Cimarex Energy Co. Q3 2009 Earnings Call Transcript

| About: Cimarex Energy (XEC)

Cimarex Energy Co. (NYSE:XEC)

Q3 2009 Earnings Call

November 3, 2009 1.00 pm ET


Mick Merelli - Chairman & Chief Executive Officer

Tom Jorden - Executive Vice President of Exploration

Joe Albi - Executive Vice President of Operations

Paul Korus - Vice President & Chief Financial Officer

Jim Shonsey - Vice President & Controller

Mark Burford - Director of Capital Markets


Ray Deacon - Pritchard Capital

Eric Hagen - Lazard Capital

Jeff Robertson - Barclays Investors

Wei Romualdo - Stone Harbor

Greg Brody - JP Morgan

Andrew Coleman - UBS

Greg Vortalon - Decade Capital


Good afternoon. My name is Litangen and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex third quarter 2009 financial results conference call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions)

I’d now like to turn the conference over to Mr. Mark Burford; please go ahead, sir.

Mark Burford

Thank you, Litangen and thank you everyone for joining us today for the Cimarex third quarter results conference call. We did issue our financial and operating results news release this morning, a copy of which can be found on our website and we will be making forward-looking statements in this conference call, so I’ll refer to the end of our press release for our forward-looking statements disclaimer at the end of the press release.

Here in Denver on the conference call we have Mick Merelli, our Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, EVP of Operations; and Paul Korus, VP and CFO; and Jim Shonsey, our Controller. We will go ahead and get moving, and I will just go ahead turn the call over to Mick Merelli.

Mick Merelli

Thanks. Thank you for joining us today on our conference call. All of our areas are having really good years. In each of these areas, our teams have adapted by cutting our costs and hard grading our opportunities and we have drilled some really good wells. You’ll hear more about that later. We generated cash flow of $181.7 million in our third quarter, which outpaced our capital expenditures for the period, which were $126.2 million.

We exited September with borrowings under our credit facility of $156 million and a net debt to cap ratio of 21%. As we discussed in our last conference call, we reduced capital expenditures significantly in 2009 in response to high service costs and weak commodity prices. Our 2009 projected exploration and production capital investment of $500 to $550 million is over 60% less than what we invested in 2008.

Our 2009 capital program is focused on three areas, our Mid-Continent gas resource, Cana play, our Permian Basin horizontal oil play, and our Gulf Coast Seismic Attribute play. I want to tell you a little bit more about those. Our Mid-Continent Anadarko-Woodford Cana play is relatively new to our company and it will have tremendous impact on what the company does and who the company is going forward.

I want to make a few comments about the play. We think it’s a very competitive play. We think it’s one of the best plays, one of the best shale resource plays. In the reason for that is and in particular in regard to our company, but the first thing is the quality of the rock. It is thick; it has above average properties. The rock itself has properties that will compete with the best shale plays that we are aware of in terms of porosity, permeability, gas in place, TOC.

That reflects itself and when we have a number of wells that have been on production for more than a year. As we look at those wells, what we see is, in the cases where we had some early mechanical failures in the real early wells and there weren’t all that many of those, but when we take those wells out, what we see is very smooth, predictable hyperbolic declines.

It gives us a lot of confidence about the early time prediction of these wells, that’s important to us because the investment decision economics are driven by the first five or six years of the wells life and from what we’re seeing, this rock is providing us predictable performance, we think, into that future. So we feel good about that.

Obviously, the ultimate reserves, the EURs, and a lot are going to be influenced by terminal decline rates and all of those things and we’ll contemplate those going forward, but the important thing is these wells are performing very well early time, the wells that we have that much a year over. On other points, with the quality of the gas, we have 1200 Btu gas and in addition to that, we have condensate in some of the wells, in a lot of the wells that are in the middle band of depth. Both of these things add to our economics on the wells. So it winds up being significant.

We have good average, NRIs, net revenue interest, because of the way that we obtained the leases and because where we’re out there, we have average NRI of something like 80%. Now, that might just be 5% better than what you see in a lot of plays, but that 5% is very important, particularly if production becomes as commodity prices get lower to make the difference in getting over to your cost of capital.

It’s in the right location for us. It’s in an industry friendly state, has lots of infrastructure for service, and you can get the gas out and it’s in one of our largest existing core operating areas. So we have a good organization to operate there. Our Tulsa office has more than 300 people in it. Now they handle more than just the Mid-Continent, but this play is in our backyard.

Opportunity size, relative to our company, our 90,000 plus acres that are in or near the core area of what we perceive to be the core area of the play has potential of multiple Tcfs on 160 acre spacing and it will be a lot more if it winds up being on 80s and we don’t know that, but Tom will be talking about that later.

Our Permian, getting back to our normal business and the things that we’ve done over the years, we have the Permian Basin oil projects. With oil prices improving and service costs have been falling, they seem to have leveled out just in the last few months. We’ve begun drilling some horizontal oil project, because of this program, we’ve grown our oil production to 30% of our total production and in the second quarter, it made up 53% of our revenue. We have a good generating team that generates our prospects. We have a large acreage position and we have a good inventory of horizontal oil drilling.

In our 3D controlled Gulf Coast Cook Mountain Yegua play, we’ve drilled the Two Sisters in the Garth discoveries and that was off a new 3D chute and they’re great wells and respectively they’re producing 40 million and 32 million cubic feet equivalent per day. Now Tom and Joe will cover each of these areas in a lot more detail.

Looking to 2010, we have a large portfolio of opportunities that, even on flat pricing will make our economics. We have continued to restrain our spending in order to stay within cash flow to allow service costs to drop. We’ve seen 20% to 30% reductions in costs, but having said that, these costs look like they’re leveling out. So we don’t really have a good reason to be holding back. I don’t think, in 2010. We’re going to have a more active program in 2010. We are finished waiting for costs to drop.

As a part of our intention to ramp up activity in 2010, we’ve hedged about half of our expected production. In our view, this is purely cash flow insurance, allowing us to better set an E&D budget and E&D kind of bottom of a range, which we could fund from our cash flow.

With that, I’m going to turn it over to Tom Jorden to cover more detail about our drilling program.

Tom Jorden

Thanks, Mick. Good morning or good afternoon to everyone, depending on where you are, operationally the third quarter was a very good one for Cimarex. As Mick said, all of our core areas are performing very, very well. We have a great balance of opportunities with Mid-Continent resource gas play, our Permian Basin horizontal oil play, and our Gulf Coast seismically controlled exploration.

We probably have the best opportunity set that we’ve ever seen while we’ve been together as a management team. We’ve made a lot of progress this year in ramping our learning curve in our Western Oklahoma Cana Woodford Shale play. Our several highly profitable horizontal oil programs are continuing to grow in the Permian, and we’ve continued to have outstanding drilling results in our Southeast Texas, seismically controlled Yegua and Cook Mountain program.

That program, as we’ve talked about, we’ve drilled two great wells this year, our Two Sisters No. 1 one which we brought on production in July at 40 million cubic feet equivalent per day, it is still producing at that rate and our Garth No. 1, which we brought online in October at 32 million cubic feet equivalent per day and those are 100% working interest wells.

So I’ll go over these in detail later in the call, but suffice it to say the Gulf Coast is having a very nice year. I’ll begin the operational highlights with a quick return recap of companywide drilling activity. During the first nine months of 2009, we drilled 94 gross or 56 net wells, completing 94% of them as producers. Our reduced operator rig count resulted in drilling 76 fewer wells this year as compared to 2009.

We’ve talked about that in prior calls as a reduction to the downturn in the economy last year. We laid our rig fleet down. We’ve been in the process this year of picking it back up. We currently have 11 operator rings drilling. That’s five in our Mid-Continent region, four in the Permian Basin and two in the Gulf Coast. As we look at 2010, we are planning on increasing that rig count significantly, by mid January; we intend to have 18 operator rigs running.

That should breakdown to eight Mid-Continent rigs, seven Permian Basin rigs, and three rigs in the Gulf Coast. As always, that’s a number that is subject to change, up or down, but that’s certainly our target. Capital expenditures for exploration and development were $126.2 million for the third quarter, bringing total exploration and development capital for the first nine months of 2009 to $366.9 million.

Fourth quarter exploration and development capital is projected to be in the range of $130 million to $180 million for a full year 2009 investment of approximately $500 million to $550 million. We will now give you a summary region by region, starting with the Mid-Continent. In the Mid-Continent we’ve drilled 52 gross or 23 net wells in the first nine months of 2009, completing 96% of those as producers and just to recap, the Mid-Continent for us is a number of different plays.

Primarily it is our Cana Woodford Shale play, but it also includes our traditional Western Oklahoma tight sand play, our Southern Oklahoma, we have a number of fields there we exploit for oily reservoirs it also includes our Texas Panhandle. We are invested $180.7 million year-to-date in these Mid-Continent plays, which amounts to about 49% of our total capital.

The majority of that drilling occurred in our Western Oklahoma Anadarko Basin, Woodford Shale Cana play where Cimarex has participated in 37 gross or 15.7 net wells this year. Currently, there are 11 gross or 6.9 net wells waiting on completion or in the process of being completed. We’ve talked about that in the past we’ve slowed our completion scheduled down while we’ve done a lot of science this year. We currently have nine operated wells cased, ready to be completed.

We are going to get those things completed just as soon as we can get frac crews mobilized and do so. Since the Cana play began in late 2007, we’ve participated in a total of 67 gross or 28.6 net wells, of which 49 gross or 18.8 net wells have been brought on production and the remainder of those wells are either in the process of being drilled or awaiting completion.

As I said, there are nine operated wells which have been on production for about a year or more. Those nine wells, on average, had an average first 30 day rate of 3.8 million cubic feet per day and we’re still producing 1.7 million cubic feet per day on average 12 months later, which calculates to a first year decline of 55%.

Now, that average 30 day rate of our existing nine wells that been on for a year or more include number of wells for which there were significant mechanical problems. So, we are certainly getting much better with our completions. We’ve run some nice wells lately and we are very optimistic about this play. In the core area where Cimarex and Devon kicked off the play and where the majority of the drilling has occurred, our average estimated ultimate recovery per well is 6.4 Bcf equivalent.

That’s our actual average based on our own well decline curve analysis. This average includes wells which we didn’t get effective fracs off or had other operational challenges. If you look at all of the wells in our core area, you see a range that goes from the low side of 2.5 Bcf equivalent to a high side of 12 Bcf equivalent or better, with the majority of these wells hitting somewhere in the middle. So we are very, very optimistic about our own results.

We had some very nice wells we brought online and as we get more and more production history, we are seeing that this play has a flatter decline characteristic than many of the Shale plays that are getting attention. Within the Cana play, as we’ve talked about in the past, we have a fairly significant acreage block that’s in the southern part of the play outside of the core area where we’ve done most of our drilling.

In our Southern area, we currently have a well drilling called the Calvert 116, and this is - Woodford Shale is approximately 150 feet thick as compared with 300 feet or more in our more heavily drilled core area. We don’t have as much well control in this area, so to the extent that we have frontier areas in this play, this Calvert is certainly a frontier well for us. The only other well we have in the area is a well called the Petri 213, which we brought on production last February.

This was when we were still struggling with our completion techniques and in completing the Petri well were only able to effectively complete three out of the nine hydraulic frac stages in the lateral. The well came on at slightly less than 1 million cubic feet a day, 30 day average, but oddly the well inclined or the production rate increased over time instead of decreasing and it hit a high of approximately 1.5 million cubic feet a day.

So we’re very interested in our results for the Calvert. We will follow it with another well in that Southern area. We are very optimistic that we will be able to make economic wells in this thinner area of the Woodford Shale. We currently have three operated rigs drilling in the Cana play and we will bring on an additional three rigs beginning in December of this year through the first quarter of 2010.

As Mick said, this is a large resource for us and it promises to be an important part of our portfolio for a long, long time. We are also working on evaluating the appropriate spacing on which to develop the Cana Woodford. We are coordinating and participating in an 80 acre or 8 wells per section pilot project and possibly even going to a 9 or 10 well per section test.

We currently expect to have this project completed by the first half of 2010, so we will drill these wells in the first and second quarter and be completing these wells in our 80 acre pilot program beginning in April. Everything we talk about when we talk about the resource potential of Cimarex, as Mick said, is based on 160 acre spacing, or four wells per section, so if this play and our pilot program gives us encouragement on 80 acre or 8 well per section spacing, it will be significant to Cimarex.

We are very excited about this play. We’re still learning a lot. There’s a lot of very good challenging science going on here at Cimarex. What we learned in the core area we feel very comfortable about the potential resource and that we are comfortable saying the potential resource is larger than our current total proved reserve base. For the play, 2 to 3 Tcf equivalent is very real and hopefully, we could go higher as we continue to learn more.

Moving on to the Permian Basin, our Permian focus for the last several years has been on horizontal oil opportunities. With improving oil prices and lower service costs, returns look very, very strong to us. We currently have four operated rigs drilling. As I said, we intend to go to seven operated rigs here in the middle of January, and those will all be working on oil projects, mostly horizontal.

For the first nine months of 2009, we have drilled 35 gross or 26 net wells, 94% of which we completed as producers. We’ve invested $108 million year-to-date in the Permian, which amounts to about 29% of our total capital.

In Southeast New Mexico, we’ve drilled this year 26 gross or 21.4 net wells, 5 gross or 4.5 net horizontal Abo wells, 17 gross or 13.6 net shallow Delaware wells, and 4 gross or 3.3 net Bone Spring wells in Southeast New Mexico. Our Abo play continues to look very promising to us.

We’ve recently brought on production our Midway 17 Federal 4H, that’s a 100% working interest. Its first 30 day average, it was 280 barrels per day. Our Drumstick 7 Federal 1H well, again 100% working interest. Its first 30 day average was 230 barrels per day. I want to emphasize that we always talk about 30 day averages, because we find that number to be the more meaningful number.

We don’t typically quote IP or flush production rates, but it’s worthy to note that our Midway well did produce well in excess of 500 barrels per day as an initial flush production rate. Other notable 30 day average rates from our Delaware wells, we’ve drilled in 2009 include our Pintail 23-5, a 100% working interest well that averaged 275 barrels a day for its first 30 days and our White City 14 Federal No. 7 horizontal well, where we have an 87% working interest. Its 30 day average was 225 barrels per day.

So this is a snapshot of what we consider to be our normal operating business in the Permian Basin. We have a number of different plays that we are currently developing. We have a number of different plays that are currently within development that we haven’t tested or we’re out leasing on. We have just a very, very nice portfolio of horizontal well plays. As I said, that would include our shallow Delaware play, our second Bone Spring in New Mexico, our Abo in Southeast New Mexico, third Bone Spring play of Ward, Winkler County in Texas.

We run our economics on a $45 flat oil price, held flat forever, that’s a NYMEX price and then we look at the local market deducts, that’s our threshold. We want to see reasonable returns at those flat prices and we’ve got a number of projects that look very, very nice to us at those oil prices.

So we’ve seen a little moderation in drilling completion costs. We’ve got some great projects both currently under development and on the drilling board, and our Permian region is just really becoming a solid, very, very nice business for us. It’s nice to have that oil in the current oil gas product price relationship. As I said, we currently have four operated rigs drilling horizontal oil wells in the Permian Basin and that’s one in West Texas and three in Southeast New Mexico.

I’ll finish with our third core area, which is the onshore Gulf Coast. Onshore Gulf Coast, we’ve drilled five gross or 4.9 net wells during the first nine months of the year. We’ve invested $71 million year-to-date in the Gulf Coast, which amounts to about 19% of our total capital. Most of the activities then are Southeast Texas Yegua/Cook Mountain play where we’ve drilled four gross or four net wells with a 75% success rate.

The drilling has primarily been in Jefferson County, Texas, right near the edge of the city limits of Beaumont. As you know, in early July 2009, we brought on production in our Two Sisters No. 1, that was 100% working interest well, 75% net revenue interest and that came on at approximately 40 million cubic feet equivalent per day, but that doesn’t tell the whole story.

That 40 million cubic feet equivalent breaks down to 25 million cubic feet of gas and 2500 barrels of oil per day, gross. It’s still currently producing at that rate. That’s obviously a very, very nice well when we quote 40 million cubic feet equivalent, that’s a 6:1 equivalence ratio of oil to gas and that 25 million feet a day and 2500 barrels of oil with the current relationship between oil price and gas price, that oil is really, really a nice product stream right out of that well.

In October 2009, we brought on production another discovery, our Garth No. 1, there it’s again 100% working interest and 75% net revenue interest. It’s currently producing at approximately 32 million cubic feet equivalent per day and that breaks down to 22 million cubic feet a day of gas and 1700 barrels a day of oil, that’s gross, so some very, very nice wells. We’re also very encouraged how these wells have confirmed our seismic amplitude versus offset interpretation and we have a number of additional drilling prospects of very, very high quality, we’re very excited about.

We have two rigs running on this play in Southeast Texas in our Yegua/Cook Mountain play. They are currently drilling another prospect off this chute, we call it the Mekong prospect and we’re currently drilling or completing the Jefferson Airplane No. 2 and Jefferson Airplane No. 3 wells. I have some timely information for you on the Jefferson Airplane No. 2 well. We logged it this morning, logged a very, very nice 130 feet of net pay. That well will be online here probably within a week to 10 days. Joe will talk about that, but our production group has raced ahead to get that well online, because we’re in a competitive situation there.

We’ve got about half a feature that is shared with a couple of competitors across our lease line. One of our competitors has drilled two wells that are currently producing in excess of 30 million cubic feet a day. So we certainly think our Jefferson Airplane No. 2 well has that kind of potential. We have a 90% working interest in that well. We’ll follow it with our Jefferson Airplane No. 3 well, which should be down here in the next couple of weeks. We think we have two more wells at least to drill within that same reservoir.

Our Gulf Coast group is really having a very nice year and it has a great prospect set behind that will bleed into next year. So our three core businesses, as Mick said our resource play in the Mid-Continent, our Permian Basin in horizontal oil project, and our Gulf Coast seismically driven high risk, high volume play are all doing very, very well and had a very good quarter.

Now, with that, I will turn the call over to Joe Albi, our Executive Vice President of Operations.

Joe Albi

Thank you, Tom, and thank you all of you for joining our call. I’ll quickly summarize our Q3 production results, along with our fourth quarter guidance and touch on where we’re seeing service costs, and then follow-up with a focus with a discussion on the focus of our production operations group during the last quarter. For Q3, we reported average net daily equivalent production of 441.5 million a day. That’s right at the midpoint of our projected guidance for the quarter of 435 million to 450 million a day.

Although we’re down 3% from our second quarter average of 454 million a day, the decline was expected and directly related to our cutback in activity in late ‘08 and early ‘09. That said, as you can gather from both Mick and Tom’s conversations, our recent increase in activity and successes in South Texas are really showing up on the radar screen and helping to offset our production decline as we enter Q4 here. I will touch more on that in just a moment.

The majority of our production drop from Q2 to Q3 came on the gas side with our oil production for the most part holding its ground. With third quarter total company oil production of 22,439 barrels a day, were essentially flat to our second quarter our second quarter average of 22,706 barrels a day.

Our Two Sisters No. 1 well, which as Tom mentioned came on in July, it has played a key role in our oil production in the quarter, accounting for 1,820 net barrels a day during the quarter or 8% of our reported total. With the recent success of that well and the program, our regional distribution of oil has shifted and will continue to shift around as we progress here in Q4 and into Q1.

At the end of Q3, our Permian regions still accounted for the majority of our oil production, producing 13,021 net barrels a day during the quarter, or about 58% of our total, while the Mid-Continent made up 22% and the Gulf Coast 18%, up from 11% in the second quarter, this, again, primarily a result of the Two Sisters well.

Both Mick and Tom mentioned this oil does continue to play a critical role in our operations. On a six to one equivalent basis, oil now makes up 30% of our total company production, up from 28% a year ago, yet is generating 53% to 55% of our total oil and gas revenues.

On the gas side, our slowdown in activity resulted in drops in both the Mid-Continent and the Permian areas, down 10% and 6% respectively from Q2 ‘09. Our Gulf Coast gas production, however, was up 31% from last quarter. Again, this was fueled by our Two Sisters well, which accounted for net gas production of 17.5 million a day during the quarter.

Our total net gas production during Q3 was 306.8 million a day with the Mid-Continent representing the lion’s share of production at 58%, followed by the Permian at 24% and the Gulf Coast at 15%. Well, during our last call, we mentioned that we were hopeful to be seeing signs of a production turnaround by the fourth quarter. We are seeing positive indications in that regard from each of the three core programs. In Cana, our equivalent net production averaged approximately 31 million a day in Q3 ‘09 and that’s up from 11 million a day in Q3 ‘08.

As Tom mentioned, we have planned increase in activity in Q4, not only with an increase in our rig count, but also an accelerated focus on the nine wells that have still yet to be completed. In South Texas, our Two Sisters No. 1 came on in July at a net equivalent rate of 30 million a day, and our Garth No. 1 came in October at a stabilized net equivalent rate of about 28 million a day.

In addition to these completions, we have two wells currently drilling which are offsetting competitor discoveries, one of which, as Tom mentioned, logged to 130 feet of pay overnight and we had a little bit of confidence in this play to the extent that we had our facilities built and the wells are drilling. The facilities build offsite at a centralized location were hooked up to our gas sales lines.

We are currently just boring our two phase line to get over to the centralized facility and we are hopeful that we can be on production within days or hours of removing or rigging off the rig that is on location. In the Permian, our third core area, our ‘09 drilling activity is at 11 million a day and keep in mind, when I mention that number, that during Q1 and Q2, that’s where we really pared back a lot of rigs.

As we move into Q4, that number should increase with our increased activity in the area during Q3 and Q4. So as a result, our fourth quarter guidance reflects the turnaround in our production and despite selling approximately 8 million a day of net equivalent production, our current modeling calls for Q4 guidance of 440 million to 455 million a day, which, after adjusting for property sales, represents a 3% increase from Q2 ‘09 using the midpoint of our guidance.

We are fairly confident in the risking we have placed on our fourth quarter inventory, but the timing of drilling and completion of the wells in queue are going to end up playing a big role in our fourth quarter volumes and of course our 2009 exit rate. With our projection for the fourth quarter, our full year guidance computes out to 455 million to 460 million a day and that locks us into the upper end of our original beginning year 2009 guidance of 440 million to 460 million a day.

As far as looking into 2010 is concerned, we are still in the midst of our planning cycle and we will be in a better position to more accurately predict our production guidance once we have completed our planning process, seen a little bit about how our fourth-quarter inventory falls out, which wells we get on when and at what rates and then of course see more of market conditions as we close the year to firm down our budget for 2010.

On the service costs side, as Mick mentioned, we seem to have seen a bottom in some of our costs. We saw a number of our drilling and completion cost components certainly bottom out during Q3, but that said, we did continue to see further cost reductions in a small number of items such as cementing, directional work, surface rentals and pipe in particular. Steel prices have been on the decline since the beginning of the year and they dropped about another 10% during Q3 alone.

These cost reductions, coupled with our continued operating efficiencies, they’ve really allowed us to put another notch in our well cost. As an example, our current Cana AFEs are running around 7 million a day and that’s down from about 8 million a day in the second quarter. Then the Permian, a typical Cherry Canyon horizontal well in the Delaware Basin, is now AFE at around 1.4 million a day down from 1.6 million a day in Q2.

Our Southeast New Mexico Bone Spring reentry is AFE for about 2 million a day. That’s down 20% from 2.4 million a day in the second quarter. So although costs are bottoming out, our efficiencies are helping to further reduce our total well cost. When you take a rearview mirror and look back, depending on the program and the well design, we’ve seen our drilling and completion costs drop anywhere from 25% to 40% since the peaks we saw in 2008.

Lastly, a few words on the focus of our production operations group during the third quarter. As we’ve mentioned in our previous calls, with a reduced exploitation budget, the group has been focused on optimizing production and trying to lower lifting costs on our base properties where they can. Through Q3, the group performed 341 projects, which totaled $38 million with a strong focused on lift and low cost, high impact recompletions.

Our emphasis on LOE continues to hit our bottom line. Through Q3, our own ‘09 production costs have averaged $46.4 million a quarter and that’s down 15% from our 2008 average of $54.7 million a quarter. Driving those reductions, the bigger cost reduction components we’ve seen 20% to 30% cost reductions in surface and wellhead equipment, water disposal, electricity and fuel, and well servicing.

On a net dollars per Mcfe basis, production costs have dropped 11.5% from $1.23 per Mcfe in ‘08 to $1.10 per Mcfe through the first three quarters of ‘09. With $38 million of exploitation capital down through Q3, we’re on track to hit the low end of our budget, beginning year budget of $50 million to $60 million, inclusive of non-op offshore platform abandonment’s, which we’re estimating to spend $12 million on during this year. Most of that capital has already been incurred.

Through Q3, a good chunk of our expenditures went towards optimizing oil and gas production via lift from Plunger Lift to conventional rod pump and/or gas lift, where applicable. Our Q4 inventory includes a continued focused on those types of projects as well as a number of select recompletion projects in all areas, as well as a handful of low risk infill drilling projects in Kansas and West Texas; so, so far so good for ‘09.

Despite property sales were at the upper end of beginning year production guidance, increased activity and recent successes in South Texas have reversed our production decline. Cost reductions and efficiencies have substantially reduced our drilling and completion AFEs and we’ve done a good job optimizing production from our base properties while lowering LOE. So we feel like we’ve made some good progress here in 2010 and now, we just need to take it the next step forward.

So with that, I will turn the call over to Paul Korus, our VP and CFO.

Paul Korus

Thank you, Joe. With our production poised to take an upturn here beginning in the fourth quarter, lower operating costs on track to have substantially lower finding costs in 2009, compared to what we’ve had in previous years. We feel very good about how we’re going to end 2009.

From an earnings and cash flow perspective, those of you that watch the gas market closely know that Mid-Continent basis differentials have evaporated and in fact, for November midweek, Mid-Continent gas was actually at a small premium to Gulf Coast gas and of course, we continue to benefit from the high Btu content of our Mid-Continent sales and we benefit from the fact that we have a greater proportion of our production coming from the Gulf Coast with these big wells that we’ve been drilling.

So like I mentioned, we should have a very strong finish to 2009, but we’re also very well positioned for 2010. As Mick, and Tom, and Joe repeatedly mentioned, we have a large inventory of things to do. We like that inventory. We like its diversity, but financially, we’re also in good shape.

Our bank debt post an October 1 property sale has been around $100 million to $120 million lately. That’s about $100 million less than it was at the end of 2008 and so we have $700 million of unused commitments on our $800 million credit facility. So we’re in great shape from that perspective.

While we’ve had several things that have contributed to ups and downs in our cash flow and our funding of CapEx this year, at the end of the day, you can simply look at it and say “Well, we sold about $115 million worth of assets and we reduced our bank debt by about a like amount.” So that’s how you can kind of think about that.

Then as we look towards our cash flow and capital expenditures for next year, we should benefit from the downside protection that we have in place in the form of our oil and gas hedges. To remind everyone, even though it’s laid out in the news release and other places, we’ve essentially put a $5 per Mcf floor under much of our Mid-Continent gas production and about a $60 floor under the bulk of our Permian Basin oil production.

Now, looked at another way, you can say that these volumes equate to roughly 1.5 of what our total company gas and oil production will average for this year and hopefully, that will be less than 50% of what we average for next year, because we should see a return to growth.

So what all that means is that, if we have another year of gas prices or weak gas prices I should say, or oil prices disappoint we should still be able to fund a $600 million to $700 million capital program, which would be up some from this year, but the floors help us take it up even more with our cash flow and of course, we have the credit facility to use as well.

Alternatively, our costless collar ceilings are high enough that, if the forward curve for gas or oil were to happen to materialize or what many analysts price forecasts are would happen to materialize, we could be positioned to fund $800 million to $900 million or perhaps even more and really prepare our production growth as we go forward.

So with that, I think its time to turn it over for questions-and-answers.

Question-and-Answer Session


(Operator Instructions) Your first question comes from Ray Deacon - Pritchard Capital.

Ray Deacon - Pritchard Capital

I had a question about the Cana step out well to the south I guess for Tom. I guess I know you talked about having one section of the Shale that you felt would be most productive and I was just wondering is that the part of the Shale that you see to the South and I guess do you feel like, by the end of this year, you may know whether the kind of Tier 1 acreages significantly bigger than that 30,000 acres you’ve talked about in the past?

Tom Jorden

When you say section, you mean vertically a stratigraphic interval?

Ray Deacon - Pritchard Capital

stratigraphic I thought you said one part of it was kind of more brittle and..

Tom Jorden

Yes, that’s correct. As we go south, the most brittle member is actually a different Stratigraphic portion of the Woodford, so we still are targeting the most brittle member as best we can identify, but it just so happens that, if you were later the logs down and correlate them, we’re currently drilling the Calvert well up into the center where we’ve done all the rest of our drilling. It is a little stratigraphically higher in this section. So we are proceeding on the same principle. There is a nice, brittle layer there.

It really is a function of our ability to effectively stimulate and then what the recoveries are. It is thinner, and we don’t I am speculating here, Ray I want to be very clear I am speculating because we don’t have any real, results, but we don’t really expect the area to the south to be as prolific as the area to the north because it is thinner. It is just a question, Cana we make very nice economic wells down there? We’ve got to get a couple of tests down before we can conclusively or probably a couple isn’t sufficient, but it will be a lot more than we know today. We are collecting data.

Ray Deacon - Pritchard Capital

I was just wondering that the other two Yegua and Cook Mountain rigs that you have operating I guess will those we will you be able to get news from those wells before year end or?

Tom Jorden

Well, we have two rigs in the Yegua and Cook Mountain, one of which well, they are both really drilling on the same prospect. One is the well I mentioned that we logged this morning. The second is a location just about 1300 feet north it is in the same reservoir and so we expect there’s a very high probability of success there.

We think both of those wells will be online here in the next well, the first one, as we mentioned, should be online in the next week or ten days and the second one is probably a few weeks behind that and we see both of those wells as having the kind of potential that our offset operator has and they have two wells making 30 million cubic a day.

Mick Merelli

That’s a competitive drainage situation; that’s why we have two rigs in the prospect.

Tom Jorden

We are probably going to have three or four wells in that prospect by the time we’re done. Then we have lots of nice prospects in the Gulf Coast Survey. So we’ll have at least those three rigs running for some time.


Your next question comes from Eric Hagen - Lazard Capital.

Eric Hagen - Lazard Capital

In terms of F&D costs, Paul, could you give us any sort of broad outline for that? As kind of a follow-up, in terms of booking PUDs with the Cana play now, do you think there’s potential to book a reasonable portion of PUDs there?

Paul Korus

Eric, one, I’m not going to let you pin me down on a number, but we’ve had our challenges with finding costs in the past. We don’t expect to have a challenge this year. Clearly, the Cana play is contributing. I mean, you listen to the drilling and completion costs, you listen to what we’re adding in terms of reserves, understand that the acreage cost was incurred last year, not this year. So we benefit from that timing difference as well.

The other thing you’ve got to remember is, one other thing, is that the price of oil is twice what it was at the end of last year, and we had a lot of negative revisions, so we’re going to get some of that back. That’s going to help. Then yes, you will see us begin to add proven undeveloped locations, per the rules, probably a conservative interpretation of the rules, in the Cana play, which is also going to help. So we’ve got a lot of things working in our favor, some of which may sound cosmetic, but some of which are very real, too. I mean we do have low costs in the Cana play.

Eric Hagen - Lazard Capital

Then moving to the Abo, could you give us an idea of what a well costs there? Do you have an EUR estimate in that play yet or...?

Tom Jorden

Our garden variety Abo well is between $3.5 million to $4 million to drill and complete and our garden variety reserves are 250,000 to 300,000 barrels.

Eric Hagen - Lazard Capital

I don’t know. Have you stated how much acreage you have in the play yet, or not?

Tom Jorden

We have, and I just can’t recall what the exact number is. We’re probably 20,000 acres, maybe 18,000. If you want to call me, Eric, I can give you an exact number. I just don’t have that in front of me.

Eric Hagen - Lazard Capital

Is that more of net or gross when you just off the top of your head?

Tom Jorden

I think that’s net. I hate to speak off-the-cuff. I have those in my office; I just don’t have them in front of me.


Your next question comes from Jeff Robertson - Barclays Investors.

Jeff Robertson - Barclays Investors

Tom, in the Cana play, can you talk a little bit about the 80-acre pilot that you all planned for the first half of 2010 in terms of what, if any, differences you’ll make in well completions and also what kind of reserve expectations you would have for increased density spaced wells?

Tom Jorden

Yes, I can tell you what we’re going to do operationally. We’ll drill four wells. We have a partner that’s going to drill five wells on their side of the lease line, so the way we’re intending it, it will be a nine-well program, or coordinate the completions, we’re still coordinate the completions. We’re still in the process of formulating our plans. There may be some simul fracs in that. We will certainly frac them all and then flow them back, we won’t produce, while we’re completing.

The big unknown is, are those going to be purely incremental reserves or will there be a fairly significant acceleration component? So we’ll certainly monitor those completions with micro-seismic. For those of you that are, unfamiliar with that, that’s a technique where we can actually monitor by putting geo-phones down-hole. They can actually sense and map the growing hydraulic fracture

We try to see, to the extent that when we hydraulically fracture a well, does its fracture network interfere with adjacent wells or does it not interfere and thereby efficiently drain its own capture or drainage area.

So those will be questions that we will be wanted to get answered and then the other question, Jeff, is going to be are the infill wells going to get the same estimate of ultimate recovery of the parent wells. While we get eight times a single well, or will there be some reduced multiple. Right now, we just don’t know and until we do that pilot program, it would be just rank speculation.

Jeff Robertson - Barclays Investors

Tom, just as a follow-up, on a pilot like that, how much time do you want to be able to evaluate the production before you feel like you have enough data to start making some determinations as to whether or not this is the right way to proceed or not?

Tom Jorden

That’s a tough question and you’ll get a different answer from anybody you ask, but you asked me, so I’ll give you my answer. I would think, within two or three months of production. We’ll know how these wells are trending. We really find that at a first 30 day average, if we look at the pressures of the well.

We look at the rate of decrease of that pressure, that we can get a pretty good idea of what kind of well it’s going to be after 30 to 40 days of sustained production. So with a project like that, when we get them all completed and online, I would guess within two or three months we’ll be able to know something fairly definitive about the results.


Your next question comes from Wei Romualdo - Stone Harbor.

Wei Romualdo - Stone Harbor

The working capital, is anything onetime in nature this quarter or do you just expect will give back some next quarter or will become a use of cash?

Paul Korus

It was very large this quarter. If you studied closely the statement of cash flows, there’s a couple of things I want to point out to you. One is actually above the line of the changes in operating assets and working capital called a change in non-current assets and liabilities of $43 million, roughly. That includes a $50 million refund of tax payments that we made in 2008 in the first half of the year, when everybody in the industry was looking like they were going to have substantial taxable income for the year 2008 and of course, then the bottom fell out.

So we got a refund of estimated payments we had made the prior year and then you see that, down below that there was quite a swing in other assets. Some of other current assets and payables, some of that is just the effect of changing prices, the effect of using up some of our current inventory of tubulars and those types of things, so a long way of saying pretty much onetime. We think that our changes in working capital will pretty much stabilize and probably round to zero.


Your next question comes from Greg Brody - JP Morgan.

Greg Brody - JP Morgan

Just two questions for you. The first one, Paul, you were suggesting that your CapEx can move around based on cash flow. I was just curious what the 18 rig program meant in terms of CapEx for next year?

Paul Korus

We don’t have that quantified yet, Greg. So I can’t give you an answer on that on the 18 rigs, but we have a very long history, just look at our numbers for the last, since Cimarex was created in 2002. If you want to go back to predecessor operations, you’re welcome to do that as well. Our capital expenditures on E&D and cash flow usually match up, within 10%, as close as we can get it, given the volatility that we have in prices and costs and those types of things.

So we would generally expect the same thing to occur in 2010. However, if we have big disappointment in gas prices again or oil prices, we do have our credit facility. It wouldn’t bother us to borrow $100 million on our credit facility if we needed to, because you’ve got to keep in mind that we will, we’re sitting here with total debt right now, which is going to be only about 85% of this year’s, 2009’s EBITDA, which is a very depressed level of EBITDA. So whether you want to look at debt to cap ratios, whether you want to look at debt coverage ratios, putting on another $100 million of bank debt would certainly not be a problem.

Tom Jorden

From an exploration standpoint, the 18 rigs is about $700 million of capital spending and so if we layer on additional obligations on our operations side and other expenditures, I would guess that it would be somewhere in the mid $800 million. It would certainly be a capital level that could sustain an 18 rig program, but as Paul said, that’s a moving target and we really haven’t finalized our 2010 plans; we are in that process.

Paul Korus

Then you have the other variable that if prices go up or even stay where the forward curve is, you are likely to see increases in service costs. If prices disappoint, you are likely to see further reductions in service costs. So, everything is related to everything.

Greg Brody - JP Morgan

Then just a final question, just in terms of acquisition opportunities is there anything out there that you’re seeing that looks interesting. What does the environment look like?

Paul Korus

We’re happy with where we’re at right now in each of our core areas, so we are not at all active in the acquisition market. That’s not to say we wouldn’t be receptive to something, but we are currently not active.


Your next question comes from Andrew Coleman - UBS.

Andrew Coleman - UBS

One was I guess staying on the M&A theme a little bit. You had in the release you had sold a small little chunk of assets there. It looks like the biggest piece of it was that field in Texas. Any chance you could tell us what the field was called?

Joe Albi

Yes, that was our Southwest Westbrook unit. Really, what it came down to is purchase this is Joe Albi that the purchase price incorporated a fair value for the upside that we saw in further development of the field. We saw there to be a fair amount of risk to that development as far as the results that we’re going to be concerned that or were concerned, but the biggest aspect to it was that, from a rate of reinvestment standpoint, that field was making about $6 million a day. We are getting fair value for the upside with the purchase price and from a rate of reinvestment standpoint, it just told us to take the money and reinvest it into a higher rate of return oil projects.

Andrew Coleman - UBS

Looking at the whole $117 million worth of properties of 28, was that a meaningful well count?

Joe Albi

Westbrook itself had a couple hundred wells to it.

Paul Korus

Yes, as a waterflood.

Joe Albi

As a big waterflood unit very old.

Andrew Coleman - UBS

The rest of those properties that you sold throughout the year, it looks like you kind of like producing wells in the 12,000 range…

Joe Albi

One was announced that operated waterflood that, again we got paid full value for the upside in the flood and I think it was making 160 net Mcf a day or something like that, and we got a very nice price for it. They are basically just not in our core areas.

Mick Merelli

That’s what it really gets down to, is that we have some assets that are in someone’s focus area and they are not in our focus area. They see value in it that we either don’t see or we won’t exploit for quite a while and so, it just makes sense, at that point, to if the price is reasonable, for them to take that asset and for us to take the money and put it someplace where we are going to spend it.

Andrew Coleman - UBS

Absolutely and then I guess the last question about that is probably because of its size, it’s not going to have a meaningful impact on LOE, but theoretically, because it is a waterflood, it would be more expensive to operate.

Joe Albi

Relative to our total LOE picture, it’s not going to drop our LOE significantly.

Andrew Coleman - UBS

Paul mentioned that differentials had narrowed significantly there in the Mid-Continent I guess are you guys looking more a hedging basis to kind of protect some of that or and I guess as the outlook unfolds, how much stability would you need to have to put a few more rigs to work there?

Paul Korus

Multiple parts to the question; one, just because the basis converges in one month does not mean that the forward curve basis converges. So where the forward curve basis is right now Mid-Continent to Henry Hub is not a whole lot different than it was when we put our hedges on earlier this year.

As it pertains to 2010, we consider ourselves done in terms of our hedging program for 2010 production. So the next question then is, “When will we begin to hedge 2011?” We have no current plans to do that over the next few months. So we can visit with you again about that when we release year end numbers in February, but between now and then, we don’t anticipate doing anything.


Your final question comes from Greg Vortalon - Decade Capital.

Greg Vortalon - Decade Capital

Tom, you’d mentioned, in your prepared remarks, some commentary around improving completion techniques in the Cana. Could you elaborate on what that means?

Tom Jorden

We’ve had quite a technical project going on this year on the proper completion techniques for the Cana play. It still is going, although we’ve had some very good recent results. We’ve experimented with various water volumes. It’s a slick water frac, predominantly, various sand volumes.

We’ve experimented with how we pump those volumes, whether we pump them in sweeps or continuous ramp in terms of our propping. We’ve experimented with acids of different types and natures and we’ve experimented with polymers. Many operators in some of these plays will use a hybrid job between slick water and some kind of a gel, typically a linear gel. We’ve experimented with all of those.

I will say our most recent completion is one where we have a little pre-pad of asset followed by some 100 mesh profit, and then our typical risen coded 4070.A volume that we settled on is somewhere between 250,000 and 350,000 pounds per stage, generally on the high side of that, usually about 400,000 gallons per stage slick water.

Cimarex is currently not using any gel. We have it on location if we need it. We’ve had a bit of a struggle from inception to date in the Cana play in that we were really having a hard time putting all of our profit away.

We would have a well that may have anywhere from 9 to 13 hydraulic fracture stages, and we may have intended to be pumping anywhere from 180,000 to 250,000 pounds of sand per stage. What happens is, you’re pumping the job, the pressure increases, the system locks up down hole and you can’t get your profit away.

Based on our completion study and putting a very good team together, both internally and in cooperation with our partner, we’ve gotten to a point where we’re fairly reliably pumping every stage we attempt and that’s been a huge technical battle for us. We’re very confident now that those nine wells we have shut in waiting on completion, we can complete them and effectively stimulate them.

Our last couple of wells has been very pleasing to us. So we’re still evolving; we’re still debating the efficacy of these polymers. We’re still debating the efficacy of the 100 mesh, but we think we have a formula that is working for us and we’re continuing to study it. Is that a long winded answer to a very short question?

Greg Vortalon - Decade Capital

No, I appreciate it. That’s what I was looking for. Switching gears a little bit down South on the Gulf Coast. I think, on the last call, you guys had mentioned that you want a little bit of time to study the Two Sisters reservoir and whether or not it was one larger structure that may need some delineation or there might be an adjacent structure. Can you kind of give your thoughts on what time has taught you about the Two Sisters?

Tom Jorden

Two Sisters has been a stellar well. I mean time has taught us that those kind of wells are wonderful. Our estimate of the volumes on that well is, it’s somewhere in the neighborhood of probably 30 Bcf. Now, we’re going to watch that and there’s still tremendous variance on that. We do have plans to offset it and drill a second well in that feature.

Then the big unknown is going to be, will that second well be in direct reservoir communication or will it tap new reserves, but we will have a second well in that feature. We intend on getting that well our current rig schedule and we will be visiting on this in Tulsa tomorrow, but our current rig schedule calls for that second well to be spend sometime here in mid November and should be online sometime around the first of the year.


At this time, there are no further questions. Gentlemen, do you have any closing remarks.

Mark Burford

Thank you everyone, for participating today on the conference call. If you have any follow up questions, please give us a ring and maybe hopefully we will see you in New York at the Banc of America/Merrill Lynch conference on Tuesday, November 17. Thanks very much for participating today and look forward to talking to you soon. Take care.


Thank you. This concludes today’s conference. You may disconnect.

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