportunities. Every now and then, you articulate a strategy, you articulate a philosophy and you occasionally get to demonstrate it by living it. What I want to say is that we've become very heavily Permian-weighted, and I'll -- we'll talk about that a lot in this call, but one of our challenges to our organization over the last 9 months to 1 year has been let's find other areas to get returns that can compete with the Permian.

We manage Cimarex and we manage our program by having a diverse exposure to a number of different play types, a number of different commodity types, and we believe the company is made stronger to have the flexibility of picking and choosing as opportunities arise. We had some extraordinary success and I attribute that to our team in the Mid-Continent working Cana, with their completion innovation and also some workover innovation. And as we sit today, we think our Cana program competes head on with returns with our Permian program. And that is an absolutely wonderful outcome.

Now it's also gratifying to raise our guidance and give an increased growth trajectory and communicate it to you. But I want to say again, and we've said this before, this is about return on investment capital and not about a growth target. And we're delighted to be facing a landscape where we have returns on invested capital in the Permian and in the Mid-Continent area that can compete head-to-head, that gives us the flexibility to adapt to market conditions and any constraints in this growing industry environment. So I want to be clear, this purchase and our excitement about Cana has not altered our plans for the Delaware Basin. We are right on track, and you'll hear about some significant new results.

Innovation has resulted in Cimarex continuing to make great wells and see improvements in our completion techniques in the Delaware Basin as well. One thing we like in particular are the results we're achieving with long laterals. So much so, we're now moving our program to drill long laterals wherever possible. We've put a lot of energy into building a land position that allows for long laterals. And this year, in 2014, approximately 40% of our Wolfcamp wells will be drilled with long laterals.

Our acreage position in Culberson County, which we solidified by our joint development agreement with Chevron, provides the perfect platform for long laterals. Today, we announced our second long lateral in Culberson County, drilled to the Wolfcamp D target, the well was the Gallant Fox, completed using a 10,000-foot lateral and a 43-stage completion. Despite some initial pipeline constraints, that well had a 30-day average production rate of over 2,500 barrels of oil equivalent per day.

With long laterals in mind, we added to our acreage position. We added 45,000 net acres to our Wolfcamp play fairway in the first quarter, including 35,000 acres in Reeves County. Now some of that acreage was added through new leasing. Some of it is added through an expansion of our fairway. We had a couple of fairly significant wells that industry competitors drilled in Southern Lea County, and that allowed us to recognize additional acreage that went into our Wolfcamp fairway.

Our pilot program continues. We're flowing back our Wolfcamp C and D stacked lateral tests in Culberson County. And our completion of our 4-well 80-acre pilots in Culberson and Reeves are underway and on target. We'll share those results with you later in the year.

So with that, I'll turn the call over to John Lambuth to discuss details of our drilling program.

John A. Lambuth

Thanks, Tom. I'd like to quickly cover some of the highlights of our overall program before getting into the Permian region. I'll then finish with our Mid-Continent region and the results in Cana.

Cimarex drilled and completed 74 gross, 36 net wells during the quarter, investing $467 million. 67% of this investment was in the Permian region, with 29% of it in the Mid-Continent. Of those 36 net wells, 21 net wells were in the Permian region, where we continue to be focused on the Bone Spring, Avalon and Wolfcamp formations in the Delaware Basin.

Bone Spring activity in the first quarter included 13 net wells in New Mexico and Texas. Results continue to be good, generating some of the company's highest rate of returns, with oil volumes representing up to 84% of the first 30 days of production. Our Bone Spring program for 2014 is comprised of 56 net wells, which results in a total investment of $375 million. We continue to have about 200 to 300 Bone Spring locations identified on our acreage in New Mexico and in Culberson County, where we have identified a thick highly productive 2nd Bone Spring sand.

At the beginning of the year, we announced a new drilling program in the Avalon Shale in Lea County, New Mexico. Results to date have been very good. The 9 Avalon wells drilled-to-date have a 30-day average IP of 1,003 barrels of oil equivalent per day, with oil making up 77% of the production from these wells. We have an inventory of over 200 locations and plan to drill from 15 to 20 wells in 2014.

About half of our Permian drilling capital in 2014 or about $685 million will go toward further delineation of Cimarex's Wolfcamp opportunities in the Delaware Basin. This includes downspacing pilots and wells drilled to hold acreage. As Tom mentioned, we now have 225,000 net acres identified as prospective for the Wolfcamp Shale, up from the 180,000 net acres we discussed during our last call. This is the result of both acquisition of additional acreage and a slight redrawing of the Wolfcamp fairway outline due to recent well results. You can view our new fairway outline in our updated presentation materials.

We are currently producing from 6 distinct Wolfcamp zones across the 225,000 net acres we've defined as our Wolfcamp fairway. While they may have the same name, they have very different characteristics across the play. We define them as the Wolfcamp A, C and D zones in Culberson, the Wolfcamp A and B/C in Reeves and the Wolfcamp A in Ward County. We currently have wells producing from all of these Wolfcamp zones.

As Tom mentioned, one of the innovations of the first quarter was the proof of concept of long-lateral drilling in the Wolfcamp. We now have 9 long-laterals wells producing across our acreage and expect 40% of our 2014 Wolfcamp wells to be long laterals, which we defined as being longer than 5,000 feet. Over half of the Culberson County Wolfcamp wells will be long laterals, with 14 in the Wolfcamp D, one in the C, and one in the A, and another 13 long laterals are planned in the Wolfcamp A in Reeves and Ward Counties.

A couple of examples of the recent success we've had with long laterals includes a well we announced today and then one that Tom mentioned earlier, the Gallant Fox, which had a 30-day peak IP average of 2,516 barrels of oil equivalent per day. It is our second well in Culberson County to incorporate long-lateral drilling and upsized fracture stimulation. The 10,000-foot long Gallant Fox well was completed with 43 frac stages. Typical of a Wolfcamp D well, it has a product mix that is comprised of 646 barrels of oil, which is 26% of the production; 6.9 million cubic feet of gas a day, which equates to 45%; and 730 barrels of NGL per day, or 29%.

In Reeves County, we recently completed a well we call Thunder, which had a peak 30-day IP rate of 1,411 barrels of oil equivalent per day from the Wolfcamp A. This well was a 6,400-foot long lateral and was completed with 30 frac stages. This rate is 50% higher than our standard 5,000-foot lateral with a 12-stage completion. Like other Wolfcamp A wells in Reeves County, the Thunder was predominantly oil, which made up 50% of the production.

Lastly, in the Delaware Basin, I'd like to give you an update on the status of the 4 unique pilot programs we currently have underway. I'll refer you to our presentation for an illustration to the designs. Our first pilot to be drilled and completed is the stacked lateral test in Culberson County. These wells are testing the concept of producing from laterals stacked in Wolfcamp C and D. These 2 wells have been fracture stimulated and have just started the flowback on them. The 2 4-well 80-acre downspacing pilots, one in the Wolfcamp D in Culberson and the other in the Wolfcamp A in Reeves County, are both in various stages of completion. Once all 4 wells in the pilot are completed, the wells will be put on production and begin flowback. The fourth pilot is in the Wolfcamp A in Reeves and is considered both a stacked and staggered, as it will test the downspacing and the viability of landing more than one lateral in the thick Wolfcamp A section. We currently have 2 rigs drilling this 6-well pilot. As scheduled today, all the wells and all of the pilots should be on production sometime in the third quarter.

Now onto the Mid-Continent, where we have perhaps our most exciting news for this quarter. We are pleased to report that our efforts to bring the upsized completion to our development in Cana has been highly successful. To illustrate, I'd like to direct you to Slide 18 in our latest corporate update posted on our website. This graph compares the traditional Cana infield completion with our aptly named Golden Section, the first section completed using an upsized frac. Results are strikingly similar to those we've experienced when we upsized the frac in Culberson County. This upsized frac had a positive impact on the initial production, the recoverable reserves and, most importantly, on the returns. Investing an additional $700,000 increases our before-tax internal rate of return from 38% to 86%. And our NPV10 more than doubles from $5.5 million to $14 million.

At Cimarex, we like having options. And based on our results so far, these wells most definitely compete with our returns in the Permian, giving us more places to invest capital for good returns. We have 2 more operated sections on the schedule to be completed in 2014, and we look forward to reviewing our future plans as we get further confirmation of upsized frac results in Cana.

With that, I'll turn the call over to Joe Albi.

Joseph R. Albi

Thank you, John, and thank you, all, for joining our call today. I'll touch on the usual topics. Our -- first, our first quarter of '14 production. I'll discuss the remainder of the year from a production outlook standpoint and follow up with a brief discussion on our operating and service costs.

We truly had a great Q1, reporting average net daily equivalent production of 740 million cubic -- equivalent cubic feet a day, a record for the company and 30 million a day above the upper end of our Q1 guidance which was 696 million to 710 million. Both Cana and the Permian played a role in us exceeding our guidance, with Cana being the real driver.

The step-change in performance that we've seen using upsized fracs in our new Cana completions played the biggest role on our production beat, while we also saw some nice increases in our Cana-based property production as a result of a number of well-bore cleanouts and remediation projects that our production team performed during the quarter. The bottom line is, Cana just simply well exceeded our plan expectations.

In the Permian, our new well forecast held very tight to plan, while our Triple Crown pipeline turnaround project went about as smooth as it can go and, therefore, resulted in less downtime on the system than we had expected. And it also played a role in helping us to exceed our guidance.

With a nice jump in our Q1 production, we were up 5% from our Q4 '13 average of 705 million a day and 12% over our Q1 '13 output of 661 million a day. Driven by Cana, Q1 ended up being a quarter of records for us in the Mid-Continent, where we set regional records for all product categories: gas, oil, NGL, total liquids and equivalent production. Our Q1 Mid-Continent equivalent volume of 371 million a day was up 28 million a day or 8% over where we were in the fourth quarter and 11 million a day or 3% from the levels we saw a year ago.

With the nice quarterly gains in Cana, our Q1 Cana volume of 255 million a day was up 30 million a day or 13% from the fourth quarter, and it actually set a new record for us once again in the play. And with that level of production, Cana continues to play a vital role in our overall program. It now makes up 69% of our total Mid-Continent production and more than 1/3 of our total company volumes.

In the Permian, we continued to see nice production growth during the quarter as well, with our Permian Q1 net equivalent volume of 347 million a day, up 4% or 15 million a day from Q4 '13, and up a very respectable 26% from the 275 million a day we averaged during Q1 '13. Oil continued to provide the growth for us in the Permian with our Q1 Permian oil production of 31,624 barrels per day, up 7% sequentially from Q4 and 22% from 1 year ago.

During the quarter, we completed 22 net wells in the Permian. That well count was constrained a bit by our Wolfcamp spacing projects that John mentioned, which are projected to come on in the late Q2, early Q3 timeframe. And as a result, our net completions in the Permian are currently modeled to accelerate from 22 in Q1 to levels of 35 to 45 completions per quarter as we end out the year. With this pickup in completion activity, our modeling is showing that our Permian production growth should accelerate beginning here in the Q2, Q3 timeframe.

Looking forward into our guidance. With our continued successes in Cana and in the Permian, our updated model is now projected -- is projecting a full year 2014 guidance range of 822 million to 847 million a day. That's up significantly from our beginning year range of 760 million to 800 million a day, and it reflects a very healthy 19% to 22% growth in our production over 2013.

I want to make special note here that this range does not include any volumes from our recently announced Cana-Woodford acquisition, and that acquisition will add about 35 million a day to our books and on top of these numbers upon our anticipated closing, which is slated for June 30. And obviously, following closing, we'll include these new volumes in any future guidance updates that we provide to you.

As might be expected from the tone of this call, the increase in guidance from 760 million to 800 million now up to 822 million to 840 million (sic) [ 847 million ] is nearly all driven and attributable to what we're seeing in Cana. As John mentioned, we've seen a solid step-change uplift in well performance, pumping larger fracs. In addition, our production group has done a great job of increasing production from our Cana-based properties by identifying underperforming wells and performing a variety of cleanout and wellbore remediation projects. That work really kicked off in late February and March, and we didn't see a full quarter's worth of that work. But the work that we did perform equated to approximately 6 million to 8 million a day to our Q1 Cana production volumes, and we expect that to increase as we close out the year. In a nutshell, both our exploration and operations teams are virtually hitting on all cylinders to boost production coming out of Cana.

We also continued to see strong results from the Permian. With the number of Permian completions projected to accelerate in Q2 and Q3, our current model projects that Permian oil will jump from our Q1 levels of 31,625 barrels per day to well over 40,000 barrels of oil per day for an average in Q4, quite a jump with more than 60% of our fourth quarter projected oil coming from the wells that we drilled this year. So that gives you an idea of the impact that our new wells will be having on our oil production.

So with our successes in Cana and our projected acceleration in the Permian, we've got just a wonderful springboard as we jump into Q2 here. And it's reflected on our Q2 guidance, which is projected at 810 million to 830 million a day, and that's a projected increase of 9% to 12% over just the first quarter. So as our volumes continue to grow, things we worry about, product takeaway remains high on our priority list. In that regard, Culberson -- in Culberson County, we're working alongside Chevron to evaluate proposals currently on the table for a third-party construction and operation of an oil-gathering system in our Triple Crown project.

In all areas of the Permian, we're expanding the number of purchasers and haulers that we use to truck our oil out of the basin. As a result, we've recently added 3 new purchasers and are evaluating additional proposals from a handful of others. And although we feel the pressures of increasing oil supply coming out of the basin, as I'm sure all of our peers in the basin are also feeling, we continue to be successful, lighting up our production with sales all the while that we've been able to add new purchasers. In general, the pricing term for receiving reflect the WTI Midland-based pricing. And when we do see some gravity adjustments, we do find them to still be in the modest range.

We're also working diligently on the gas takeaway and processing side in all the core areas of our activity. As an example, I'll use Triple Crown. Along that Triple Crown pipeline infrastructure, we now have 6 available markets for gas takeaway and processing as compared to just one option that we had years ago when we started in the area. Our marketing and midstream groups are doing a great job to work side by side with our exploration and production teams to ensure that we're building out infrastructure as far ahead of our activity as we can, and ultimately providing for takeaway.

Shifting gears to OpEx. Our Q1 lifting cost came in at $1.13 per Mcfe. That was at the low end of our full year guidance range of $1.12 to $1.22 and right in line with our 2013 average of $1.13 per Mcfe. Although we saw some cost pressure during the quarter in items such as chemicals, compression, power and fuel, our per-unit operating expenses benefited from our stronger production, obviously. And as a result, we've brought down the top end of our production expense range for full year to $1.18, putting our revised guidance for lifting cost for this year at $1.12 to $1.18.

A few words on service costs. We continue to see most costs on the drilling side to stay relatively in check, including our day rates, which, for 1,500-horsepower top drives, have been holding in the $22,000 to $25,000 a day range for multiple quarters now. That said, top drives do seem to be in short supply. And with that, we are seeing that the number of new builds seem to be going up. But with service costs flat, our drilling team is continuing to focus and is successful on doing what they can to reduce our cost through operating efficiencies, and we continue to see that in most all of our programs.

On the completion side, we've seen some modest cost pressure from a tightening market for equipment. But most of the cost pressure has come on the transportation side, particularly in the transportation of prop when we're pumping these bigger jobs. That said, any real significant cost increases that we've seen on the completion side have come directly associated with us pumping bigger jobs, more stages, more fluid, more prop. And as a result, the completion component of our AFEs can now make up more than 60% of our total well cost in programs like Cana in the Mid-Continent, and in the Avalon, Bone Spring and Wolfcamp in the Permian. Our recent well results, however, are telling us that the incremental benefits are certainly well worth the additional cost.

From a total well cost standpoint, incorporating the upsized frac into our new Cana well design puts our current Cana core AFE at the $6.9 million to $7.2 million level. That's up from the $6.3 million to $6.5 million level we saw early in Q1. With the smaller fracs -- on the smaller fracs in Q1, the increase that we've seen has been entirely attributable to the upsized fracs. And as a good example of this, we've made just tremendous strides on the drilling side in Cana over the last 6 to 9 months. And it's very well evidenced by the fact that our current AFE, including the large frac, is running about where we were all-in for the small frac in Q3 '13.

In the Permian, AFEs for a 4,500-foot lateral, 2nd and 3rd New Mexico Bone Spring wells continue to run in the range of $5.7 million to $6.5 million, depending on depth. That's flat from last quarter and down about $400,000 to $500,000 from where we were a year ago. In our shallower Texas 2nd Bone Spring program, our AFEs are still in the $5.1 million to $5.5 million range. We've bumped the upper end of that range from last call by pumping a little bit larger-sized frac, but that's still down about $0.5 million from where we were a year ago. And our current Avalon wells are running in the $7.2 million to $7.5 million range, incorporating the larger frac.

As we continue to experiment with upsized fracs in our Wolfcamp program, our current AFEs for a 4,500-foot lateral are in the $8.5 million to $9 million range, that's depending on the geographic area and the size of the frac, while our 2-mile Wolfcamp laterals, our AFE are in the $13 million to $14.5 million range, again depending on the size of the frac.

So in closing, we're off to a great start here in 2014. Q1 production came in very, very strong, and it gave us a wonderful springboard into Q2. And with that, we've raised our full year outlook for production. We're keeping our LOE and our service costs in check, and we're making very good progress finding ways to optimize production from the wells that we've drilled.

And with that, I'll go ahead and turn the call over to Q&A.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question is Matt Portillo from Tudor, Pickering.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just one quick question on the Cana. Obviously, the returns you guys have highlighted here are quite impressive. I was curious if you could provide a little bit more color in terms of how you're thinking about the asset from an acceleration perspective as you move into kind of 2015 and, in particular, with regards to the recent acquisition?

Thomas E. Jorden

Yes, Matt, this is Tom. We are looking at acceleration in Cana. We're, of course, kind of in the midst of a lot of moving parts here with just announcing this transaction. We're in the due diligence phase, getting ready for the June closing. We are looking at a potential acceleration that would have additional infill drilling, really would be a 2015 issue. We might get started later this year. But obviously, we have other companies to coordinate with. Cana is a multi-company arena, and no one company can just do things in isolation. So we're looking at some plans, we're lining it up and we'll get back to you when get a little more detail on it.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a second question, kind of a bigger-picture question in terms of, I guess, both the Cana and Permian. Given the resource base that continues to expand here, I was wondering if you could maybe provide a little bit of context of how you guys think about kind of your drilling program and how it will progress over the next year or 2 in terms of the size and scale that this may move to from kind of your current position.

Thomas E. Jorden

Well -- again, this is Tom. We see -- given commodity windage, we see an accelerating drilling program. And the beauty of what we've announced today is we think we have an equal opportunity to accelerate in the Mid-Continent, in the Permian and/or both. Now one of the things that we're concerned about, the industry is concerned about, is some of the pressures of so many Permian companies accelerating simultaneously. That leads to pressures in rigs, pressures in stimulation and other services, pressures in oil and gas takeaway and pressures in manpower. So one of the things that this allows us to do, to the extent we look at accelerating, we have a little built-in relief valve without sacrificing our return on invested capital. I mean, this is exactly the strategy Cimarex is built around. So yes, we'll -- we will accelerate. And the way we're thinking about it is we have the flexibility that we've always cherished that optimize both our returns but also our ability to execute efficiently.

Operator

Our next question is Brian Gamble, Simmons & Company.

Brian D. Gamble - Simmons & Company International, Research Division

On the long-lateral wells, we've talked about a couple of them. You said you had 9 producing now. Any others to note anything of, or is that something the -- for later in the future?

John A. Lambuth

This is John Lambuth. Well, obviously, we don't talk about every long lateral that we drill. We just try to point out significant ones, which is why the Gallant Fox was talked about because it was a very nice confirmation of what we were able to achieve with the previously announced Montrose well. And likewise, the Thunder we talked about because besides being a long lateral, it also incorporated a bigger upsized frac. That really -- those 2 components are kind of the go-forward components in all 3 of those areas, for Culberson, Reeves and Ward. And certainly, as we get further long lateral results and, let's say, others zones that we haven't talked about, we'll certainly add more color and comments to that once we have those wells to talk about.

Brian D. Gamble - Simmons & Company International, Research Division

And on that same-well results side, the -- I'm sorry, go ahead.

Thomas E. Jorden

I was going to say, obviously, we're very encouraged that the program is moving in that direction. We don't know that every well we drill is going to be representative of the 3 10,000-foot laterals we have announced. But so far, so good.

John A. Lambuth

Yes.

Brian D. Gamble - Simmons & Company International, Research Division

And the 30-day IP rate, one of your slides, the Eddy, Lea County number moved up significantly during the quarter. Is that all upsized frac, or were you doing anything else there during the quarter versus last quarter? I think it moved up from 665 to 966...

John A. Lambuth

Can you tell us what particular page are you referring to so we'd look at it?

Brian D. Gamble - Simmons & Company International, Research Division

Sure, of course. On slide -- let's see, on Slide 8. You mentioned the 2nd and 3rd Bone in Eddy and Lea, your 30-day rate for this quarter versus last quarter, 966 versus, I think, last quarter was 665. Is that all frac stuff?

John A. Lambuth

Yes, it is. In the Bone Spring, we haven't talked a lot about that. But we have definitely, in the Bone Spring, gone in and made adjustments to our frac design there as well. And we're seeing some nice results by doing that, especially in the White City Culberson area, and so we're moving to that frac design in that area. And going forward, that's what we'll use. But -- plus, we're still tinkering with it. We still think we can even get better results. So we're very encouraged so far from what we're seeing out of that area.

Brian D. Gamble - Simmons & Company International, Research Division

And then one more, if I may. The gravity adjustment that you mentioned were modest thus far. Are you intending to just continue to lock in modest adjustments in some of these new purchasing agreements or eliminate those adjustments moving forward? How do we think about any sort of deducts that may be involved in new deals or even better pricing that may be involved in new deals?

Joseph R. Albi

This is Joe. The current deducts that we're seeing are like $0.30 to $0.40 per degree gravity, and they're over different API numbers, depending on the contract. Getting long-term contracts with these guys, with our purchasers, is not as easy as, I guess, we had hoped to have it be, because I think they are concerned about the same things we are. That said, what I will tell you about our ability to get new purchasers into the game down there, we've been very successful. We've added 3 additional purchasers and all of them seem very comfortable in taking any of the gravities that we're giving them.

Operator

Our next question is Jason Smith, Bank of America Merrill Lynch.

Jason Smith - BofA Merrill Lynch, Research Division

I just want to follow up on Brian's question on crude oil pricing again. Is that gravity issue, is that more just focused in the Wolfcamp C and D, and as you guys kind of the move up to the A, it's less of an issue?

Joseph R. Albi

Yes. This is Joe again. The only areas we're really seeing any kind of adjustment in the Permian are in the Wolfcamp, and so in the Culberson area, as well as in the Reeves. The Wolfcamp, the Culberson is little bit higher gravity. It's like 54 to 58 degree. And when you get over there into Reeves, it's 46 to 52. We've got -- let's see, we've got 3 specific purchasers that I'll speak of in Culberson. And we're seeing the deducts in one case over 45 degrees, and then the other one will take crude over 50, but it's just a little bit higher fee. So their fee jumps up about $1.50. So I don't know about...

Jason Smith - BofA Merrill Lynch, Research Division

But all the zones you're seeing -- I mean, I know you haven't done much in the Wolfcamp A over there. But you're seeing the Wolfcamp A in the high -- in the mid-50s as well?

Thomas E. Jorden

We -- this is Tom. We do see a little lower API number in the A than we do the D and the C. But it's still what you would call light. It's in the 50s. So really, the variation we're seeing that's significant is more regional than it is stratigraphic. We'll get a little lower API number in Ward County than we will in Culberson County, and Reeves is kind of intermediate.

Jason Smith - BofA Merrill Lynch, Research Division

Got it. And then in Reeves and Ward, the acreage you guys tacked on, can you just maybe give us some color on what you paid for that?

John A. Lambuth

Yes, this is John Lambuth. We added approximately, as Tom said, the 35,000 acres. And the cost for that was right around in the $2,300, $2,400-an-acre range for that additional...

Thomas E. Jorden

This was a leasing effort. It wasn't one fell swoop. This was dozens and dozens of incremental deals.

John A. Lambuth

I mean, we saw an opportunity from our -- in our explorations where we felt like we could expand the play and get more acreage, and we were able to execute upon it and add that acreage. So we're very pleased with that additional acreage position we've added to it.

Operator

Our next question is Joe Allman, JPMorgan.

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

Tom, for that Cana acquisition, why flip half of it and not keep the whole thing?

Thomas E. Jorden

Well, there's lots of answers to that. Would we have been happy to keep it? Yes, yes, we would. That said, Cimarex and Devon had a long-standing cooperation out there, and we typically offer assets like this to one another. So that was part of the thinking. We also are the biggest working interest owners out there. And so both companies, I think, having a willingness to reawaken the drilling program in Cana is important to both of us. So I will say this, I was more concerned about just the willingness to invest and go forward than I was the $250 million or $500 million. We do look at our debt, and this is incremental to our debt. We have lots of inventory, and it was not a -- it wasn't a tough call for us. We're happy to offer half of it. Joe, Cana is -- just I can't underscore how pleased we are with our recent results. We're encouraged that it will translate over the widespread field, and we're going to have a long road ahead of us of just top tier returns out of Cana. The executive team, we're here in Tulsa today and we're having an annual conference with all of our technical people from around the company. And I walked up this morning and came in the middle of an argument that 2 of our junior engineers were having, one was a Permian engineer and one was a Cana engineer, and they were debating whose programs generates higher rate of return. And that's a debate that we love and greatly encourage here at Cimarex. And so we've got plenty to do here. And you know what? Yes, could we have taken all of it? You bet, but we're real pleased with the decision we made.

Operator

Our next question is Drew Venker of Morgan Stanley.

Andrew Venker - Morgan Stanley, Research Division

Just thinking ahead to the 2015 program, you talked about potentially accelerating in Cana. Are there any gas processing or pipeline takeaway concerns in Cana? And I guess, how many -- how much running room do you have before things become tight there?

Joseph R. Albi

Yes, this is Joe. We've taken a good, hard close look at our production wedge and the marketing arrangements that we currently have. And with our current takeaway options, we feel very comfortable getting through the remainder of this year without any processing or compression issues with our primary purchaser. We also have 3 other markets that we're pursuing now as we look forward into 2015 to try and understand our wedge there. We really -- with the '15 program, if we were to accelerate, it'd be row [ph] drilling. We'd start that in the fall, and that completion activity probably wouldn't really start to hit the books until second quarter of next year. And that would be the time that we hope to have these other potential arrangements locked up. So I guess a high-level answer is we've got plenty of breathing room that we see right now in the short term, medium term, and we're worrying about our long-term ability to get out of there.

Thomas E. Jorden

Yes. And, Drew, it's Tom. the -- like anything we do, we have to look pretty far ahead and make sure that the infrastructure's ready, the market's ready, the rigs are there. And so as Joe said, we're in the process of doing that. The nice thing about where we sit right now is Permian and Cana kind of complement one another and play off one another. So any activity that's limited in one can be taken up by the other. So we're intending to accelerate in Cana, but we've got plenty to do in both basins. So we're-- we feel like we've -- today, are announcing a very significant safety valve for Cimarex in terms of our future growth profile.

Andrew Venker - Morgan Stanley, Research Division

And then just to follow up to that. Do you feel like these new Cana completions can be applied across your position, or is there anything that would keep you from being able to use the new completions across-the-board there?

John A. Lambuth

Yes, this is John Lambuth. That's a great question. That's exactly what we're attempting -- or are doing right now with our current rigs. We are both completing some additional new infill sections, which are geographically separate from the Golden Section. So that'll be a nice checkmark to show that we can get similar-type returns. And then likewise, we are out there drilling some initial parent wells or first wells in the section in areas where we're trying to reestablish what is the type of production we should expect using this new frac style. So there's a lot of delineation in a sense. It's hard to imagine me using that word. But in some sense, that is there, that we're trying to kind of recalibrate ourselves as to what type of production profile we should expect with this new fracture stimulation. And then let me also say we haven't really honed on -- honed in to actually exactly what is the best frac job. Even within the Golden Section. We changed it up some -- among a number of the wells there. And we are still experimenting some that we think we could perhaps even -- can do even better than what we have right now. So there's definitely some additional drilling and testing we need to do to just gain further confidence to how applicable this could be across the broad Cana area.

Andrew Venker - Morgan Stanley, Research Division

Is there any conservatism baked into your Cana production forecast, just given how much production history you have on these new completions?

Thomas E. Jorden

That's a very...

Joseph R. Albi

In all of our modeling, we're modeling what we book and -- as a starting point, and that's with our base properties. And those are based on current well productions levels and current well declines. And as we start to see better and better well results, the -- I guess the type curves of the wells that you're drilling are going to be integrated into those future wells that you drill. And those are the wells that we model off of. As far as guidance is concerned, our beginning year guidance did not incorporate the impact that these upsized fracs had because we kind of wanted to wait to see if it happened first before we go ahead and do that. And obviously, now that we've upped the ante on our Cana production for this year, we're sending the signal to the market that we're fairly confident that what we're doing is working and it's showing up in Cana. So as we continue to see results, we build those results into not only our future investment decisions, but also to what we forecast that we'll produce in our cash flow models.

Thomas E. Jorden

Yes. Drew, we always estimate what we think is realistic. And is there conservatism? I mean, there's always is. And life in the oil patch can be a very humbling experience. Things tend to go wrong. So we always build in a fair amount of tolerance for either timing delays or operational issues. But yes, it is what we think we'll achieve.

Operator

Our next question is Cameron Horwitz, U.S. Capital Advisors.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

On your Delaware Wolfcamp map, can't help but notice more dots there to the east and in Ward County. Maybe a little bit early, but I was hoping if you could potentially give us a little bit of color as to how you're thinking about kind of the opportunity set over there, the relative productivity and the oil cuts on -- in the Wolfcamp over there to the east?

John A. Lambuth

Yes. This is John Lambuth. The word you used is very appropriate. It is early. A lot of those dots you see are in their flowback, and we haven't really achieved peak 30-day averages for us to talk much about them. It is definitely oilier as you get into Ward from Reeves. That trend continues into there. But we are still very early there in Ward and just trying to get a good understanding of the type of the well we're going to have there. I would hope, certainly, by next conference call, we'll have a lot more to say about our Ward County program.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Okay. And then just in terms of modeling for the rest of the year. With the Cana acquisition, how do we think about the average working interest there in Cana at the current pace once that acquisition closes?

Joseph R. Albi

This is Joe. I'll just rattle off some of the stats, working interest-wise, that pertain to our share of the QEP sale. There were 793 properties that were in the proved category. They operated about 243 of those. We'll own an average working interest in all those wells of about 14.5% working. That is where that 35 million a day level that we've quoted in our call comes from. That production mix is about 64% gas, 28% NGLs and about 8% oil. About half those properties are in the Woodford. In the Cana area, they comprise probably 90% of the value, and our working interest in those properties is at the 9.5% level. The remainder of the properties are older vertical wells that obviously don't carry as much value as the Woodford section, and make up the balance of the deal. So hopefully, that helps kind of give you a high-level snapshot of what you're looking for.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

That's helpful. And then just lastly, any evolution in terms of your view on the stacked concept? I think you alluded to a well that I think you had flowing back. Just curious if your view has changed at all from last quarter. I know obviously early there as well.

Thomas E. Jorden

Well, we're currently flowing our first Merrimack well back. And we don't have 30 days production, so we'll defer that to our next call. But we definitely recognize the potential. We follow the play carefully. As I've mentioned before, we've taken our own core. We're in the process of analyzing it. And so I would anticipate that we'll have other drilling to do, and probably 1 or 2 wells to discuss on our next call.

Operator

Our next question is John Nelson, Citigroup.

John C. Nelson - Citigroup Inc, Research Division

I wanted to build on Drew's question in a little more detailed fashion, if I could, thinking back to our discussions on why 2013 production was able to beat -- I think you guys attribute it to haircutting -- the new Wolfcamp completion design as you sort of factored that into guidance. I guess is there any reason to believe that you wouldn't be following a similar practice with the new Cana completion design, or have you maybe learned a bit from 2013 and we're more in the gray area? If you could provide any color there.

Joseph R. Albi

This is Joe, again. I -- we don't set off and say, "Hey, here's this forecast. Let's haircut it." If we don't have a lot of wells under our belt, and we're really not certain if it's just a geographical thing or something's working versus something else, we may look at it unrisked and risked and risk certain areas other than others. So it's a very dynamic thing that I would hope that quarter-to-quarter, and I think we've demonstrated in the past, we're pretty darn tight on our guidance. And in this quarter, it was, in my mind, an exception for just a couple of extraordinary reasons. We didn't know what was going to happen in Cana. And so now that we've got a little bit of this under our belt, we're going to incorporate that into our future guidance as if it -- we think it's going to happen. And so I really just want to underscore that. We don't start off and say, "Hey, let's just kind of really watch this thing and not put the right numbers out there." We got a budget and cash flow model and everything else here, too. We want to be as accurate as we can.

Thomas E. Jorden

But -- yes, I'll follow that. Joe is absolutely right. To the extent that we have meaningful data in these upsized completions, we only have a long flowback period over a fairly restricted area of the core. Now we do have a couple of outlying experiments that we're watching and we're encouraged, but we don't have the calibration that we do in the core. That's the thickest, highest gas-in-place part of the field. So we have modeled an uplift over the entire area. But until we get some calibration, we've left ourselves some room, as we need to. So we don't think we're being overly conservative in anything we're forecasting.

John C. Nelson - Citigroup Inc, Research Division

That's really good color, and I can appreciate, I guess, not conservatism, but not being aggressive, I guess is the way I'll put it. And then if you could just remind me what -- timing-wise with regards to Cana completions throughout the rest of the year. I think the presentation notes 2 rigs, but can we just -- should it be pretty steady, the flow of completions over the course of the year?

John A. Lambuth

Yes. This is John. We are currently actually completing our next operating section, as we speak. We have 2 sections to complete. But I would also point out that the other company in Cana has quite a bit of completions ongoing through the rest of the year that we have a pretty good interest in as well. So I would say a good rest of the year.

Mark Burford

John, this is Mark. Actually, we had 14 net completions in Cana, roughly, in the first quarter. Second quarter, we should have about 11 net completions, so fairly similar rate. Similar into the third quarter, with about 14 net completions. But it really tapers in the fourth quarter.

John A. Lambuth

In the fourth quarter, yes. The fourth quarter is where it tapers off. And that's where -- again, we have to get this closing done, but that's where we look at -- once we start ramping up, where do we do that. Although more than likely, no matter what we do, we really won't get those wells online until probably sometime first, second quarter '15. So there will be a slowdown some in the fourth quarter, but of course, we've incorporated that in our guidance.

Joseph R. Albi

This is Joe. From a high-level standpoint, all these -- how all this is playing out underneath the hood, you're -- what we're seeing is fairly consistent quarter to corner -- quarter-to-quarter -- I can't say that word apparently -- Cana completion count through Q3. It tapers off in Q4 right about the same time we're starting to see the acceleration in the Permian. So where the Permian is accelerating, Cana is kind of rolling off, and the bottom line is what it is.

John C. Nelson - Citigroup Inc, Research Division

That's really, really helpful. And then just one last one, if I could sneak it in. It looks like you widened sort of the Wolfcamp map, specifically that acreage, and sort of Central to South Central Reeves. Are you chasing similar targets to what you have and sort of more north of that acreage, or just stay tuned or any color around that?

John A. Lambuth

Yes. This is John Lambuth. And that is the area that we went out and pursued and was able to acquire that additional acreage. And...

Thomas E. Jorden

Southern Reeves.

John A. Lambuth

Southern Reeves, as you highlighted. And that is an area that we'll be targeting our first well in later this quarter, early next quarter. But we see it as being very similar to the same section we're drilling in Northern Reeves, in terms of Wolfcamp A, as well as B/C, as potential targets down there.

Thomas E. Jorden

And if you were to go back historically, you'd see some of our early trend maps included a lot of Lea County acreage. We skinnied it up, just because we weren't sure what it would do up there. There was 1 or 2 industry wells there in the southwest corner of Lea County that were very, very nice Wolfcamp wells, and fully made us realize that, that acreage we have in the southwest corner of Lea County is absolutely going to be Wolfcamp prospective.

Operator

Our next question is Michael Hall, Heikkinen Energy Advisors.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Quite a bit have been answered. I guess couple left of mine would be -- just curious, to what extent is Devon also employing these sorts of upsized fracs and how much are you guys sharing, I guess, information on technology and whatnot?

John A. Lambuth

Yes. This is John Lambuth. Devon is applying the similar-type frac design as we are doing as well. They have interest in our wells. We have interest in their wells. So we clearly learn from each other. So they have quite a few sections now under their belt with a similar frac style and, again, quite a bit of experimentation within there, too. We're still trying to hone in on what works best. Early data on that is encouraging so far, but it's very early. But they are, themselves, also trying to apply the same frac style.

Michael A. Hall - Heikkinen Energy Advisors, LLC

Okay. And I'm assuming -- it sounds like you guys are thinking about some acceleration. Have you been in contact with Devon around that as well for the new properties or what's the -- any commentary there?

Thomas E. Jorden

It's too early to really get too granular on that. We're just kind of talking about it at this point.

John A. Lambuth

Got to close.

Michael A. Hall - Heikkinen Energy Advisors, LLC

That's fair. Okay. And I just want to make sure I heard you right in terms of the ramp in Permian oil production, the prepared remarks there. In the fourth quarter, was that to over 40,000 barrels as a net number in the fourth quarter on average?

John A. Lambuth

That's correct. That's a net number for our Q4 average that we hope to exceed that number.

Operator

Our next question is Jeb Bachmann, Howard Weil.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Just had a question on these upsized fracs and looking at recovery factor. Is -- are you expecting these upsized fracs to essentially accelerate the recovery of the reserves, or do you also think you're going to get an increase in that recovery factor as well?

John A. Lambuth

Well, I'll take a stab at it first. I'm sure Tom will want to as well. It looks as though we are, I would say, getting a higher recovery factor for the same gas-in-place section, that's what's occurring. So I would not call it acceleration as much as we're more effectively connecting to the rock and draining that resource. That's what we think is happening.

Thomas E. Jorden

But to the extent we're getting higher recovery and higher rate, getting -- we're getting more gas out faster, so.

John A. Lambuth

Yes, yes. It's coming out faster. But we are not -- I would say, in terms of acceleration, we're not really competing with other wells. We are effectively just getting better connected to that total resource that's there in place. That's what we feel is happening.

Joseph Bachmann - Howard Weil Incorporated, Research Division

And going forward, do you guys get a sense of when you're going to be able to come out and talk about maybe increased EURs associated with this new design, or how long -- how much longer -- or how much history, I guess, do you need to establish before that?

John A. Lambuth

Yes, I don't know. It's just too early right now for us to think about when we might publish some type of EUR on that. I mean, again, what we showed you today was an early idea of the flowback data, what it looks like. You can judge for yourself the type of wells we're making there, based on that graph.

Joseph Bachmann - Howard Weil Incorporated, Research Division

Okay. And last one for me. Do you guys have a resource-in-place estimate for Reeves County, for the Wolfcamp in Reeves at this point, or it's still too early for that?

John A. Lambuth

This is John. We internally have a resource-in-place map, but I'm not really going to talk about it. Reeves County is a very competitive area. We're still actively trying to lease. So that's not something that I really want to talk publicly about.

Operator

Our next question is Nicholas Pope, Cowen and Company.

Nicholas P. Pope - Cowen and Company, LLC, Research Division

I wanted to get a little bit of granularity on the Cana wells and the upsized fracs. I want to -- I did want to clarify that -- are -- what you all -- the data that's shown, is that just a upsized frac with the same lateral length as what you all previously had been doing in the region?

John A. Lambuth

Yes. This is John. It is the exact same equivalent of a 5,000-foot lateral. And what you're seeing within that graph is an average of the well results from that section.

Nicholas P. Pope - Cowen and Company, LLC, Research Division

Got it. And do you all have just a rule of thumb? It looks like a 2-stream volume that you provided. As you all report on 3 stream, do you know what the uplift is in the Cana from the wet gas to a 3-stream profile, just volumetrically?

Mark Burford

Yes, Nick. It's approximately 20% uplift going from 2 to 3 stream.

Nicholas P. Pope - Cowen and Company, LLC, Research Division

Got it. And how many wells were included in that, in the new infills?

John A. Lambuth

Yes. That was an average of 8 wells.

Joseph R. Albi

On the graph.

John A. Lambuth

On the graph.

Thomas E. Jorden

We have completed a whole series of wells.

John A. Lambuth

Yes. But for that particular graph, that's 8 wells.

Operator

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

Mark Burford

Thank you, everyone, for joining. We appreciate the -- taking time to stay with us and going over our results. And then we look forward reporting to you in the future quarters.

Thank you very much. Bye-bye.

Operator

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

Copyright policy: All transcripts on this site are the copyright of Seeking Alpha. However, we view them as an important resource for bloggers and journalists, and are excited to contribute to the democratization of financial information on the Internet. (Until now investors have had to pay thousands of dollars in subscription fees for transcripts.) So our reproduction policy is as follows: You may quote up to 400 words of any transcript on the condition that you attribute the transcript to Seeking Alpha and either link to the original transcript or to www.SeekingAlpha.com. All other use is prohibited.

THE INFORMATION CONTAINED HERE IS A TEXTUAL REPRESENTATION OF THE APPLICABLE COMPANY'S CONFERENCE CALL, CONFERENCE PRESENTATION OR OTHER AUDIO PRESENTATION, AND WHILE EFFORTS ARE MADE TO PROVIDE AN ACCURATE TRANSCRIPTION, THERE MAY BE MATERIAL ERRORS, OMISSIONS, OR INACCURACIES IN THE REPORTING OF THE SUBSTANCE OF THE AUDIO PRESENTATIONS. IN NO WAY DOES SEEKING ALPHA ASSUME ANY RESPONSIBILITY FOR ANY INVESTMENT OR OTHER DECISIONS MADE BASED UPON THE INFORMATION PROVIDED ON THIS WEB SITE OR IN ANY TRANSCRIPT. USERS ARE ADVISED TO REVIEW THE APPLICABLE COMPANY'S AUDIO PRESENTATION ITSELF AND THE APPLICABLE COMPANY'S SEC FILINGS BEFORE MAKING ANY INVESTMENT OR OTHER DECISIONS.

If you have any additional questions about our online transcripts, please contact us at: transcripts@seekingalpha.com. Thank you!

Source: Cimarex Energy's (XEC) CEO Thomas Jorden on Q1 2014 Results - Earnings Call Transcript
This Transcript
All Transcripts