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Cimarex Energy Co. (NYSE:XEC)

Q1 2009 Earnings Call

May 5, 2009 1:00 pm ET

Executives

Mark Burford – Director of Capital Markets

F. H. Merelli – Chairman of the Board, President & Chief Executive Officer

Thomas E. Jorden – Executive Vice President Exploration

Joseph R. Albi – Executive Vice Operations

Paul Korus – Chief Financial Officer, Vice President & Treasurer

James H. Shonsey – Vice President, Chief Accounting Officer & Controller

Salil Sharma – Highbridge Capital Management

Gregg Brody – J.P. Morgan

[Eric Hagen] – Bank of America Merrill Lynch

Brian Kuzma – Weiss Multi Strategy

Andrew Coleman – UBS

[Ray Deegan – Pritchert Capital]

Operator

Good afternoon, my name is Kayla and I will be your conference operator today. At this time I would like to welcome everyone to the Cimarex first 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) Mr. Burford you may begin your conference.

Mark Burford

We released our press release last night which is now on our website so I would point you to there if you don’t have a copy of that. We will be making forward-looking statements on this conference call and I will also refer you to the end of our press release and our SEC filings regarding forward-looking statements.

Here in Denver on today’s call we have Mick Merelli, our Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, Executive Vice President of Operations; Paul Korus, VP and CFO; and Jim Shonsey, Controller. We have a lot to cover today so I’ll go ahead and turn the call over to Mick.

F. H. Merelli

We reported first quarter results and our production was solid coming in at 489 million cubic feet a day equivalent. That was above our top end of our guidance. The upside came from our premium oil wells and obviously, to impact the first quarter or to impact this quarter those wells were drilling in the tail end of ’08 so they’re kind of carryover wells and they’re giving us good impact in ’09.

As we talked about in our last conference call we scaled back our activity. We hit a first quarter low of three operated drilling rigs and all three of those rigs are working in our Cana play. We’ve since picked up another rig that’s operating in Hardin county in our Cook Mountain Yegua play on a new shoot, Tom’s going to cover this in more detail later. That’s a new a rig and we detoured it in to Hardin County, it was headed towards the Cana play and probably will wind up there later this year.

Our 2009 capital program is focused on three areas: our Midcontinent Anadarko-Woodford Cana play makes up the bulk of our drilling activity. The play is working out very well, we have low finding costs, the wells are highly productive and our economics look good even in this low gas price environment and I think you’ll hear Tom talk a little bit about the fact that we’re still making improvements in terms of costs and our performance of the wells.

Our second area that we’re focusing on is our new 3D and our Gulf Coast Yegua-Cook Mountain play. Again, we’re drilling our first well. The prospect is a nice looking prospect and is a little larger than what we normally see there. So, relative to the other prospects in this area this one has a little bit more potential. Having said that, we still have a little risk in there.

Our third area is our Permian Basin horizontal oil projects. We wound up cutting our drilling program there back severely because of basically the oil prices headed down and the costs were really high. More recently, the oil prices have leveled out or improved but what’s really important is that our service and our drilling costs and completion costs have fallen.

So, what you’re going to see as we look at these three areas, what we’ll see going in to the year is that we’re going to maintain activity, probably increase activity a little bit in our Midcontinent Anadarko-Woodford play but we’ll start seeing in the third and fourth quarters more activity in our Cook Mountain Yegua play and our Permian horizontal.

That’s really about all I have to say. Tom is going to again, give you more detail, Tom and Joe about these areas. I’ll repeat what we’ve said before and that is as we look in to the rest of ’09 we see that we’ll be generally limit our capital programs to our cash flow. A significant amount of that capital is going to go towards our Woodford shale Cana play. We again are lucky in that we don’t have significant lease exploration or other commitments for ’09.

We’re going to increase our activity in the third and fourth quarter in our Gulf Coast and Permian Basin. Really, these are the kinds of times that Cimarex is built for. We’re a very nimble company, we cut our spending and out activities from 43 rigs to three rigs and as we look forward in to the rest of this year and next year we intend to maintain our good cash flow, our low debt and we’re going to maintain kind of a nimble approach to whatever the opportunities are for us.

With that, I’m going to turn the call over to Tom who will cover our drilling program.

Thomas E. Jorden

In the first quarter we drilled 41 gross or 24 net wells and we completed 95% of those as producers. As we’ve told you before and Mick certainly covered, we’ve sharply reduced our operating rig count beginning in the fourth quarter which cost us to drill 68% fewer wells in this first quarter of 2009 as compared to 2008. As Mick also said we had a high of 43 operated rigs running in the end of the third quarter and that went down to a low of three in this quarter.

We currently have four operated rigs drilling, three of them are in Western Oklahoma in our Anadarko-Woodford Cana play and one is in the Gulf Coast. In the first quarter we invested $142 million in exploration and development drilling and that breaks down to 48% was in the Midcontinent, 37% was in the Permian Basin, 15% was in the Gulf Coast and other. I’ll cover each region separately starting with the Midcontinent.

In the Midcontinent we drilled 26 gross or 11 net wells in the first quarter. We completed 96% of those as producers. We invested $68 million in the Midcontinent, or as I said 48% of our first quarter capital. The majority of that drilling occurred in the Anadarko Basin Woodford shale Cana play and there we participated in 17 gross or eight net wells. We’ve talked quite a bit over the last few months about or Cana play and we’ll give you a few more details here today.

Since the play begin in late 2007, Cimarex has participated in 49 wells in that trend. Now, that’s 49 out of a total of 59 that the industry has drilled or is drilling. So, if you look at the inception of the play in 2007 to current, by our count there are 59 total wells in the industry that are either drilled or drilling and we have participated in 49 of those. So, we have an excellent database to the extent that data is available in the play.

There are currently 42 wells on trend that are producing, we have an interest in 35 of those 42. We operate 20 of them. So, we operate almost half of the wells that the industry has drilled and completed in the trend. With that said, I would still underscore what we have said in the past in that we are early time in the play. There are a number of things that we’re working on to optimize and it’s a constantly evolving project.

Even though there are 59 wells drilled or drilling, are only sold if we said two thirds of it would be perspective at 168 acre spacing, that would generate over 400 drilling locations. So, we’re still at the inception of this play and its rapidly evolving. Many of the evolutions I can outline for you, one is cost, our completed well costs are now approximately $7.5 to $7.8 million and that’s down from $9 to $10 million last year.

We’re experimenting with a number of different techniques on the play as we drill and complete these wells and these include completion techniques. We’re asking the question, optimizing our completion should we use slick water or gel fracs and we’re experimenting there. We have six wells that are currently waiting on completion and we’re trying to do those one at a time as we optimize our completion techniques.

There are a number of things that we are also experimenting with, this would include the spacing between frac stages and horizontal wells, the geometry of our perforations in our horizontal wells, the type of cement and then the optimum Stratigraphy in which to land and complete these wells. So, very rapidly evolving technology on this play and we’re very optimistic that our results thus far and think our results will get better as we optimize these parameters.

Our net production for the first quarter averaged over 30 million cubic feet a day and this year with our three operated rigs plus non-operated drilling we expect to be in approximately 50 gross wells this year. We should operate approximately 22 of those gross wells. We currently have seven wells that are drilling, three of which were operating, four of which are non-operated and we have eight wells that are waiting on frac, six are our operated and two non-operated. So, a lot of activity in the play as we’ve said in the past, our results thus far are very good and we are looking forward to optimizing that.

As we look ahead to the remainder of the year we are very excited about what we have teed up in the Permian Basin. As Mick said, we laid our rig fleet down in the Permian Basin and that was for a number of reasons that would include low oil price, high cost of services and then we were trying to live within and manage our own cash flow and we had some commitments in our Anadarko Cana play that simply ate up our available cash flow. But, as we look through the remainder of the year we’re trying to free up additional cash flow and redirect it to the Permian Basin where we can.

So, in May we’re getting back out at it. We have a number of projects that we’re going to be moving ahead and I’ll talk about those here in a minute. But, for the first quarter in the Permian Basin we drilled 13 gross or 10 net wells, 92% of which were competed as producers. We invested $53 million in the Permian Basin or 37% of our first quarter capital. A lot of that capital was spent finishing our 2008 horizontal oil drilling program.

In 2008 we had about 17 rigs running in the Permian Basin and so looking in to the first quarter through March we still had a number of completions from those wells and that was quite a bit of carryover that resulted in that $53 million first quarter capital. We’ve had good results in our Permian horizontal oil plays, in fact, we’ve been delighted with our results. As I said we dropped our activity because of low oil prices and service costs. Well, what we’ve seen is improvement in oil prices and a fairly significant decrease in our service costs so a lot of our projects in the Permian Basin look very attractive to us now.

In light of these changes some select particularly horizontal oil drilling projects have become economic again and we’re planning on restarting our drilling program in the second quarter of 2009. One of the nice things about our Permian program is when we talk about Permian program it’s really Permian programs. We have a number of different areas, all of which are internally generated, seated on that core position we picked up when we purchased Magnum Hunter in 2005.

We have a number of projects from shallow casing exit reentries, we have a number of well bores that we have cased ready to go that we are going to drill, casing exit, horizontal wells and these projects are typically $1.5 to $2 million go forward to drilling complete and we’re looking at exposure of 200,000 to 300,000 barrels per well. So, extremely economic in today’s environment.

We also have in Eddy County New Mexico a wonderful shallow oil project that we’ve developed and exploited over the last few years. Our team has done a fantastic job of finding more things to do and we’ll get out there in force with seven or eight wells targeted between now and the end of the year. Our [Ozley] project that is in Eddy Chavez County New Mexico, we’re going to get back out there we’re going to be drilling two to three wells here in the next few weeks. We should get six wells drilled and completed there between now and the end of the year, four of which we’ll operate and two of which will be non-operated.

So, as we look ahead in the Permian Basin, we’re anticipating drilling completing between 24 and 31 gross wells between now and the end of the year. We have several times that in terms of opportunities ready to go and teed up. It’s a function of cost of services, the cost of our product price, of course the oil price we command and the overall cash flow that we’re generating. But, we’re trying to redirect as much as we can in to the Permian. We’re very, very excited about reactivating that program.

Then thirdly, we have our 3D seismically driven Gulf Coast onshore program. As Mick said, we’re back out drilling there and I’ll talk about that in a minute but in the first quarter we finished drilling and completed two gross or 1.9 net wells in the Gulf Coast both of which were turned on to production in the first quarter of 2009. In 2008 we shot a couple of new 3D programs that we’re just now getting started drilling in. One is our [River Fork] program in Hardin County Texas. We have a number of very nice projects in what we’ve identified as either the Yegua or Kirby sands that’s either lower Yegua or upper Cook Mountain depending on who you talk to.

We have one drilling now, it’s one of our four that’s a very nice high potential target. We typically don’t like to talk about individual wells because we run these at a 50% COS so any individual well can be a dry hole but we have a very, very nice prospect inventory there from our recently processed 3D shoot. We intend to keep that rig busy between now and the end of the year on that 3D seismically generated drilling. We should get five Yegua Cook Mountain tests now with that rig between now and the end of the year.

So, we’re continuing a pace with a little lower level of activity than we’re typically use to talking to you about but we have a great set of internally generated opportunities. We’re very excited about what our program looks like between now and the end of the year and we look forward to not only a resurging Gulf Coast program, a resurging Permian Basin program but our Anadark-Woodford shale Cana program continues to please us and we’ll march ahead and should get those 50 wells down between the beginning and end of the year.

With that I’ll turn that over to Joe Albi, our Executive Vice President of Operations.

Joseph R. Albi

I’ll briefly summarize our Q1 production results and also touch on our ’09 guidance. As well, I’ll give you an overview of our production groups current focus and then finish up on where we see current service costs. As Mick had mentioned, the carryover of our ’08 completion activity really helped to support our production levels during Q1. They really allowed us for the most part to report average net daily equivalent production of 489 million a day which was up 3% from our Q1 ’08 average of 476 million a day and slightly ahead of our guidance which we provided at 476 to 488 million a day.

Although our reduction activity resulted in our Q1 ’09 total company gas production being flat to Q1 ’08 at 339 million a day, the horizontal completion activity in the Permian boosted our Q1 ’09 total company average net daily oil production to 25,086 barrels a day setting a new record for the company and presenting a 10% increase from our Q1 ’08 average of 22,757 barrels a day. At current levels oil now makes up 31% of our net daily equivalent production which is up from 29% in Q1 ’08.

During Q1 we continued to see some nice production growth in our core areas of activity. On an equivalent basis our Q1 ’09 production in the Midcontinent and Permian areas both set new records for the company with the Midcontinent net volumes averaging 239 million a day and also up 16% from Q1 ’08 and Permian net volumes averaging 182 million a day, up 14% from Q1 ’08.

The positive impact of our Permian horizontal oil program and the Woodford shale gas program continued to be evident in our production statistics in Q1. Our Q1 ’09 Permian oil volume of 15,766 barrels of oil a day was up 31% from our Q1 ’08 average of 12,050 barrels a day while our Midcontinent gas volume of 204 million a day was up 18% from our Q1 ’08 average of 174 million a day. So, the carryover of an active program in 2008 certainly helped us in Q1 ’09 and as we’ve talked about many times before, our production growth is dependent upon our activity.

With the dramatic drop in commodity prices we simply opted to reduce activity and live within cash flow. The wild cards, just picking up activities we’ve mentioned before, our further service cost reductions and the timing and magnitude of product price recovery. We’ve seen some significant service costs reductions and Tom touched on a few of those and we’ve also seen some stability in the price of oil but we’re still in the midst of a low gas price environment and as such through Q1 we continued to run with the low rig count we had projected at the beginning of the year and therefore still anticipate the same production drop that we accounted for when we provided our full year guidance earlier this year.

Looking forward, our current modeling results and projected second quarter guidance of 444 to 456 million a day with no change to our full year guidance projection of 440 to 460 million a day. There’s a couple of things I want to point out though about our modeling, first the drop from Q 1 to Q2, it’s a about an 8% drop but it’s highly influenced by the carryover of the ’08 completion activity that we touched upon, all at the same time we’ve been running three rigs.

Secondly, with the increased activity that Tom just hit on we’re predicting shallower declines for Q3 and Q4 which we see as positive signs in our production profile. We remain bullish on our program, we’re rich in opportunity and simply find ourselves living on cash flow. Further cost reductions and price support will generate additional activity and that activity is what’s needed to provide the catalyst to get us back on track with the production growth that we established in 2007 and 2008.

As Tom mentioned, our pulse is picking up a bit. We remain active in the Woodford including non-operated wells we have now have seven wells drilling and eight wells waiting on completion while we evaluate and work towards optimizing our frac design. We have a high profile well drilling in Southeast Texas which Tom also touched on which could open up a number of leads on that shoot.

We’ve seen significant cost reductions in each one of our core areas and the recent oil price support is a positive sign for the many leads we have in our Permian program, a number of which have now made their way on to the rig schedule.

Shifting gears to our production operations group, we stated in our previous call that with the drop in commodities prices and our reduced budget the groups focus in ’09 would be directed towards improving NOI and effectively deploying a reduced exploitation budget. During Q1 we made very good strides to improve the profitability of our wells. On the production side, the group worked hard to reduce down time and maximize production via lift and compression.

On the LOE side, we made significant progress reducing cost, progress which should make its way to the bottom line here as we move in to 2009. We obtained significant cost reductions in many areas, well servicing, lease maintenance, rentals, chemicals, salt water disposal and compression. Depending on the area and the cost component, individual reductions ranged anywhere from 10% to 50% so we’ll see those flow in to our net income here as the year progresses.

We’re also stepping up our fill training in an effort to take our overall operating effort to take our overall operating efficiency to yet a higher level. As we stated in our last call, our ’09 exploitation was $50 to $60 million and during Q1 with our focus on profitability and lease operations we reduced our level of exploitation activity from that of past levels deploying about $8.5 million to the effort. But, with continued cost reductions and/or improvement in our product prices we’ll pick up our exploitation activities as we move forward through the rest of ’09.

We have a deep inventory of opportunities. As I mentioned in our last call, through our planning process we identified over $550 projects but we’ll act prudently as we move forward. We’ll be focusing on the higher impact, lower cost type projects first. Finally, I want to make a few comments on where we’re seeing drilling and completion costs before turning the call over to Paul.

Just like last quarter, we continue to see significant reductions in most all of our drilling and completion cost components. Depending on the component and of course the geographic area, costs for services have dropped anywhere from 15% to 50% since the beginning of the year. Reductions in some items are down 50% to 60% from the peaks we saw in October and November of last year.

As an example, since the beginning of the year, day rates are now down 20% to 30% and now include many rental items which were previously excluded. [Inaudible] costs are down and we’ve seen 25% to 50% reductions in directional, cementing and stimulation costs and our AFEs have come down accordingly. Tom hit on this in this discussion, current AFE for the Woodford well is now down 20% to 25% from that of an AFE in late 2008 with today’s well having a longer lateral lane and even a larger frac.

We’re seeing the same type of decreases in the Permian which already has helped to kick off activity in that program and we anticipate will accelerate activity as we move forward in to ’09 with continued reductions. So, we’ll continue to aggressively pursue additional cost reductions where we can, retool our program design where we can and maintain a focus and a simple goal and that’s to pick up our activity in a reduced cash flow environment.

With that, I’ll turn it over to Paul.

Paul Korus

I just want to cover a couple of things. Many of you have noticed that our bank debt and total debt increased by $125 million from year end to the end of the first quarter. So, we now have total debt of about $713 million. It’s up, it’s up because as prices have come down and activity has come down we were paying bills in the first quarter from activity that was conducted in the fourth quarter so you’ll see on the statement of cash flows that our cash capital expenditures were closer to $200 million versus our accrual cap ex of about $140 million.

Then, you’ll also see large swings in our working capital as payables came down and our pipe inventories went up. So, as a result you see the increase. You’re also aware that during the first quarter, or actually in April, we put in place a new credit facility with a group of 14 banks. We increased our commitments from $500 million to $800 million. Our borrowing base remained unchanged at $1 billion. We could have gotten more commitments, it would have cost us quite a bit more for the extra $200 and we really didn’t see any liquidity needs to go beyond the $800 so we sized it at that and we’re very pleased to get it done and satisfied with the cost.

Presently, we have about $350 million drawn on that facility so we have $450 unused. We’ve not changed our capital guidance, we’ve not changed our cash flow expectations so we think we’re in good shape there with adequate liquidity. Of course, the good thing about bank debt right now is cheap. Our average borrowing cost on bank debt is probably around 3%, that’s pretty attractive and you blend that with the 7 1/8th notes that we have outstanding at a similar face amount, $350 million, our overall blended cost of borrowing right now is only about 5%. So, at least there’s some good things that do happen in the current environment.

So, our credit statistics remain strong despite the large write downs that we and every other full cost company in our sector have had to take. We still have a good amount of shareholder equity and so with our $713 million of debt, our debt to cap ratio is still a pretty good looking 28%. And, if you look at our debt to EBITDA coverage, I mean if you used trailing 12 months which is kind of interesting, it would be .65 but if you look at most estimates of forward EBITDA which would be call it $500 million we’re still at a very healthy 1.5 times coverage.

Our covenants in our credit facility and other long term debt allow for 3.5 times so we remain very low levered I guess by most measures. We’re also pretty pleased with the structure of that with about 50% of it fixed at 7 1/8 and the other 50% floating.

Some other things that have come up as people have reviewed our earnings release from this morning, there was I think a quick reaction our adjusted earnings of $0.09 was below expectations that were generally more in the high teens. For those that are concerned about that I would ask that you take a closer look at the income statement and you’ll see that our core oil and gas operations performed very well but we did have a couple of swings on the income statement in our costs and expenses which pertained to operations.

You’ll see in the other operating that we had a $9 million swing and then below that in our non-operating or other income and expense we had a $5.5 million swing. So, you add those together and that’s $14.5 million or $0.11 per share and clearly the analysts were not modeling those types of things. The source of those items as I said non-operating pertains to lower cost to market adjustments on our large inventory of tubular as well as some ongoing provisions for litigation.

The other things that have come up, oil price differentials were large in the quarter, over $7 relative to the average daily average of NYMEX oil. Our differential I don’t think is out of line with what others are seeing, the pricing we are receiving in the field have been quite a bit lower than the prompt month that is recorded on the NYMEX. We are over $7, it was exactly $7.38, we’d expect that to come down to closer to $5 as we get a little less [inaudible] between the front months on NYMEX.

The gas price differential, the good news is it was a little over $1 in Q1, $1.06 down substantially from $2.25 in the fourth quarter so the good news is the differential is lower, the bad news is the price is lower. We would expect that differential to be between $0.50 and $0.60 in the second quarter. Realize that we’ve already seen the index pricing for April and May and so have a pretty good handle on that.

We’re very dependent upon gas prices in the Midcontinent. There seems to be a bit underneath in that market in the $2.50 to $2.60 range, that’s the price we’ve seen for each of the last three months so as NYMEX has plummeted, the Midcontinent level prices have been fairly stable albeit at a very low price.

With that I will turn it over to the operator for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from Salil Sharma – Highbridge Capital Management.

Salil Sharma – Highbridge Capital Management

I’m just wondering in your 10K you have some properties in the Granite Wash and I’m just wondering if you have acreage perspective for that play?

Thomas E. Jorden

We’re looking at that the last couple of days. We believe we do not but we’re doing reconnaissance.

Salil Sharma – Highbridge Capital Management

Just real quickly the second one, you mentioned $14 million charge, should analyst be treating that as a onetime charge?

Paul Korus

I will leave that up to the analysts.

Operator

Your next question comes from Gregg Brody – J.P. Morgan.

Gregg Brody – J.P. Morgan

I was just wondering if I could get your thoughts just on the acquisition opportunities out there and how that dovetails with your new credit facility expansion?

F. H. Merelli

Well, I think the easiest way to put that is we have our nose in the wind. It has to be an exceptional opportunity that would cause us to take on more debt and buy something that is of any significant size. We’re keeping an eye on it. We have dry powder and as we move in to the fall we’ll be watching it. But, you know, we really have a lot of drilling opportunity that we’re contemplating so it’s just going to be best opportunities for either our cash flow or increasing our debt.

Paul Korus

I’ll add to that Gregg, as you know especially the high yield market for issuers such as ourselves has been quite active recently. We think we’re obviously well positioned to access it when and if we choose. The dilemma of course is trading 3% money for 10% money and if we were to term out say $300 million the simple math is that’s about $21 million of additional annualized interest expense plus up front underwriting fees so that’s the economic decision.

Until we see indications that that market will not remain open for the foreseeable future to issuers like us we can afford to wait. If we find a good acquisition opportunity later this year or early next year then we could access the market at that time is our view.

Gregg Brody – J.P. Morgan

Just a question for Mick, the hedges obviously protect your cash flow and you’ve added them there so that you can keep your plan going, I’m just curious what to expect going forward in terms of a hedging program? Should we view this as a one-time sort of action or do you think that you’ll actually maintain a hedging program going forward?

F. H. Merelli

Well, I wouldn’t want to call it maintain a hedging program but I think protecting our cash flow is something we’re interested in so we’re going to be looking at that in terms of 2010. But, I can’t tell you that we’re going to or not going to I’m just saying that its under consideration.

Gregg Brody – J.P. Morgan

Just a question for Paul, you seem to have been the guy on the litigation front, any updates there?

Paul Korus

Really nothing new. The reoccurring question is when will the appeal for the appeal for the Krug suit be filed, that has not happened yet and our expectations is that it would be late fall early winter.

Gregg Brody – J.P. Morgan

Just my final question, just in terms of working capital the [inaudible] we saw this quarter, should we expect that to continue next quarter or are we at the end of the payables coming down?

Paul Korus

We think we’re at a leveling out point. Like I said, prices have stabilized so the odd things that happened, for instance paying our royalty owners in the first quarters based on November/December prices which were substantially higher, that’s what gives you the big decrease in payables and therefore a large use of cash. As we went from a very high level of drilling activity last year in third and fourth quarter and those bills came in and paying those bills in the January/February timeframe gave us a mismatch between what current capital expenditures are and the cash out the door for capital expenditures in prior periods. So, we think we’re at a leveling off point.

Gregg Brody – J.P. Morgan

Just in terms of the Permian, you mentioned that you will pick up activity there, how many rigs are you thinking about? And, just while you’re at it talk about what the current breakeven costs are there today in your estimation?

Thomas E. Jorden

We typical today don’t think about rigs but I’ll answer your question. We’ll have two or three on different projects here as we enter in to May that’s operated. Then, depending on our results and how we balance opportunity we may keep those two or three going. Certainly, I can tell you that the wish list that our Permian region has given me has seven rigs they’d like to operate between now and the end of the year so we certainly have those opportunities. Your question on breakeven price, we think at north of $45 with what we’re seeing in cost of services makes many of our plays economic. We have a couple of deeper horizontal oil plays that still need a little bit of price or decreased cost but at $45 we’ve got a lot.

Operator

Your next question comes from [Eric Hagen] – Bank of America Merrill Lynch.

[Eric Hagen] – Bank of America Merrill Lynch

Paul, on the other operating line, just to follow up on Salil’s question, how much of that will be recurring? And, can you break that down? You addressed the non-op as being marking down the tubular but what about the other $9 million.

Paul Korus

We call it other for a reason, it’s because it doesn’t lend itself to classification in to our normal operations. Clearly, what we’ve seen in this quarter is unusually high on a recurring basis so we would expect to return to kind of normal average run rates is all I could tell you.

[Eric Hagen] – Bank of America Merrill Lynch

The other question on the Woodford, any rough idea of what kind of exit rate or is it just too early to tell this year?

Joseph R. Albi

Well, our current modeling for the Midcontinent program is running around 41 million a day as an exit rate just for that program and that’s just for this year’s drilling. Tom, you may have a better number with regard to aggregate drilling from last year, I’m going to put it around 55 to 57 million a day.

Thomas E. Jorden

Mark Buford

Just to clarify that 41 is the wedge [inaudible] and the 55 is the exit rate.

Operator

Your next question comes from Brian Kuzma – Weiss Multi Strategy.

Brian Kuzma – Weiss Multi Strategy

Could you guys talk a little bit about when you look at the Yegua play and as you get back in there talk about how you high graded your portfolio and historically do you have a better success on like the first well that you drill after you do your 3D shoots and all your work?

Thomas E. Jorden

There’s nothing so exciting as the first well on a new 3D shoot. We’ve got a great prospect set. We’re really very excited about what we see but I will say that there have been instances in the past where we’ve marched out, we’ve been excited about what we see and then we get an early data point that doesn’t fit the data or contradicts the data and we go back to the drawing board. We’ve had a lot of internal debate about what we should do with our current prospect inventory.

I’ll give you a for instance, we have a couple of projects that are lined up, they really look nice to us and people are telling me they’re non-contingent and we either go ahead and move dirt and drill both of them back-to-back come hell or high water. I am very reluctant to proceed on that course because we’ve been there before. We’re going to drill our way through it, we’re going to collect the data that has kept us whole up until now and hopefully we’re going to have six to 10 or 12 prospects back-to-back on this 3D data set.

We see some great opportunities. These are rifle shots based on direct hydrocarbon indicators. We have some opportunities that are a little more sizeable then some of the typical ones we drill. We think we have some opportunities that could produce at rates that are on the high end of what we’ve seen in the trend but they’re risky. We’re running these at a 50% chance of success which means as much as we love them we think there is equal chance that they’ll be dry holes as they’ll be producers.

So, I don’t mean to dodge your question but I just will say that particularly with a new 3D shoot we need to calibrate it, we need to record our own data and make sure that the model response matches what we observe on the data and really tune it up in our first couple of wells.

F. H. Merelli

Having said that, I’d just add that we’ve never had a dry shoot.

Thomas E. Jorden

We’ve never had a dry shoot, yes.

F. H. Merelli

So, if we miss on the first one the reprocess and they beat on it and they’ll figure it out what we ought to be seeing and correlate that to the wells that we are drilling and we’ve always found things to do on every shoot so far and I don’t know what that total number of shoots are but it’s quite a few.

Joseph R. Albi

In the case of the well we’re drilling now we’re on trend with a fairly significant accumulation in the same Stratigraphic inner hole. We think it’s a lay down look alike and obviously we love it or we wouldn’t have one of four rigs drilling the opportunity.

Brian Kuzma – Weiss Multi Strategy

Can you guys talk a little bit more going back to the Woodford, you guys have tried some longer wells, you tried some gel fracs now, what do the latest IP rates look like?

Thomas E. Jorden

Our current model we haven’t changed and just to refresh for everybody our current model is a 4,000 to 4,300 foot horizontal leg depending on the lease and the particular surface location we will have anywhere from eight to 12 frac stages in that lateral, sometimes it can go from 13 to 14 depending on our spacing and that typical well as we model it will cost $7.5 million to drilling complete, it will produce 4.8 million cubic feet on average for its first 30 days of production. I want to underscore, we don’t talk about flush IP rates we talk about average 30 days and that well will ultimately produce 6.3 BCF equivalent over a 40 to 50 year reserve life.

That’s our type well. We have some that are sizably better than that and some that are sizably worse than that but our actual result for our wells that we drill 4,000 foot laterals or greater are right on with that average. We are experimenting with some different techniques. We’re going to go a little shorter stages between our fracs. We started out in the play with 500 feet interval between our fracs and now we’re going to 350 foot intervals and we have just experimented with our first gel frac as opposed to a slick water frac which is the convention in shale plays other than the Haynesville, a lot of people are putting gel fracs down.

We’re currently flowing the well back and results to date really are inconclusive. So, we really don’t have a material change in our completion. If we can get a slick water frac off we prefer that. We’re looking at a technique where we could go to a gel frac if we can’t pump a slick water frac. But again, it’s too early to tell whether that’s going to work for us or not.

Brian Kuzma – Weiss Multi Strategy

One last one, in your commenting on the Granite Wash is there something – could you compare it to all the shale plays we’re use to hearing about in terms of the variability that you see across the play? Even across your acreage position that leads you to the conclusion that you’re not going to be able to have as good horizontal wells as some of these other guys?

Thomas E. Jorden

Well, the question I was answer is are the wells that were splashed in the news this morning in and around our acreage. We would say no, they’re not. Now, we were one of the most active horizontal drillers in the Granite Wash in 2007, 2008. We had some mechanical problems with a number of those wells, we went back to the drawing board in terms of studying how best to drill and complete those wells and we’re very interested in watching the industry activity in preparation of getting back out.

We have a very nice position in the Granite Wash and I didn’t mean to answer the question do we think we don’t have exposure to the Granite Wash horizontal upside, we absolutely do. But, it looks like our acreage isn’t directly around some of the high volume wells that are being discussed out there yesterday and today.

Brian Kuzma – Weiss Multi Strategy

Could you just talk about the variability that you see across your acreage? Should I read that to mean that since your across – I guess, they’re on the other side of [Hemp] county, since you’re across the way is that a material geologic difference?

Thomas E. Jorden

Certainly, the vertical and horizontal results as you go south or even northern Wheeling county are significantly better than anywhere else on trend. So, to that extent, yes I think that’s a reservoir issue. But, we really like the Granite Wash. We find it to be extremely predictable from drilling costs, reserves and production standpoint. We need a little better gas price. So, unless we can learn something from the activity that’s going on now that operators are doing something materially different than what we have been doing we need a little better gas price.

Operator

Your next question comes from Andrew Coleman – UBS.

Andrew Coleman – UBS

I had a couple of quick questions, one is you’ve gone through every attribute there in the Woodford play except for your acreage success factor. What are you using for that?

Thomas E. Jorden

Well Andrew we don’t know what the answer is, we haven’t sampled the entire trend. There’s a core area that consumes most of the drilling activity. We drilled one or two wells that are step outs and to date if you ask well how much of our acreage is ultimately going to be perspective at some spacing, we don’t know the answer to that. So, when I quote a number of two thirds time our acreage and divided by 160 acres I am completely pulling that number out of the air.

The experimentation we’re doing with completion techniques will do a lot to opening up additional areas. One thing we do know is the area that’s currently being heavily drilled is the thickest area within the Cana play. Both Cimarex and other operators are focusing on that area. As we get out and more extensional it gets thinner but even at that we’re still well thicker than many of the areas the Arkoma Woodford that produce quite nicely.

F. H. Merelli

Put a number on that though like the thickness in the good area Tom.

Thomas E. Jorden

The thickness in the good area is 200 to 300 foot thick and the thickness in the core area is getting to 125 to 200 feet thick.

F. H. Merelli

The gas in place even in those areas is very significant and so we’re truly just trying – we’re starting off in the area that where most of the drilling has been and its radiating out and we’ll have to see just how effectively we can stimulate those other areas as we drill wells because there is plenty of gas in place to justify the drilling of the wells.

Thomas E. Jorden

That’s entirely correct Mick. Andrew, not trying to be coy with you, we really have this raging debate. I was in a technical meeting with our Tulsa engineering group who manages the project last week and we refused to believe, certainly we have just a couple of step out wells and those are on the lower end of our average and yet there are a few of us, myself included that believe that as we optimize completions, we’re going to unlock that gas in place in what is the thinner areas. So, we just don’t know how extensive the overall full scale development is going to be in our current acreage position.

F. H. Merelli

It’s going to be big.

Andrew Coleman – UBS

Second of all, just looking at the force pooling issue, you talked about this a couple of weeks ago at IPAA but I just wanted to see, as you continue on your drilling pace, have you seen more folks dropping out? Or, would you say the way to think about working interest over the last few months, the summer is probably going to be pretty consistent in terms of having all participants kind of participating in the wells?

Thomas E. Jorden

What’s been happening is if you’re a major operator out there of which there are four or five, you participate with your core interest. If you’re a small independent which is western Oklahoma is a pretty active set, they’re getting out of the well. So, we’re finding our working interest is increasing when we propose a well through force pooling we’re ending up with quite a bit more of the well than our base interest.

Now, there have been some of these smaller companies, one of the things we’ve seen lately is a number of smaller companies are attempting to sell their position. But, we’ve looked at it and we’re having a hard time putting 2008 prices on 2009 acreage.

Andrew Coleman – UBS

My last question is looking at, and I think you mentioned it at the beginning of the call so maybe this is just a clarification but, the $198 million it looks like you spent in the first quarter versus your $400 to $600 million capital budget, how’s the phasing of that going to work out over the next three quarters?

Mark Burford

We actually incurred $142 million in the first quarter. The $198 million that you mentioned is actually the cash flow so the $198 is the cash payments that we made which reflects a fair amount of 2008 activity that was paid in the first quarter of 2009. So, the statement of cash flow actually reflects the cash payments of capital as opposed to what we actually incurred. We incurred $142 million of what we expect for the full year capital.

Thomas E. Jorden

What we did is we were certainly outpacing in the first quarter because of the activity we had through the fourth quarter of 2008. So, we’ve been working at getting it balanced and right now our run rate is in balance with our current cash flow and we watch that very carefully.

Paul Korus

Which unfortunately is only about $100 million a quarter.

Operator

Your next question comes from [Ray Deegan – Pritchert Capital].

[Ray Deegan – Pritchert Capital]

I was just wondering if you could talk about the variability in the well results in the Cana? I guess, how many are – are you seeing significant variability or are the vast majority kind of in that range that you’re talking about?

Thomas E. Jorden

There are a lot of variables that we’ve found in this play and one of the variables is the Stratigraphy with which we land that lateral. The Woodford shale is not one uniformed black rock. What we find is that it has some layers that are very brittle and some layers that are very ductile and if we land the lateral in the brittle section we get a significantly better completion. So, we really micro steer these wells over a 4,000 or 4,300 lateral we may attempt to keep that well within the same 15 or 20 feet of brittle Stratigraphy.

I will say that in our last few attempts we’ve done a much, much better job of that. We’re learning and we’re getting much, much better. So, some of the wells that we’re currently waiting on completion have the entire lateral in the most brittle Stratigraphy of that entire Woodford section. So, we’re very excited to see the results of these upcoming completions. So, when you ask about variability not only do we have variability from well to well but we have variability from stage to stage within a well depending on where that well bore intersected the Woodford.

But, to answer your question, our porous wells on this trend are just a little over 1 to 2 BCF. Our best wells in this trend we think are between 9 and 10 BCF and possibly better depending on how they perform. Our average that we’re reporting and feel very solid about that our average actual well if we drill a 4,000 foot lateral or better is 6.2 BCF equivalent. But, we think we have a long ways to go in terms of optimizing.

F. H. Merelli

But that 6 is the result of [inaudible]?

Thomas E. Jorden

Yes, that has the [inaudible], that has the victories and the defeats, the 6.2 and we’re getting better so we’re expecting our average to get better. Now, how much better and how fast will it get better, that’s our number one challenge right now.

[Ray Deegan – Pritchert Capital]

One more quick one I guess, where would you expect your rig count to be assuming the strip comes to pass I suppose versus the three rigs in Cana and the one rig in Yegua Cook Mountain? And, with the Permian in there are you adding one or two rigs?

Thomas E. Jorden

Well, we have four or five wells that we’ve okayed. In 2008 we thought in terms of rigs because when you got a rig you wanted to keep it busy so we talked a lot about rig lines. Today, rigs are sitting in the weeds ready to go so we can slip in a rig, drill a well and release it. So, what I told you was our Permian group when they give us their wish list between now and the end of the year they’d like to have seven rigs, really they could take 12 if we let them have it but they’d like to have six or seven rigs continuously working. We may try to do that depending on our cash flow and how we can balance our overall expenditures.

In the Woodford shale as we talked in the past we have lots of opportunity. We have the land ready to go so depending on product price and cost of services, we could easily double or triple our rig fleet there but there are a lot of variables and I am just waving our arms over there. At $2.50 price in the Midcontinent we’re just about our cost of capital so we would need to see that strip in order to do that.

Operator

There are no further questions at this time.

Mark Burford

Thank you everyone for joining us today. We appreciate all the inquiries. If you have a follow up question, please give us a call and we look forward to talking to you more in the future. Take care, have a good day.

Operator

This concludes today’s conference call. You may now disconnect.

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Source: Cimarex Energy Co. Q1 2009 Earnings Call Transcript
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