Cimarex Energy Management Discusses Q4 2012 Results - Earnings Call Transcript

| About: Cimarex Energy (XEC)

Cimarex Energy (NYSE:XEC)

Q4 2012 Earnings Call

February 19, 2013 1:00 pm ET


Mark Burford - Director of Capital Markets

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

John Lambuth - Vice President of Exploration

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

Paul Korus - Chief Financial Officer and Senior Vice President


Phillip Jungwirth - BMO Capital Markets U.S.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Jeffrey W. Robertson - Barclays Capital, Research Division

Joseph Patrick Magner - Macquarie Research

Ryan Todd - Deutsche Bank AG, Research Division


Good afternoon. My name is Kayla, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Energy Fourth Quarter Results Conference Call. [Operator Instructions] Mr. Mark Burford, you may begin your conference.

Mark Burford

Thank you, Kayla. Welcome, everyone, and thanks for joining us today for our fourth quarter conference call. In Denver, we have Tom Jorden, President, CEO; Joe Albi, EVP and COO; Paul Korus, Senior Vice President and CFO; John Lambuth, VP of Exploration; and Jim Shonsey, our Vice President and Controller.

We issued our financial and operating results in the news release this morning, a copy of which can be found in our website. I need to remind you that today's presentation will contain forward-looking statements. However, a number of factors could cause actual results to differ materially from what we discuss, and you should read our risk disclosures on forward-looking statements in our latest 10-K, other filings and press releases for the risk factors associated with our business.

We have also posted a copy of the year-end investor presentation on our website, which we'll also be referring to, from time-to-time, on today's call.

So with that, we'll go ahead and jump into the call, I'll turn it over to Tom Jorden.

Thomas E. Jorden

Thanks, Mark, and welcome, everyone. It's a pleasure to be releasing our fourth quarter and full-year results this morning. We had a very nice year in 2012, and I really want to give credit to our organization across the board, for executing and performing on target with the plan we laid out this time a year ago. We had some headwinds to overcome, as those of you that follow us, in the past years. Very pleased that the underlying growth of our asset base is showing, and that Cimarex is on firm footing today and -- as we march through an uncertain future, so we've never felt better about the position of the company.

I'm going to be walking you through our results and will be referring to the slides that are posted on our website. I'll start with Slide 4, and will just be letting you know when I move a slide.

So to start, we had a solid fourth quarter, reporting record production for the quarter of 677 million cubic feet equivalent per day, and that was 13% greater than our Q4 2011. It's a very nice growth. We grew fourth quarter oil 28%, to another record, 35,099 barrels per day. Very, very nice oil growth.

Our full-year 2012 production averaged 625 -- excuse me, 626.5 million cubic feet equivalent a day or 6% greater than our 2011 production. Oil was the biggest driver of that growth. Oil production for 2012 averaged 31,463 barrels per day, increasing 17% over 2011.

Our oil and gas sales for 2012 are relatively flat, with higher production being offset by lower prices. Gas prices fell 35%, natural gas liquids prices, on average, dropped 28%, and oil was down 4%.

So we reported strong cash flow from operations of $1.1 billion and net income of $353.8 million or $4.07 per diluted share. Another metric that speaks for who we are, we ended the year with no bank debt and only $750 million of senior notes. As of year end, our debt-to-total capitalization was 18%.

And I just want to say at the outset, something we've said from time-to-time, we're not averse to borrowing money. That balance sheet is there to weather the commodity cycles and provide flexibility, but also there for opportunities. So even though we're classically a low-debt outfit, I wouldn't want to surprise anybody, we see that balance sheet as flexibility, and for the right opportunity, we'll tap it.

Moving on to Slide 5. We had a good year, adding significantly to our proved reserves. Very, very good year to the drill bit. We replaced 330% of production from extensions and discoveries. Proved reserves grew 10% to 2.3 Tcf equivalent. But if you exclude the property sales that we closed on in December, our reserves grew 13%. Oil reserves grew 18%, excluding property sales. We added 757.3 Bcf equivalent from drilling, and of those additions, 51% were liquids.

We invested $1.6 billion in exploration and development. We drilled 192 net wells and realized very solid returns in both our Permian and our Cana programs.

Overall, we had very strong execution in our key plays. We're very, very pleased with our core Mid-Continent and Permian programs, the execution we saw in 2012, the execution we're seeing as we look ahead to 2013 and also the investment returns that those plays offer us.

We had continued strong results in our Permian and Bone Spring plays. And John Lambuth, our Vice President of Exploration, will be giving you quite a bit of color on this, but we're increasingly excited about our Culberson County play. Both the Wolfcamp and the Bone Spring look attractive to us in that play. We've got the Wolfcamp in Reeves County, that's a new add for us, in addition to our core plays of the Second and Third Bone Spring.

The Permian also continues to develop new targets, some of which we haven't disclosed yet. And overall, it's a very, very nice place to operate, and we're seeing improving costs and operations performance.

Slide 6 shows our core operating areas. Year-end 2012 reserves are 2.3 Tcf equivalent. As you can see, 68% Mid-Continent, 31% Permian. And our fourth quarter 2012 production at 677 million cubic feet equivalent per day was 52% Mid-Continent and 43% Permian.

Slide 7 shows our growth in proved reserves from 2009 through 2012. We have a very, very solid proved reserve base. Our PUD percentage is still a very low 20%. One of the things I'll say about our reserves, they're solid, they're real. We do look-backs every year, back to the history of Cimarex in 2002. Our reserves have stood the test of time and we feel very, very confident in laying these reserves out to the investing public.

100% of our proved undeveloped reserves are currently in Cana.

As our investments have been pulled towards more liquids-rich areas of our portfolio, that's resulted in solid liquids growth. As you can see, we're currently 55% gas, 45% liquids. We've seen a nice compounded annual growth rate of 42% of our liquids, going back to 2009, and we expect to see that liquids growth continue as we continue to emphasize the Permian basin.

Moving on to Slide 8. Slide 8 shows our proved reserves by region. And we'd have -- we've had solid reserve growth in our core Permian and Mid-Continent areas. They have increased to the compound annual growth rate of 22% over the last 4 years. But more than just growth, that increase is a result of solid returns in our capital investment program.

As you know, we understand the challenge to grow, but mostly, we view our mandate as the challenge to reinvest our cash flow at high rates of return, and growth is a natural outcome of that. So we're very pleased, as we show you our production reserve growth, to be able to stand before you this morning and tell you that, that's an outcome of some investments that are very attractive to us, and we have a very nice investment portfolio that we're prosecuting in 2013 and beyond.

Going on to Slide 9. Looking forward into 2013, we're moving into this year at a very active drilling pace. And as we always say, we'll be carefully watching our returns. We've given our activity guidance, our investment guidance of between $1.4 billion, $1.5 billion, but we're going to keep our hand closely on the throttle. Depending on our own results, our opportunity set and commodity prices, that could be accelerated or decelerated. We certainly have the flexibility, based on the environment we find ourselves in.

We'll have a very active 2013 Permian program nonetheless. Our Bone Spring programs in New Mexico and Texas are performing very well. And again, John Lambuth will give you some color on that. And as I said a moment ago, we're getting very bullish on the Wolfcamp. Very pleased with our recent results. There've been some industry results that have confirmed what we've always known about the Wolfcamp, and it's rightly getting a lot of attention in the Delaware Basin.

In the Mid-Continent and Cana, we're seeing very good results in our infill drilling. One of the things we'll do, however, we'd like to manage our total capital to be in that $1.4 billion to $1.5 billion, as we currently model it with our current model for our cash flow. So Cana is an area where we'll be adjusting our activity. And again, John will cover that in more detail.

Finally, in Slide 10. As we look at our capital investments over time, the Permian, in 2013, continues to get a slightly larger share of our total capital, over what it did in 2012. We currently project the Permian to be getting 55% -- excuse me, got 55% in 2012. We're projecting it to be 62% this year. The midpoint of our capital at $1.45 billion is down about 10% from last year. But again, we're going to see how it goes. Our cash flow is a certain and critical part of that equation and our results are a critical part of that equation, as are our costs of drilling and completing these wells.

But the good news is we're seeing solid returns in all our areas and lower capital, a result of wanting to keep our capital closer to cash flow.

Slide 11. There's a little pie chart that shows you our capital investments. We're currently running -- today, we have 15 rigs in the Permian, but we'll say, as we move through the year, we'll be between 11 and 14 rigs. We'll drill 150 gross or 105 net wells in the Permian. Those will be spread throughout our programs. In Cana, we'll continue our Cana infill development, and John, once again, will give you some color there. One of the things we're seeing in Cana, as a little bit of change from prior years, we're seeing more demands from other operators. So although our operated activity may decrease, it's being taken up, by and large, by outside operated activity.

And then the Gulf Coast. We're working on some new 3D data sets, and we expect to spend a small amount there this year, drilling 6 to 9 net wells.

Onto Slide 12. Slide 12 showcases the underlying growth engine of our company, and that's the Permian Basin and Mid-Continent. And you can see our production growth. Our investments are delivering that strong growth. For 2013, we expect continued predictable growth for Mid-Continent and Permian. And this is not growth for growth's sake. We're seeing solid economics in our Permian, and liquids-rich gas in both Mid-Continent and Permian, and 40% to 50% of our drilling results are liquids.

So we're seeing very, very nice returns in that Permian and Mid-Continent program. And that is -- has indeed, I think, become apparent to all, that's the engine of our growth.

Slide 13 showcases our Permian oil production and how that's grown over time. And that's driven by outstanding results in our Bone Spring drilling program in both Texas and New Mexico. The growth in 2013, excluding the impact of our year-end asset sale, is 8% to 12%.

So overall, we're seeing very nice results from our program. Again, I'm very proud of our organization and the way we've executed in 2012. We're firing on all cylinders as we enter 2013. With a healthy balance sheet, a fantastic inventory and good prospects for very nice returns on capital, we're looking forward to making 2013 again, a year in which we execute on target.

With that, I'd like to turn the call over to John Lambuth, our Vice President of Exploration.

John Lambuth

Thanks, Tom. I'm going to give you an update on our 2013 exploration drilling program. I'm going to first start with our most active region, as Tom mentioned, Permian Basin.

I'm on Slide 15, for those of you following along with the presentation. You will note that for 2013, our total expected capital investment will be approximately $900 million, which is just a little bit of an increase over 2012. You will also note, though, that the number of gross and net wells is down relative to 2012, with 150 gross for '13 relative to 182 for '12. The primary driver of that is just our overall portfolio, the type of wells we'll be drilling. Where in '12, we had quite a large inventory of shallow Paddock-Blinebry wells, we really don't have much of an inventory of those left for this year, thus, for the same capital, you get fewer wells because the overall portfolio is slightly more expensive.

Going onto Slide 16. As Tom mentioned, our bread-and-butter play has been the Bone Spring. In 2012, we drilled 107 gross, 60 net Bone Spring wells, with 64 in New Mexico, 43 in Texas. We continue to have very strong performance from this program. In New Mexico, our average 30-day IP for the 2012 wells was 640 barrels of oil equivalent per day, with those wells being primarily 90% oil.

In the Texas part of the Bone Spring, where we're mainly targeting the Third Bone Spring sand, the 30-day IP rates were 1,000 barrels of oil equivalent per day, with 85% of it being oil.

We continue to see great results in both of these plays, and we expect that this will continue throughout 2013.

Of course, as we drill these wells, we learn and we try to look for areas to expand into, and we've done just that by moving into Culberson County. We have a couple of recent wells we're going to talk about, that have us very excited about the potential with our acreage there.

The first well is the Owl Draw 12 Unit 12H well. That well had a first 30-day average of 665 barrels of oil per day or an equivalent of over 1,000 of oil equivalent per day. We then followed that up with the Alysheba 17 2H. It had very similar results of 645 barrels of oil per day and over 1,100 barrels equivalent per day, wet gas plus oil, when we combine.

What's really exciting about this is that, in Culberson, we're actually slightly shallower than what we typically drill in New Mexico. And thus our well costs are even little bit less than what we usually experience in those other plays. So the type of returns we're getting from this play are very, very good.

When we look at this play and look at the totality of our acreage, we can put a wide range of potential locations here. In fact, the numbers range from 100 to 200. But the simple fact is we really don't know until we drill more wells and we get a very better idea of how we define and de-risk this play.

It is this encouragement that is leading us to maintain an approximate 2 rig schedule in Culberson, targeting this Second Bone Spring interval.

But of course, our acreage in Culberson was initially driven by our Horizontal Wolfcamp play. In 2012, we drilled 15 Horizontal Wolfcamp play, bringing the total number of wells we drilled within this White City Culberson area to 33 from its inception. As most of you know, we have been the leading driller and industry maker for this area.

We continue to see better and better performance from these wells as we try to continue to change the recipe in terms of frac-ing, fracture stimulation, and where we land our laterals. Please keep in mind that the Wolfcamp in Culberson is upwards of 600 to 700 feet gross thickness. So it's taken us a while to find that magic landing zone relative to frac to get the best performance, but we're definitely starting to see that.

As we show on Slide 17, from first quarter to fourth quarter 2012, we've been able to increase our liquid yield from 59 barrels per million to 97 barrels per million. That is definitely having a big impact on the type of rate of returns we can expect from these wells.

As you go to Slide 18, you see then over the last 3-year period, what our Horizontal Wolfcamp production looks like. You will note a couple of things: first off, we made a major investment in a new pipeline within Culberson County, we call Triple Crown. That pipeline, which was completed in late 2003, gives us the flexibility for multiple outlays for the -- for taking our gas to market.

That has also then enabled us to go out there and increase our drilling activity, which you see, resulted in a nice increase in production you see in 2012. We fully expect to see that continue to increase as we go into '13.

On Slide 19, you see, based on the most recent wells in terms of the average, we are presenting to you our type curve, essentially what we expect these types of wells to make. You will note that the 30-day average is 6.4 million cubic feet equivalent per day, with an EUR range of 4.5 Bcfe to 5.5 Bcfe. Although in this case, this particular type curve is a 5.4 Bcf equivalent. The makeup of that hydrocarbon is 47% gas, 30% NGL and 23% oil.

If you now go to Slide 20, and I use that type curve, along with our net revenue interest of 75%. And then finally, our most recent AFE for a completed well being $7.2 million, you will see that, with a forward strip from February 11 of '13, we are able to generate in the low-30 type of internal rate of return for this type of program. This really is exciting for us because, as you recognize, this shale play is rather extensive over this acreage, and thus great potential is there for us. I'm sorry, that's an APAX [ph] rate of return.

Furthermore, then, in summary for Wolfcamp in White City and Culberson, along with our improving results in terms of the production we're seeing, we're also seeing a nice decrease in our well costs over time. In 2011, our average well cost was around $10 million. 2012, it decreased again, down to around the mid-8s. And now for 2013, we're seeing somewhere in the mid-7s, a nice decrease, which again only helps with the type of returns we'll get from these wells.

If we look again at our total acreage position and just look at the overall potential, then we've shown you a table of what the future may hold for us in this play. Now I must emphasize strongly, we have not yet drilled a downspacing pilot to determine what our ultimate spacing will be. With that said, on the conservative side of just 160 acres, or 4 wells per section, based on our current acreage position, we would have 500 net wells with a reserve potential of 1.7 to 2.1 Tcf. And that would require a capital investment of $3.6 million. Obviously, if we could prove via a downspacing pilot, even tighter spacing, essentially going down to 80, that would result in the doubling of those numbers. Again, we need to, at some point, plan a spacing pilot, but as of right now, we're still in the mode of HBP-ing in our acreage in order to secure our acreage position.

But as Tom mentioned, that's not the only place that we are drilling Horizontal Wolfcamp wells. We do have a significant position at Reeves County, approximately over 35,000 acres. We have drilled 2 wells now on that acreage position. We are in the early parts of flowback on those wells. What I can tell you is we are very encouraged with the results we're seeing, so much so that for this year, we plan to drill approximately 3 additional tests in the immediate area to better define the opportunity there.

I'm now on Slide 22. I'll be stepping to the Mid-Continent region. On that slide, you will see that for 2013, our estimated capital investment will be $450 million as compared to $673 million for 2012. As you know, for Mid-Continent, the majority of that money goes to Cana-Woodford. In regards to the change in capital, from $673 million to $450 million, you need to keep in mind that in 2012, for that program, over 37% of wells we drilled were one-off or exploratory wells, to better define the Cana opportunity for us. 63% were infill core drilling. When we look at our 2013 program, over 90% of the wells that we will be drilling to participate in, are infill core programs. That is where we're going to get our best rate of returns and that is where we're focusing our capital on.

From the inception of this play, as you see on Slide 23, we have drilled or participated in over -- approximately 492 wells, through the first -- fourth quarter 2012. We have a very strong land position of 120,000 net acres, of which, as we show on the display there, we have delineated what we call a gas-rich down-dip area, up-dip liquid-rich area. Within the liquid-rich area, we have 75,000 acres, of which almost all of them now are in a held-by position status. So we really are not driven anymore to go out to drill wells to hold acreage, it's just a matter of maximizing our opportunity in terms of picking the best rate of return.

As we go to Slide 24 then, we are doing just that with our infill drilling program. We are essentially carrying forward into 2013 what we are doing through the majority of 2012. We have 4 operated rigs, currently. We -- for full development in Cana, we are drilling 8 new wells per section, in addition to the existing parent well. That results in 9 wells per section. We plan for 2013 to have 125 gross wells, that's 35 operated, 90 non-operated. I will point out that, for 2012, we participated or drilled in 128 gross wells. So there's not that large a difference between '12 and '13 when it comes to Cana infill development.

On Slide 25, you see a display or graph of our net production from Cana-Woodford for the past 3 years. You will note, in the first 2 quarters in '12, there was a slowdown to -- in fact, a slight decrease. And that was due to the fact that, to start the infill development program, we need to develop a sufficient buffer space between our actively drilling wells and the frac fleet. Once we accomplish that, we then immediately start to develop, or frac-ing wells, and then you see that nice ramp-up in production in the last 2 quarters there.

It's that type of production growth again, we'd expect in '13 with this infill drilling program.

So in summary for Cana-Woodford, we exited fourth quarter 2012 with net production of 215 million cubic feet equivalent per day, which was a 30% increase over fourth quarter 2011. And at the bottom, I still want to point out, there's still great potential here, even though we've already embarked on an infill development program. To date, we have 1.1 Tcf of equivalent gas proved for Cana. And yet, we still show a risk upside within that liquid-rich core area of 3.3 Tcf, which would equate to 660 net wells and close to $5 billion of capital. So total risked resources for Cana, as you see there on that slide, is 4.4 Tcf.

Finally, on Slide 27. A quick word on our Gulf Coast program. As those of you who follow us know, Gulf Coast is our higher-risk, greater-reward opportunity region. It is a region that is entirely dependent upon 3D seismic and the attribute work we do with that to pinpoint our drilling locations. In 2012, we made a major investment in a number of new 3D surveys, in order to replenish our drilling inventory.

That data has been acquired, processed, it is in house. We are currently rebuilding that inventory and hope to be drilling again in the second quarter of this year. But I want to emphasize, unlike the other regions, we do not think of Gulf Coast as a rig line, as much as it is of capturing good opportunity. We hope that there will be 10 gross, 7 net wells there. But again, it's all about the quality of the opportunity we have, and if it's good, we will drill it, if not, then we won't reach that number.

With that, I will hand it over to Joe Albi, who will talk about the productions for Cimarex.

Joseph R. Albi

Thanks, John. I will be going over our fourth quarter and 2012 production statistics. I'll hit a little bit on our 2013 guidance and then just a few comments on where we ended the year with LOE and where we see current service costs. For those of you following along, I'll start here on Slide 29.

And to echo Tom's earlier comments in the call, we really did have a great year. We had some strong October and November new well adds that helped prop our fourth-quarter volumes up to a level of 677 million equivalents a day. That was right at the upper end of our guidance of 652 million to 677 million, and up 13% from where we were in Q4 '11 at 601 million a day.

All the while, we set a new record in the fourth quarter for total company production, and the driver to that growth, as we've alluded to already in this call, was our increased oil production, which grew 28% over Q4 '11 to a record of 35,099 barrels a day in Q4.

Also helping the quarter were minimal production disruptions for plant turnarounds, ethane rejection and other downtime, which, those of you following us for a while have known, did impact us a little bit more, earlier in 2012.

We dig deeper into the numbers, we continue to see production growth from our Permian and Mid-Continent programs. Our record fourth quarter Permian net equivalent volume of 292 million a day was up 6% or 17 million a day from Q3 '12, and up 36% or 77 million a day from fourth quarter of 2011.

Our oil growth was the real driver here, with our Q4 Permian oil volumes averaging 27,091 barrels a day, another record for the company, and up 42% from fourth quarter last year. We're drilling some really great wells, and it's showing up in our numbers, with some strong adds from really virtually all our programs in the Permian. Our Texas and New Mexico Bone Spring plays, as well as our Wolfcamp program.

Our fourth quarter Mid-Continent equivalent volume of 351 million a day was also a record for the company. It was up 8% from last quarter and 11% from a year ago. Cana continued to drive the increase, with record fourth quarter volumes of 215 million a day, that's up 31 million a day from last quarter and a respectable 57 million a day from Q4 '11.

With that, Cana now represents 32% of our total company production. So in a nutshell, Q4 came in, I'd say, as modeled, but I'll say it came in on the high end of our model, reflected significant increased volumes from our Permian and Mid-Continent programs. And as a result, our full-year 2012 equivalent production came in at a record 626.5 million a day, which was up 6% from our 2011 average of 592 million a day.

And driving the year-over-year growth was really 3 important factors: a 43% increase in Permian oil volumes; a 15% increase in our total liquid volumes; and a 21% increase in our combined Permian and equivalent -- excuse me, Mid-Continent equivalent volumes. Definitely, a good year.

Shifting over to Slide 30, where we look at production by region. Big obvious thing pops out here, and that is we've seen a nice increase in our total liquid production over the last few years. Our Q4 liquid volumes averaged 57,217 barrels a day. Looking back 3 years ago, that's 2.5x the 22,935 barrels a day we averaged in the fourth quarter of 2009.

The catalyst to the growth has been the Permian, which accounts now for 61% of our total liquid production. That said, we're also seeing nice contribution from Cana, which is the backbone to the 35% of the total company liquids comprised by the Mid-Continent.

The Mid-Continent still represents the lion's share of our gas production at 69%, and our total company equivalent production of 677 million a day is now nicely balanced between the Mid-Continent and the Permian, with the Mid-Continent representing 52% of the total and the Permian at 43%.

On Slide 31. Looking forward to our 2013 production guidance. We're projecting our 2013 equivalent daily volumes to average in the range of 675 million to 705 million equivalents per day for the year. That's up 8% to 13% over 2012. Built into this estimate is the $294 million Permian property sale that we closed on at the end of the year, which reduced our net volumes by 2,550 equivalent barrels per day, 2,000 barrels a day of which was oil.

If you're looking at the table in the presentation, you'll see our projected 2013 oil growth to be quoted at 1% to 5%. But if we exclude the impact of that sale, in essence, we're projecting 7% to 11% oil production growth, and so we have a very good chance for a second year of double-digit oil production growth here in 2013.

Although our Gulf Coast production is modeled to contribute only 3% to 4% of our total company production, we do have some drilling planned for the program this year and have incorporated a modest, I'll call it, heavily risked drilling wedge of 5 million to 10 million a day for the year, which has been built into our modeled projections.

Hence, from 30,000 feet, what we're projecting is for 2013 to look quite similar to 2012. Strong double-digit Permian and Mid-Continent production growth in the range of 11% to 15%, with an emphasis on liquids, which as modeled, would bring our liquid percentage up to 51% by the end of '13.

Our first quarter guidance of 614 -- or, excuse me, 642 million to 667 million has been reduced by about 15.5 million a day, for a recent property sale, as well as some weather and other facility shut-ins that we experienced in early January. In essence, after accounting for the property sale and the shut-ins, we're projecting Q1 to be fairly flat with our strong Q4 '12 results.

Shifting gears over to operating expense on Slide 32, as we talked about before in our previous calls, our production group has put a great deal of energy into fighting the overall cost increases the industry has seen over the last year in LOE, in particular, in the area of SWD and more specifically, in the Permian.

In addition, we've undertaken measures to control workover costs company-wide. Well our efforts are showing up in the financials, with a Q4 lifting costs coming in at $1.06 per Mcfe, that's down another $0.01 from where we were in the third quarter of 2012 and we're down $0.12 or 10% from Q4 '11. Our Q4 '12 lifting cost is the lowest lifting cost we've seen since late 2010.

Looking forward into 2013, we've projected our full year ROE guidance at $1.05 to $1.17, and hoping to fall in on the lower end of that range.

Just a few comments on service costs before I turn the call over to Paul. On the drilling side, similar to what we discussed last quarter, we are seeing most cost components remain relatively in check, but we are seeing continued signs of a softening rig market, as evidenced by recorded day rates down anywhere from 3% to 5% from last year.

Our biggest cost savings continue to come in the form of drilling efficiencies and lower per unit frac costs. An interesting observation, when we compiled our frac statistics at the end of the year, our total company frac statistics show we pumped upwards of 20% to 30% more sand and fluid in 2012 than in 2011, yet our overall frac costs were down 18%. And that's really a combination of pumping more white sand, reduced service costs and additional horsepower on the market.

Looking more specifically at individual well costs, in Cana, our drilling efficiencies and lower frac costs have brought our current AFEs in the core infill program down to about $7 million, total well cost. That's $400,000 lower than what we quoted last call and down $1 million from where we were a year ago, so it's paying off in Cana.

In the Permian, our Horizontal Second Bone Spring wells continue to run in the $6.5 million to $7.1 million range, while drilling efficiencies in our West Texas Third Bone program have brought total well costs down to $7.2 million -- around $7.2 million. That's $300,000 lower than the figure we quoted last call.

And finally, our Horizontal Wolfcamp wells are running $7 million to $7.5 million, total well costs. That's down from $8 million to $8.5 million, the levels that we saw about 6 months ago.

So all in all, we're quite excited about where we are. Our production and our reserves are trending up, while our lifting and well costs are trending down. We've got a deep multi-year inventory of drilling projects in the Permian and the Mid-Continent, probably the richest inventory XEC ever had. And all those are very good reasons to find ourselves in a pretty good position here, starting out in 2013.

So with that, I'll turn the call over to Paul Korus.

Paul Korus

Thank you, Joe. If you'll page forward to Slide 34, I'm a little brief, I only have one slide.

Despite the fall in gas and oil prices during 2012, we had reasonably good earnings, driven by nice growth in production and proved reserves. After investing $1.6 billion in 2012, we ended the year with $750 million of debt. That was inched up, if you will, from about $400 million at the end of 2011.

So still plenty of capacity on the balance sheet, but please do recognize that our prior tolerance of note debt has at least evolved into a tolerance of some, albeit still low, amount of debt.

We had -- as we mentioned repeatedly, we had good growth in production of 6%, which actually met the midpoint of our very original guidance for the year. And we increased our proved reserves by 10% to 2.3 Tcf, adding 750 Bcfe of reserves through new drilling, which was more than 3x our production for the year. And we had good finding [ph] costs and good rates of return doing it.

So as we look to 2013, our expected capital, at the present time, gives a very narrow range for us of $1.4 billion to $1.5 billion. But as Tom mentioned, please appreciate that we reserve the right to increase it some or decrease it some, as the year evolves.

Still, at the tight range that we're giving, our expectations are for double-digit growth in production and reserves in 2013.

Those are my comments. Kayla, we would be happy to entertain questions at this time.

Question-and-Answer Session


[Operator Instructions] And we do have a question from Phil Jungwirth from BMO Capital Markets.

Phillip Jungwirth - BMO Capital Markets U.S.

On the oil production guidance for 2013, 32,000 to 33,000 barrels a day, it seems to be a little bit lower than the 4Q average, even adjusting for the assets. So can you address why this would be the case? And is it mostly just conservatism on your part, given that greater allocation of capital is going towards the Bone Spring and you've seen better results there?

Joseph R. Albi

Phil, this is Joe, I'll answer that. Yes, if you look at the slide, it says, hey, without the property sales, we're showing 1% to 5% growth. When we throw those back in there, 7% to 11% growth. Our projections do incorporate risking. And if we're off, I think what it's basically telling us is that we've got a very strong chance of having another year of double-digit production growth. There's a couple of other things that are at play here, too. At any one given point in time, new wells make up 40% to 50% of our total company production. And those new wells, even these permian wells, they can come screaming off pretty hard. So we're always constantly fighting the snowball effect of new well decline, which can impact the rates of production growth and certainly have an impact on what ends up being the final product of our modeling. But as Tom alluded to earlier in the call, as those of you who've known us for all these years, we are focused on rate of return. And it's all about rate of return. And to the degree that production is a byproduct of that, so be it. Obviously, we want our production to go up. That year or -- all that said, our model is really showing that we have a very, very good chance of another year of double-digit production growth. And we're really pretty pleased with that. Being able to have double-digit production growth is not something to not be proud of. So that's, I guess, our answer to that question.

Thomas E. Jorden

Yes, this is Tom. If I could just follow up that up. Joe has done this for a long time and he's gotten quite astute at making these models. Our business units send in what they think they're going to do and they time it out, and Joe takes that and looks to see what historically they've done. In the oil patch, things tend to go more wrong than they go right. You have delays in timing, you have delays in equipment. And so Joe factors in what he thinks is our historical average and he risks those business unit models down. That said, the business unit modelers are getting better and better at it. They're going to challenge him and if all goes right, we're going to beat that number. But we'll just have to see as we go through the year. It'd be nice to have a year where all goes right, but it would be our first.

Joseph R. Albi

The other thing I want to add because I'm guessing we'll get the question, is on Q1, with our guidance being lower than Q4. Well, a couple of things at play there and this is also impacting our total number. But the Permian Basin sales that we closed on at the very end of the month last year, took about 15.5 million a day off our first quarter production. We also had a number of freezing issues and pipeline issues, and particularly in Culberson County, in early January, that hurt January to the tune of about 16 million a day, that built into that number. We also had a handful of good strong fourth quarter wells that came on in October and November that were on a very good screaming decline here in November and early January that we were fighting. And all of that, when you add it all up says, hey, we're going to be at about flat with Q4, which was strong quarter for us. We were at the upper end of our production guidance. All that said, the model is also saying that we anticipate production to start picking up here pretty quickly in February, and our early indications are that production is doing just that. And when you take a look at our production guidance for the year, and you look at 675 million to 705 million and you compare it to where we were in Q1 or what we're given guidance in Q1, hey, it smells an awful lot like what we told you guys last year. We're going to be kind of flat for the first half of the year and we expect to ramp up here at the end of the year and, lo and behold, that happened. And that's what we're modeling this year. We're going to have a little bit of a delayed start here in the first quarter, primarily as a result of the property sale. Our model is saying that, come around second quarter, we're going to start to see some real nice production growth. And ultimately, I hope, allow us to talk quarter-to-quarter about continued record numbers. So kind of a long answer to your question but I thought I'd knock off the second question because I thought it was going to get asked.

Phillip Jungwirth - BMO Capital Markets U.S.

Here's a third question on the guidance. On the NGL production growth of 33% to 39%, is any of that driven by a change in processing contracts and then reporting the NGLs as opposed to leaving it in the gas stream?

Joseph R. Albi

No, most of that is all due to the existing contracts, which have already been modified. Most of the old contracts that could be rewritten or revised, all that's been done. So anything really showing up now is all through new adds.

Phillip Jungwirth - BMO Capital Markets U.S.

And then final question here, I appreciate all the Wolfcamp disclosure. It looks like there could be some variability in the GOR as you move from the south to the north. Is that the case or am I just drawing some conclusions from 2 wells here?

John Lambuth

I don't know. You should -- this is John Lambuth. I don't know you should draw any conclusion from just 2 wells. I would say, clearly, based on how we understand that formation, there is variability. But we tend to think as more of an east-west trend than north-south. But again, we still get surprises as we continue to drill this. But I would say not north-south necessarily, just based on those 2 wells.

Thomas E. Jorden

But we also see a primary variability, stratigraphically. And that's a complex system.

John Lambuth

It is, and that's something again, I want to emphasize. It's a very thick shale and we have really honed in on a particular interval, where we're getting our best results. And you would expect us then to get much more consistent results as we go forward, because that's the interval that we're primarily going to be drilling in.

Thomas E. Jorden

And we're obviously -- our excitement about the Wolfcamp comes through in our comments. But we're really early times here and, with the interval as thick as it is, we have a lot of that stratigraphy we haven't tested. So we're, as yet, uncertain as to what our ultimate spacing will be, either laterally or vertically. I mean, there's an argument that says 8 wells per section is not adequate to fully exploit this resource. But the truth of the matter is, we don't know, and we really would like to get data rather than speculation.


And our next question comes from Mario Barraza with Tuohy Brothers.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Mario Barraza here. Just want to dive a little deeper on the Second Bone play on the Texas side. Last quarter -- are we still thinking just over 125 well locations is a comfortable count for this point? I know you guys said right now, 100 to 200 locations. But what percentage of your acreage in Culberson do you think this is prospective?

John Lambuth

Well, this is John Lambuth, again, and I guess, I would say 100 to 200 locations. I mean, we are very, very early. If you think we're early in Wolfcamp, we're very early in this play. We have 2 very good, very exciting wells that we wanted to tell you about. We have very limited well control. Basically, our well control in that area is our Wolfcamp drilling. It helps define that shallower Second Bone Spring. But unlike the Wolfcamp, there's quite a bit of stratigraphic variability in the Second Bone Spring, so with each well we drill, we learn a little bit more, some to the negative, some to the positive. All I can tell you is, just looking at our acreage position and the current wells we have, we see definite potential and it's in the range that I just mentioned. This year will be very important for us because we have a lot of wells. We will be drilling to test it and further define it. So maybe during the course of the year, we might be able to give you a little bit better update. But we're just being honest, this is how we see it right now, based on the limited well data we have.

Thomas E. Jorden

This is Tom, if I could just follow-up on that. We've long recognized the potential of Second Bone Spring in Culberson County. This is not news to us. The reason that we haven't talked about it prior to the last call or 2 is because we expected it to be gassy. Based on our overall trend in the basin, we looked at that and this part of the basin and thought, it's probably gassy. We had good shows and we drilled through it, but we hadn't tested it. And these first tests, ours and there are some offset operators, have really surprised us pleasantly. We really didn't expect the Second Bone Spring to be as oily as it is. I mean, these are fantastic oil wells. And so when you ask what controls these 100 or 200 locations? We have that sand map throughout this Culberson block. We have very good shows when we drilled through it. We're just hesitant to get too out in front of ourselves and say how oily or gassy it is, and that's the main controlling factor. Is it going to continue to be oily or will there be pockets of this land where it's a little heavier gas? So that's why we are not waving the checkered flag just yet, but we're very, very encouraged by the results we have, limited though they may be.

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Okay, appreciate that color. If I can shift gears towards the CapEx budget for this year. On the last call, you talked about -- you were going to exit the year with 4 to 5 rigs in Cana, but if gas prices stayed depressed, you might -- you were considering shifting out, possibly some rigs and transferring some more CapEx dollars to the Permian. What's kind of the price lever you're thinking about for -- where would you pull back on the number of rigs in Cana?

John Lambuth

Well, this is John Lambuth, again. I really couldn't pick a particular price. Again, it's going to be a matter of rate of return. And that's going to be dictated by the type of section we have an opportunity to drill. Again, the yield, the NGL mix, really dictates that rate of return, more than the gas price even. So we're constantly monitoring both our results to make sure we're hitting our expected volumes and our drill costs. Right now, we're very encouraged, I mean, very encouraged with what we're seeing coming out of Cana but, that said, we're always keeping an eye toward gas prices. And yes, if it drops to a level where we don't see it to be economic, we will slow that down or even shut it.

Thomas E. Jorden

Yes, it's Tom. It's really a function of how much money we want to borrow this year, more than anything else. Our cash flow is what it is, and we're trying to allocate it. Our returns in Cana are quite good. Our returns in the Permian, in general, are slightly better, and it's a function of how much money we want to borrow.

Paul Korus

It's Paul. I'll just add that, whether we run these 4 rigs through roughly the middle of the year or whether we run them all through the year, it's only about a $50 million swing. So it really won't move the needle that much in terms of capital or production volumes in 2013, because the wells drilled in the first half will be frac-ed in the second half, roughly. It would have further implications for 2014, perhaps, in terms production volumes. But it's not a needle mover.

John Lambuth

I mean, I would just say, again, I would emphasize, we're getting some really great results and they're really making it hard for us to not want to go ahead and get those rigs going. I'll leave it that way. I mean, really good results so far as we start this year.

Thomas E. Jorden

But we have not made a final decision. We currently have 4 rigs running at Cana, and we've not made a final decision.

John Lambuth

That is correct.


And your next question comes from Jeff Robertson with Barclays.

Jeffrey W. Robertson - Barclays Capital, Research Division

Tom, in the Wolfcamp play in Culberson County, can you talk about where you think you'll be with some of these questions, just around stratigraphy and spacing, by the end of the year? By the end of 2013, that is?

Thomas E. Jorden

Well, there's really 2 issues, Jeff. And I'd invite John to chime in here. One is, we're still sampling real estate. If you look at our current penetrations, although we think we've got a lot more than we know, there's still a lot of that area that's very finely sampled. So we need to just sample the real estate over that acreage block. We don't currently have planned this year a spacing pilot. Now that's something else that we're still kind of arguing about, because that's -- our experience in Cana is that, that's something you want to know as early as you can for full development. But right now, we don't have a spacing pilot planned for the Wolfcamp. And so we don't know yet what the spacing will be, both laterally and vertically. So your question is, what are we going to know by the end of the year? I think under our current plan, we're going to know the liquids yield and the producibility of that rock over a wider area than we've currently sampled, but in our current plan, we probably won't know any more about spacing than we do now.

John Lambuth

This is John Lambuth. I agree. I mean, the only thing I'd add, besides just the overall productivity of these wells is, again, we're very excited about what we're seeing with our drilling complete costs and, really, right now, as we look at these wells, that really is going to be one of the bigger drivers to the type of rate of returns we get. And so far, we're very encouraged by what we see going on in regards to those costs, both from the drill side, but especially on the completion side, is something Joe alluded to earlier. We're definitely seeing a decrease in our completion costs, and that really is very impactful for these wells.

Jeffrey W. Robertson - Barclays Capital, Research Division

Second question on that play. I think you said there are several different zones within the Wolfcamp. Is all of your drilling going into what you think is the same Wolfcamp interval?

John Lambuth

This is John Lambuth, again. Early on, we were, how do you say, all over the court? I mean, trying to understand, optimally, where we should be. It's fair to say, going forward, we've kind of honed in on the particular interval. We break it up into A, B, C, D and E. In our case, we have a particular interval that we now feel really good about and that's where you'd expect us to put the majority of our wells going forward.

Thomas E. Jorden

If I might add to that, Jeff. Some of the new drilling you're seeing over in Reeves County is in the shallow-most stratigraphy in that Wolfcamp. That's something that we haven't sampled in Culberson County, and there's a -- it looks interesting to us, we don't have a well in it. And it might be additive to everything else were doing and it might not be either/or, it might be additive. And please take that with a grain of salt, don't run out and update your model on that. We just don't know. I mean, we're just -- it looks to us like this Wolfcamp is going to be a legacy asset that can stand tall next to Cana for the future of Cimarex. That's the message this morning. The detail, whether it's $7 billion, $10 billion, $15 billion of future capital, we just don't know. But it's here to stay and we like it.

Jeffrey W. Robertson - Barclays Capital, Research Division

One last question. Is there the ability to increase acreage in the play, in the areas that you think are promising?

Thomas E. Jorden

Well, we did increase acreage in 2012. We made a couple of acreage acquisitions that we talked about. It's getting skinny on the broad brushes. But we still get up every morning, and we wrestled home some things and we're continuing to do that. But I wouldn't want to start from scratch today in that part of the real estate, that part of the world.


And your next question comes from Joe Magner with Macquarie Capital.

Joseph Patrick Magner - Macquarie Research

I just wanted to, I guess, get a sense on when, during the year, do you think you'll have enough information or insight into some of these new opportunities? And the results seem very encouraging, rates of return seem very equivalent across different plays and competitive with existing development opportunities. I'm just curious when we might start to expect to hear decisions on increasing capital or drilling additional wells?

John Lambuth

Well, I guess -- this is John Lambuth. What new -- which ones you're referring to, just specifically, so I can....

Joseph Patrick Magner - Macquarie Research

Well, I guess, the Second Bone Spring opportunity in Culberson, in particular, and then the Wolfcamp Shale, over in that same general vicinity, seemed like the 2 areas, at least where results could be supportive.

John Lambuth

Well, I would just say, in Culberson, I think we're pretty set on that 1 to 2 rig schedule for this year, as we continue to identify the opportunity there.

Thomas E. Jorden

For the Bone Spring, in addition to the Wolfcamp.

John Lambuth

For the Bone Spring, in addition to the

Wolfcamp, you're absolutely right, Tom. That all -- like we say, that's always subject to change based on performance. But right now, we think that's the adequate rig schedule and capital we need to fully define that opportunity. Clearly, by the end of the year, we'll have a much better understanding of it. In terms of Reeves County, all I'll say is, we really need some more well performance and perhaps even a couple more wells, before even we're ready to talk about it. We need time there. Again, I'll just say we're encouraged. But we need a couple more wells, and we just need to see some more consistent performance, and then we'll probably be in a better position to talk about it.

Joseph Patrick Magner - Macquarie Research

Okay. And I guess with respect to the Horizontal Wolfcamp that's been focused in New Mexico, 33 wells drilled to date, how much of that acreage has been held now? And what is required, I guess, through this year, to be able to -- this year into next year, to lock up more of that acreage?

Thomas E. Jorden

Yes, in the New Mexico, in that Wolfcamp trend, it's by and large, I won't say 100%, but it's almost all held. We have a couple of obligation wells that we drill every year but other than that, we don't have any kind of an acreage exploration that's driving our New Mexico portion.

Joseph Patrick Magner - Macquarie Research

Okay. And there's one last one for me. I believe you all have been working on some other shallow liquids opportunities, or other Mid-Continent liquids opportunities. Any update on any of those new initiatives?

John Lambuth

No, no new update as of today. You are right in that there are a couple of plays that we have been pursuing. We still have some more evaluating and drilling to do in those plays. We really can't add any color to that today.


Your next question comes from Ryan Todd with Deutsche Bank.

Ryan Todd - Deutsche Bank AG, Research Division

A question -- I don't mean to beat a dead horse, but I just wanted to follow up on the guidance for this year. The 60 million cubic feet a day that you talked about that was affected by shut-ins in Culberson County, is that just 60 million cubic feet a day in January or is that across the entire first quarter?

Joseph R. Albi

This is Joe. That, for the most part, those were very mature properties with very shallow declines.

John Lambuth

So it came from the shut-ins, Joe.

Joseph R. Albi

Oh, for the shut in. I thought -- the freeze-outs [ph] , for the most part, appear to behind us. We will have, in the Culberson County area, probably in the first part of Q2, some work done to high-grade some of our pegging facilities and improve some of the line itself. So there'll be a little bit of downtime there, but it looks like the freezing issues in January are behind us.

Thomas E. Jorden

But it's just January. It's built into our Q1 guidance.

Joseph R. Albi

So if you were to divide it by 3, I guess, if you want to take a look at that.

Ryan Todd - Deutsche Bank AG, Research Division

And then on the -- how would you describe -- I mean, can walk me through to the state of infrastructure, I guess, as you look forward over the course of 2013? I mean, how much conservatism did you build into the numbers from potential infrastructure downtime? I guess, I'm still having a little bit of a hard time wrapping my head around the fact that, for 18 months, you've done kind of 2,000 barrels a day sequentially each quarter, Permian oil growth, and it seems to have flattened off. I'm just trying to figure out is that -- how much that it's infrastructure downtime conservatism you're building in versus anything else?

Joseph R. Albi

There's maybe, if you were to take a look at the Permian, I'll just tell you in equivalents, I don't know how it's going to answer the oil side of it. But I venture to say that we, just on base properties, have integrated somewhere the range of 7 million to 10 million a day of a risk in our base property production that you could attribute to being directly associated with downtime, because that's about what we saw last year as an average. Second quarter last year, I think, we had a 14 million a day impact for the quarter, and most of that was in the Permian. And let's face it, the Permian is a tight deal out there. And we're constantly finding it. We had a few wells here in Q1 that we delayed fracs on, waiting to get the connections put into place. So I guess, if you're looking for a number, that'd be about the number I'd give you. Other than that, I always take a minute when I answer this question this way, too. What we're trying to do with our guidance, heck, the majority of that number is coming from new wells, and we're trying to predict when we're going to drill, and when we're going to hit the good ones, what they're going to produce, and for the most part, I'm really pretty amazed, as close as we all get playing this game, when you're trying to project what you're going to see. So we inherently put, maybe, a 70% to 80% risk into our region on risk numbers, based on history. And that's kind of how we end up where we end up. We look at capital utilization, how well we spent money and added production and so forth, and then come up with our final number.

Mark Burford

Ryan, this is Mark. I have one other thought to add to that discussion, is that, as you pointed out in the slide, for the guidance slide, we talked about oil growth, excluding property sale, being 7% to 11%. And the risking that Joe is alluding to and then further risking, if you take our risked/unrisked team's wedge, as Tom alluded to, probably be adding a few thousand barrels a day to these numbers. And if we add that back into these guidance numbers, it'll probably be close to 20% growth year-over-year in oil. So we definitely have tried to build in some uncertainty with the infrastructure, uncertainty in well timing, all those factors that go into guidance. But definitely, there's a lot more upside in these numbers if we hit our plan, but we know historically, there's always timing -- issues with timing, infrastructure, and those things. And so we try to build in, we think, would be a reasonable amount of conservatism for the numbers we can think we can reasonably achieve.

Ryan Todd - Deutsche Bank AG, Research Division

I guess, one last thing for me from an infrastructure point of view, as the pipelines come in, connecting the Permian to the Gulf over the course of the year, I mean, how do you -- you've obviously seen the differential come in quite a bit up to this point, I mean how do you view that playing out over the rest of the year? Do you see upside in terms of potential to narrow that differential or maybe even go at a premium to WTI at any point? Or...

Mark Burford

WTI premium -- WTI, no, Ryan. We don't see that potential occurring. We're grateful to see it tightening to where it's gone. But I mean, we've -- when we look at the forward curve, I'd say it's still at around $1 range, that's -- we look at our models, and we don't assume it to go to premium, but we don't also assume to buying [ph] back out like we saw early late last year and early part of this year.


And there are no further questions at this time.

Mark Burford

Great. Thank you all for joining us on the fourth quarter conference call. I look forward to reporting to you next quarter. Take care. Bye-bye.


This does conclude today's conference call. 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 All other use is prohibited.


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