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Cimarex Energy Co. (NYSE:XEC)

Q4 2008 Earnings Call

February 18, 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

Analysts

[Amir Bala – Liberty Mutual]

Andrew Coleman – UBS

Gregg Brody – J.P. Morgan

Jeffrey Robertson – Barclays Capital

Kevin Smith – Raymond James

Jeb Armstrong – Calyon Securities (NYSE:USA), Inc.

Operator

My name is Connie and I will be your conference operator today. At this time I would like to welcome everyone to the fourth quarter 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. Mark Burford.

Mark Burford

Thank you everyone for joining us today on Cimarex’s fourth quarter results conference call. We did issue our financial results in a news release that was put out this morning and a copy of which can be found on our website. I will point out that on today’s call we will be making forward-looking statements and at the end of that release I’ll refer you to that regarding a disclaimer 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, our Vice President and CFO; and Jim Shonsey, our Vice President and Controller. Thanks again for joining us and we’ll go ahead and jump in on the call. I’ll turn it over to Mick Merelli

F. H. Merelli

2008 was actually a good year operationally. We increased our oil and gas production by 8% to 486 million cubic feet a day equivalent. That’s the average for the year. We generated record oil and gas sales of more than $1.9 billion and our cash flow from operations increased 45% to an all time high of $1.4 billion.

Of course the collapse of commodity prices at year end took a toll on our financial results and impacted our proved reserves. That was exacerbated even more by our price realizations that were impacted even greater than what you had seen from the change in the NYMEX. Our basis blew out in the Midcontinent Permian so that during the fourth quarter our differential in these areas averaged over $3 per mcf.

The drop off in both oil and gas prices caused our reported yearend reserves to be lower and resulted in a $1 billion dollar full cost ceiling test right down. Paul Korus will cover that in more detail later in the call. Having said that, we have a very solid reserve base with over 80% of our reserves classified as proved developed. These reserves are associated and come from highly productive wells.

The reserve changes that we have, the negative changes they mainly came from cutoff of the tails of the decline curves and from puts that were loss due to lower prices. But, if you remove the price drop affect from the reported numbers, proved reserves would have grown by 8%. The proven undeveloped reserves loss because of low prices are mainly in our horizontal Permian oil plays and our Texas Panhandle gas program.

With these low prices cash flow available to reinvest in 2009 will be somewhere between $400 and $600 million and of course that’s down significantly compared to 2008. So, our capital is going to be down and we’re going to have to hydrate all of our investment projects. We have a lot of projects and we’re going to rank them all and do the ones that make sense.

Added to that is the fact that right now it makes sense for us to defer drilling. The projects can be profitable but it makes sense for us to defer the drilling to later when we hope the cost will fall and catch up with the drop in commodity prices. So, we don’t think we’ve seen the full impact on the cost of drilling to complete the wells. Again, one of the things that won’t change in our approach is that we’re going to be doubled disciplined in how we evaluate these project and which ones that we pursue.

Looking at 2009 our capital program will focus on three plays, number one is going to be our midcontinent Anadarko-Woodford play and that’s going to comprise the bulk of our drilling activity. The play has low finding costs, the wells are very productive and even in this commodity gas price environment the economics are acceptable.

The second area that we’ll be working in even though our activities will be cut down there to some degree is our Yegua-Cook Mountain Gulf Coast program mostly in Southeast Texas. We envision having a rig start up later this spring and depending on how the program proceeds we may run that rig in the program for the rest of the year.

Our third area that we’re going to focus on is our Permian basin horizontal oil projects. That activity has been really curtailed a lot and it really is going to require for that program to really pick up and present us with the kinds of opportunities that we’d take advantage of we have to have significant cost reductions so we’ll just have to see how far the drilling and completion costs fall because we have a lot of projects there to drill but they don’t make very good economic sense at current costs.

So, recapping our capital approach and general comments about our 2009 E&D capital, we’re going to spend generally what our cash flow is so we’re going to try to hold ourselves to our cash flow. Our bias is to defer until service costs decrease. We will be mostly focused on the Woodford shale. We do not have significant lease expiration issues in the Woodford or other areas.

We’re going to have a decreased level of activity in the Gulf Coast and Permian is really depending a lot on what happens to the drilling and completion costs. So, what’s going to happen is we’re going to slowdown but we’re going to continue to move forward. Along the same lines, we are really, really going to be hygrading all of our investment opportunities.

Having said all of that we’ll constantly adapt and adjust the programs and I think a lot of things are going to be changing. With our low debt we think we’re relatively well positioned to not only get through this economic slump but maybe we’ll see some opportunities come from it. We have a lot of things to drill and with our financial position it may work out that we may even look at some acquisitions later in the year or next year.

With that, I’ll turn this over to Tom and he’ll give you some more detail about drilling program.

Thomas E. Jorden

I’ll walk you through our exploration development activity for the year program by program and as we have for the past several years our program generally falls in to three major arenas: one, would be our midcontinent; second would be the Permian basin; and third, would be onshore Gulf Coast.

In aggregate in 2008 we drilled 450 gross or 277 net wells and we completed 94% of those wells as producers. Our total exploration and development capital for 2008 totaled $1.4 billion. Of that midcontinent and that would be our Andarko-Woodford play, our Texas Panhandle play and southern Oklahoma is the bulk of it. That accounted for 45% of our total capital.

The Permian basin accounted for 38% of our total capital and those are mainly horizontal oil plays and we’ve talked about those in the past, the Third Bone Spring, the Abo Wolfcamp horizontal play and we’ve also begun prosecuting a shallow horizontal play. Just by flavor of that program about 62% of our net wells in the Permian basin were horizontal oil wells and 74% of our total capital in the Permian basin were horizontal oil wells. We invested about $420 million exploration development in the Permian basin and 74% of that was horizontal oil wells that were internally generated opportunities.

In 2009 we’re looking at paring back significantly from where we were in 2008. As we discussed in our last call and in some of our operational releases, we hit a high of 42 rigs in late September. When we saw the market turned on us, when we saw commodity prices turn on us we adjusted rapidly. It’s taken us a while to finish out that existing drilling program.

We still have some wells that are in the process of being completed from that. By the end of this month we should have a rig fleet that will be somewhere between four and six rigs as a company ongoing. So, we’re looking at investing this year somewhere between $400 to $600 million of capital. As Mick said we’re going to stay within cash flow. That capital number is a bit of a moving target depending on our cash flow and that of course is a function of oil and gas realized prices.

Our Midcontinent for 2009 is getting an even larger share of our total pie, that will be around 60% of our total capital and that’s due to the Anadarko-Woodford horizontal shale play and the commitments that we have there. Now, I say it’s due to the commitments, it’s also one of our most profitable programs and it can stand quite a bit of downside sensitivity in our commodity prices.

We’ve been somewhat quite about our results in this play as we’ve been drilling and gaining information over the last year or two but today we’re willing to be increasingly forthcoming. Over the last 18 months we’ve gained a much better understanding of the basic play and we’ve seen good results from the wells we’ve drilled so far. We’ve drilled or participated in essentially every well in the play. There are only a small handful of wells out of the industry that we don’t have a working interest in so we feel we know as much as anyone about the play.

We currently have 98,700 net acres in the play. Of that 50,200 are held by production and 48,500 are term acres that have some kind of expiration to them. Those are important numbers to us because with the downturn in commodity price, with the decrease in our own cash flow, we’re managing our drilling program not only to optimize our rate of return, maximize our cash flow from our investment but also hold our acreage position. The fact that the majority of our acreage is held by production gives us the luxury of timing. For most of that we’re not under the gun to drill expiring leases.

As we talked about in our last call we completed a purchase of HBP or held by production acreage from Chesapeake in October and that was the last large remaining held by production acreage in the core of the play. We very much like that asset and are delighted to have it. A key attribute to that [inaudible] is that 88% of the 38,000 acres were held by production. Because of the uncertainty around gas markets that gives us significant flexibility with held by production acreage and timing and development and that was a critical decision in our proceeding with that purchase.

The Characteristics of the play itself are very attractive to us. In 2008 in the Anadarko-Woodford we drilled 21 wells for about nine net wells and we have a type well that we have a type well that we’re willing to talk about. Today we see the Woodford in the core area of the play. The type well is somewhere between $7.5 to $8 million to drilling complete. That type well is depending on the lease situation, the land, somewhere between a 4,400 and a 5,00 foot lateral length and we see that type well as somewhere between 6.5 and 7 bcf. So, good economics around that, those are long live reserves, good flush production.

These numbers I’m quoting are based on our own average. We have of those 21 wells that we drilled last year we have 18 of them where we think we have enough data to actually make informed statements about their ultimate recoveries so we see this play as involving somewhere between $7 and $8 million to drill and complete a well and somewhere between 6 and 7 bcf equivalent per well.

Now, I will say that there’s still a fair amount of internal debate around those numbers. Those are actual averages from our actual results. We’re still experimenting with our drilling completion techniques, we’re still sampling our acreage so it would be unfair for anyone on this call to take our net acres and divided by a spacing and say that’s our total resource potential. We certainly don’t do that internally. There are sweet spots in this play but that average that I’m quoting has sampled our acreage fairly.

We’re going to have three to four rigs in the Woodford this year running continuously and we’ll drill in the neighborhood of 20 wells this year. Our primary constraint on that is really managing around our cash flow. At one point I will say that we modeled between nine and 12 rigs running in the play. We certainly have the opportunity and a lot of question remain in this play. As I said, there’s a debate around the ultimate recovery there is a certain question as to where drilling completion costs are going.

Earlier in the year we were dealing with a $9.4 million drilling completion cost, that same well today has come down between $7.5 and $8 million and we’re experimenting with cheaper drilling and completion techniques with smaller hole size, smaller pipe and different stimulation so there’s still a lot of unknowns about this play but we’re very excited about our results. We think it’s a solid contributor for us to the ongoing future and we’ve got a great opportunity set.

One of the unknowns is ultimate spacing on this play. We’ve modeled this internally as 160 acre spacing and when I say 160 acre spacing I mean four wells per section and there’s still a question as to whether it will be down spaced to more well per section than that. Certainly, when we look at other shale plays that we monitor around the country, it wouldn’t surprise us if our own Woodford play ultimately goes to 80 acre spacing or eight wells per section. These are things that will evolve as we drill and complete.

Moving on to other areas, our Gulf Coast we have an ongoing Yegua-Cook Mountain play that will be a continuing part of our 2009 program. We currently have in our core are of the Yegua-Cook Mountain approximately 2000 square miles of 3D data. We acquired in 2008 92 new square miles of proprietary data that we haven’t drilled on yet so we have a very rich opportunity set. We’re looking forward to that being a solid contributor to our program in 2009.

Then as Mick said, in 2009 in the Permian basin we have a very rich opportunity set of horizontal oil program spread over several plays in West Texas and Southeast New Mexico. The problem with that play is it can’t stand $33 oil. We’re looking for our costs to come down significantly, we’re looking for hopefully some ongoing support in the price of oil. We’re going to need both before we reactive that program. These are all internally generated opportunities, very attractive to us from a technical standpoint but obviously the economics currently aren’t where they need to be.

We do have a Permian program that’s a reentry program that’s shallow oil that we’ll be prosecuting here in the latter half of the year that does withstand some of these lower prices but as Mick said, for our program we’re watching costs, we’re expecting our costs to come down dramatically and it’s going to take a combination of cost decrease and price increase before Permian is a significant portion of our 2009 capital.

As we go forward our strategy is pretty straight forward and it’s a three pronged approach. Our program is going to be comprised of our horizontal shale, mostly that’s the Anadarko-Woodford, our onshore Gulf Coast geophysically driven program and our Permian horizontal oil. Go forward strategically we’re positioning ourselves for those three plays to be the underpinning of our capital investment program.

So, we have a great opportunity set. Certainly, when we look today at our current cash flow we’re in a position that’s somewhat new to us and that’s we have much, much more opportunity than we do cash flow and so we’re selecting and hygrading our opportunities and funding the very best companywide. So, our regions are competing for capital and that’s kind of a new position for them but, we certainly have a very rich opportunity set.

With that, I’d like to turn the call over to Joe Albi, our Executive Vice President of Operations.

Joseph R. Albi

I’d like to briefly go over our ’08 results in production exploitation and then touch on our ’09 outlook for both the production exploitation again and then give you a quick synopsis of where we see the current market for service costs with regards to our drilling program.

We ended ’08 with a good strong fourth quarter for production. We reported net equivalent production of 493.7 million a day, that was an increase of 9 million a day over the third quarter. It was right in the middle of our guidance and we were up 5% from our third quarter ’07 average of 471 million a day.

We also recovered the majority of the volumes we lost to Hurricanes Gustav and Ike during the third and fourth quarters which in the end impacted our overall 2008 production by approximately 6.5 million a day. But, despite the storms, our strong fourth quarter brought our reported 2008 total company average net daily production up to 485.5 million a day. That’s an 8% increase from our ’07 reported average of 451 million a day but, more comparably on an apples-to-apples basis, after adjusting for property sales our ’08 production was up 10% from our 2007 levels.

During ’08 we saw very nice production gains in each one of our core areas of activity. As compared to ’07, our ’08 equivalent daily production increased 16% in the midcontinent, 15% in the Permian and 5% in the Gulf Coast. Fourth quarter also marked record quarters for regional production in both the midcontinent and the Permian. With our midcontinent region averaging 238 million a day and our Permian region averaging 176 million a day.

Year-over-year our total company gas production was up 6% during ’08 an increase driven by the high activity levels in our Texas Panhandle and Woodford shale gas programs. These programs helped to increase our average daily gas production in the midcontinent 19% from 160 million a day in ’07 to 190 million a day in 2008.

On the oil side, we also saw a nice increase there as well. Total company oil production increased 12% and this primarily was a result of, as you are all familiar with, our Permian basin horizontal oil program which helped to boost our oil production. In fact, in the Permian we saw 36% increase from ’07 going from 9,520 barrels a day in ’07 to 12,938 barrels a day in ’08.

Our high activity levels during the fourth quarter continued our upward production growth trend in to January and right now we’re looking at January falling somewhere in the range of $496 to $498 million a day. However, with our decision to cut back our rig count until costs fall back in to line with low commodity prices we anticipate a drop in our production sometime here in the middle of Q1.

Looking forward in to ’09 we’ve put various models together trying to predict our ’09 production levels and in each case we’ve built in one primary assumption and that is that we’ll live within cash flow for our capital investment. The wild card in each one of these models is the timing of when we’ll see the costs fall back in line with low commodity prices and be able to pick up our activity. If it’s early in the year we’ll pick up our production trend after a short period of production decline and if it’s later in the year we’ll see a bit longer period of decline before our production growth continues.

Based on a wide range of possible results, we’ve projected our full year production to average in the range of 440 to 460 million a day with our first quarter expected to be in a range of 476 to 488 million a day. We’ve demonstrated our assets allow for production growth however, given current market conditions and as Mick said as a precursor to this phone call here in his segment, we’re simply living on our cash flow and we’re waiting for service costs to fall back to levels encouraging our investments. The timing of this is going to have an impact obviously on our production.

Shifting gears to our exploitation efforts, last year was another successful year for our exploitation program. During ’08 our production group deployed approximately $139 million in capital, the performed 448 projects, 75 of which were drilling projects and 373 were work over recompletion and/or remedial type projects. For ’09 back in October, we actually began our ’09 production group planning process.

With the dramatic change in product prices, we’ve refocused our group and our ’09 production growth strategy around really three simple objectives: number one, increasing on net operating income by optimizing production and lowering lifting costs; number two, effectively utilizing a reduced exploitation budget; and number three, prioritizing and accelerating our focus.

We actually have a very solid inventory of exploitation opportunities that we’ve identified for ’09 and through our planning process we generated an inventory of over 550 projects which equated to about $177 million of possible activity. We culled through these projects, we hygraded them and we put together and built a targeted budget of $50 to $60 million comprising a final list of 337 projects, a wide range of varied opportunities from artificial lift, gathering and compression, salt water disposal, recompletion work overs and low risk in field drilling projects.

The majority of the inventories is falling in to make [inaudible] Permian areas as has been the case in the past. The projects have been prioritized, it is very important to us so that we focus on the low cost high impact projects here early in the year.

Outside of our exploitation efforts our production group has identified a number of action items where we’re focused on improving overall operations and lowering lifting costs. We’re ahead of the game from a standpoint of planning and now it comes down to execution.

A couple of comments on where we see the current market from a cost standpoint before I turn the call over to Paul. But, over the last month in particular we’re finally beginning to see strong indications of drilling and completion costs relief. As compared to the peak cost we saw in October ’08 we’ve seen 10% to over 40% reductions in a number of our drilling and completion related costs.

As an example, day rates have dropped anywhere from 10% to 25%, stimulation costs have dropped 30% to 40% and cementing costs have dropped by as much as 50%. Although it’s a good sign, we’re coming of a three year period where we saw drilling and completion costs in some areas increase significantly, in many instances more than two fold. With low commodity prices and a sharp drop in industry activity, as Mick pointed out, we’re optimistic that further cost reductions may be right around the corner.

So, we’re aggressively pursuing additional service cost reductions where we can and we’re retooling our drilling and completion program design where we can. We’re rethinking whole geometry, Tom mentioned some of that, our casing programs, our steering and down hole tool technologies, utilization of different types of fluid systems, challenging ourselves on stimulation design. We’re also working with all of our drilling and services contractors looking at all angles to try and reduce costs.

At the same time we’re continually evaluating program economics based on the service cost reductions that we’ve achieved and the change [inaudible] drilling and completion program design that we contemplate, all with the goal of getting our drilling program back in to gear as soon as possible.

So, with that I’ll turn it over to Paul.

Paul Korus

I think today probably the most important things for me to mention or to talk about are: one, cash flow; two, our liquidity situation; and then finally, I’ll do a little bit of explaining about the full cost ceiling test write down since not everyone is familiar with how that works.

You’ve heard Mick, Joe and Tom talk about our process of hygrading our prospects and other drilling activities and lowering costs. Certainly in this type of price environment, that’s what we need to be doing and that is what we are focused on. You also hear them mention trying to squeeze a drilling program in to about $400 million of cash flow. I know many of you think that’s very conservative, I know I have several analyst that follow us have our cash flow more in the range of $600 to $700 million so let me just talk about our $400 million case.

Right now midcontinent gas is selling for about $3.10 and our crude oil is being solid for about $33 or $34. The forward curve for both commodities assumes that prices will rise as the year unfolds. But, the fact of the matter is that the forward curve has been saying that for quite some time. I was just looking at some data, on January 2nd the forward curve said we should be getting about $5 to $6 for our gas right now, we’re not, we’re getting $3. Oil was suppose to be $45 or $50, it’s less than $35.

So, we’re just taking a look at a case that says, “Hey prices are where they are and if they remain so what will our cash flow be?” That translates in to about $30 to $35 million a month. So, if you do the math that’s how we get to our $400 million case. It’s not our forecast but it is a case that we’re obviously taking very serious and one that we’re going to choice to live with.

So, the next topic then is could we spend more if we wanted to given our existing financing arrangements? The fact of the matter is yes, we could. But, we probably need to complete some endeavors that we have currently underway. We have a revolving credit facility with a strong syndicate of banks led by JP Morgan but also comprised of many other fine banks. Our borrowing base is limited by the size of the note which is about $1 billion.

We have tried to mimic the calculations that banks do for borrowing base ourselves and even with the price deck that the banks are using we would anticipate in the new price regime our borrowing base will still be $900 million to $1 billion. Our challenge in the current environment is that when we put our facility together back in 2005 we only asked for and paid for $500 million of commitments on that credit facility. You see from our yearend disclosures that on December 31st our bank debt was about $220 million which was up from zero at the end of September.

How did we get $220 million of bank debt? Well, in December we had some convertible notes that were put to us by some of the holders which resulted in us drawing $105 million on our credit facility to fund that repurchase which was the right that the holders had to put to us. So, that was $105 and then as had been mentioned in October, we had made a $180 million purchase of additional acreage in the Woodford shale which we’re very glad we have and of course will be the bulk of our capital program in 2009.

As it turned out though, that purchase was essentially funded largely with drawing on our credit facility because our cash flow shrunk so much in November and December after we had made that purchase. So, at yearend we were at about $220. We’re currently at about $300 million of bank debt which leaves us about $200 million of liquidity, certainly a number that we can live with and are comfortable with but as Mick mentioned, we are opportunity rich.

We see the possibility that there may be some purchase opportunities we may want to take advantage of later in the year so we are presently working with our banks to redo our credit facility and increase our commitments to approximately $800 million. Hopefully by the time we report to you on our next conference call we’ll have that done. So anyway, that process is underway.

We’re also encouraged by the fact that some of our BB rated peers in our sector have been able to access the high yield market with yields or coupons somewhere around the 10% range. That’s pretty high, it’s called high yield for a reason but that is also an option that we will explore after we get our new credit facility put in place.

Those are some things that we’re working on from a finance perspective. Of course, having said all that you still need to realize that all of our credit statistics are still very strong, rival investment grade companies. Our debt to cap ratio despite the large full cost ceiling test write down last year was still 20% at the end of the year, just slightly higher than that right now. Most credit facilities and debt covenants have a provision for that your debt should not exceed three times your trailing 12 months EBITDA and ours is only about .4 times our trailing 12 months EBITDA.

In our worst case scenario of $400 million cash flow, maybe we’d be 1.5, still very, very low and of course our debt to total proved reserves is still less than $0.50 per mcfe. So, very strong credit statistics which obviously encourage us that we can indeed expand our revolving credit facility despite the tightness of credit and banks sometime begrudging wiliness to lend. So that’s what’s going on in that front.

Then on to the ceiling test and perhaps some explanation of our adjusted earnings which we describe in our news release. Of course, adjusted earnings is a non-GAAP measure of earnings and we describe that in the news release. But, as opposed to our $12, almost $13 per share loss or $1 billion loss for the year, if we adjust for the combined ceiling test write downs we had during the third and fourth quarter of $1.4 billion, after tax $2.2 billion pre-tax and also adjust for the litigation provision that we had to make which we’ve described in a couple of news releases which was $126 million pre-tax and $75 million after tax, we come up with adjusted earnings closer to a positive $600 million or $7 per share.

That’s another way of saying or reiterating what Mick said, you know 2008 was a pretty good year operationally, it just had a very lousy ending with the two events that caused large charges to our earnings. So, to those of you not familiar with the ceiling test impairment that we had to take, generally accepted accounting principles require that companies that chose to utilize the full cost accounting method versus successful efforts must evaluate the carrying value of their proved properties for possible impairment at the end of each reporting period.

So, that’s each quarter and yearend. The test to simplify it for you consists of comparing your net book value of your oil and gas properties less any deferred taxes associated with those properties to a calculated maximum carrying value which is referred to as the ceiling. The Ceiling or that maximum carrying value in turn is calculated by determining the present value of the after tax future net cash flows from your proved reserves plus the historical cost basis of any non-producing properties you have.

In other words the book value of your acreage. That ceiling is calculated using oil and gas prices in effect on the last day of the period or in the case of an annual period December 31 and then held flat forever and then you discount those cash flows by 10%. You then compare the net book value of those properties less the deferred taxes to that calculated ceiling and if you have an excess you write it off.

So that’s how we got to our two ceiling test limitations that we had, the first one at the end of the third quarter and then another at the end of the year which totaled $1.4 billion after tax or $2.2 before tax. I also need to add that prices that were used in that determination at yearend were $5.33 per mcf of gas and $36.34 per barrel of oil. Well now, we’re looking at a gas prices which is almost $2 lower than that and an oil prices that’s also about $2 lower. So, on our worry list is of course the end of this quarter so we’ll see where prices are but if they don’t improve we are of course facing another impairment.

Of course, we believe in being very transparent, we have scrubbed all of the assets on our balance sheet and we keep a list of looking at everything we have. Many of you know we have goodwill on our balance sheet, close to $700 million worth. We did look at that and evaluate it for possible impairment. There are rules to follow for it and as a result of the testing that we did we did not have to impair it.

Goodwill tests are a little bit more like companies that use successful efforts, you get to use escalated prices, we would use whatever the NYMEX curve would suggest prices would be, you can use different discount rates and you also get to use all of your reserves not just your proved but you get to use all of your probable and possible.

Of course given the opportunities we have in the Permian and the large opportunity set we have in the midcontinent Woodford shale program we have plenty of value from our probable and possible to cover our goodwill so therefore that was not impaired.

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

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from [Amir Bala – Liberty Mutual].

[Amir Bala – Liberty Mutual]

Just a couple of questions, first on the basis differentials you know midcontinent, Permian and that area, I mean obviously you’re in the $3 range now, do you anticipate that being the scenario for the remainder of the year if gas stays and NYMEX stays in the $4.50 or $5 range or do you expect those to kind of slim down a little bit?

Mark Burford

We do anticipate the differential to narrow as we go in to the second half of the year and our base of that belief is the forward curve actually indicates that and the forward curve is indicating that because of some additional expansion of the [Rex] pipeline from Missouri in to the Ohio area which should hopefully move some gas that is bottlenecking up in the [inaudible] to move to the east coast markets which would imply we have some improvements in the differentials in the midcontinent.

[Amir Bala – Liberty Mutual]

Another question was what is your calculated F&D cost for ’08?

Paul Korus

Well, there’s many different methods and calculations and of course the sales side will provide most of those. The short answer is they were too high. If you look at the so called all sources method which includes the negative revisions that we recorded to prior year estimates of proved reserves it was just a crazy number, it was $26.61 per mcfe by my calculations. Obviously, like I said that’s impacted by the negative revisions.

If you look at the money we spend on exploration and development and you look at the reserves that were added through extensions and discoveries that turns out to be $7.51 obviously, higher than the price of gas so also not good. With where prices ended up these numbers for last year are of course not acceptable. When we were making these investment decisions, many of them anyway, oil was north of $100 and gas was $9 or $10.

It is what it is and I think you heard from both Mick and Tom we’re very focused on a few programs right now so we expect to see our finding costs improve substantially along with the efforts that Joe has underway to reduce costs and our expectations of what will happen with service costs in general. We think we’ll get back in to a competitive level of finding costs.

[Amir Bala – Liberty Mutual]

Paul, one more question for you on the working capital side of it. You said your revolver was $300 million as of today. Is that primarily due to just working capital, kind of timing of spending and receipts at the end of the year or is there more to it than that?

Paul Korus

There is some of that, prices have fallen rapidly so our receipts are coming down. The decrease in the drilling program, we acted quickly but it is still slow to materialize. We peaked with 40 some rigs in September/October time frame. By the end of the year we were down to 21, by the end of January we were down to 12 and we’re soon to be down to this four or five but we are still paying the bills from the higher level of activity so there is a disconnect.

Cash receipts falling faster than our disbursements are so there is some of that. But, another way to look at it is E&D expenditures amounted to about $1.4 billion last year, cash flow amounted to about $1.4 billion also. Well, we had $180 million of acquisitions so, dollars are fudgeable but in the simplest sense you could basically look at how did we get $300 million of debt? The convertible notes put to us and the $180 million acquisition.

F. H. Merelli

And we increased our pipe inventory by over $100 million.

[Amir Bala – Liberty Mutual]

You’re at $300 right now, do you see that again, given that the convertible issue is past you know, do you see that an additional kind of draw on working capital? I’m looking at $300 million outstanding, right now you’re $500 million on the commitments, are we going to get squeezed pretty soon here? That’s kind of what I’m worrying about there.

Paul Korus

Well, we’re not worried about it. We’re obviously watching it very closely. We don’t expect to be any higher than $350 by the end of the quarter and simultaneously with that we anticipate having our commitments expanded.

Operator

Your next question comes from Andrew Coleman – UBS.

Andrew Coleman – UBS

I have a question, just looking at your firm transport, what kind of options have you looked at over the past few months and are you going to look at ahead of these new infrastructure projects coming on that might give you a little more chance to capture better basis?

Joseph R. Albi

Well, what we’ve done really in that regard is more focused on the Canadian county stuff. We’ve been working with [Oneok] who we’ve got a long term contract with to help expand our systems and ensure that we’ve got more than enough capability in their system with enough of that being dedicated to us on a throughput commitment basis. We feel like we can fund anywhere between two to nine rig and meet the commitments and be able to sell our gas. I don’t know if that’s kind of a rough way of trying to answer your question.

Andrew Coleman – UBS

So you don’t have any backhaul arrangements or other sort of foundry stuff?

Joseph R. Albi

No, it’s just getting it in to their system and getting it sold.

Andrew Coleman – UBS

A question for Paul, it looked like you guys had a fair bit of capitalized interest for the quarter. Do you expect that sort of trend to continue in ’09 or was that really related to those notes being called?

Paul Korus

No, it has nothing to do with the notes being called. What capitalized interest stems from is basically the value of the properties not being amortized times and average interest rate. The value of our properties not being amortized has risen as a result of the $180 million acreage acquisition net of costs moved up in to the costs being amortized which in turn were written off.

Andrew Coleman – UBS

Then just a clarification here for Tom, if I heard you right at the beginning it was 98,700 net acres, roughly 50,000 HBP and the balance was on term?

Thomas E. Jorden

That’s correct.

Operator

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

Gregg Brody – J.P. Morgan

You mentioned that costs are coming down, I was just curious how much is currently factored in to your operating costs and your capital spending budget?

Joseph R. Albi

Where the costs are really hitting us hardest is on this end of the drawing side. I expect that we’ll be able to see some further cost reduction on the [LOE] side, the lifting cost side. Our Permian basin New Mexico team was able to cut about 25% to 30% [LOE] and part of our ’09 production group plan is to dissect the [LOE] look at everything we can, electricity, chemicals, remedial work, is it necessary or not necessary in an effort to try and reduce those costs. But, the biggest place where costs are hurting us are on the drilling and completion side, that’s our life blood.

Gregg Brody – J.P. Morgan

You’re currently assuming numbers as of last year?

Joseph R. Albi

No, no we’re looking at those daily. Between Tom’s guys in exploration and our guys in drilling we know what it’s going to take at current price levels or even higher or lower price levels to make these projects economic and we’re looking at current cost reductions that we’ve seen as well as contemplated program designs and their effectiveness to try and understand what program economics are so we’re ready to pull the trigger at any given time.

Thomas E. Jorden

We’re seeing costs come down. It kind of depends on the basin, depends on the play but certainly in the Woodford for a new drill we’ve seen those costs come down 15% to 20% and they’re falling rapidly as the industry drops rigs many contractors are competing for services now in a way they haven’t in the past and we’re anticipating costs coming down continuingly certainly through the first half of the year.

The question is a natural fall through is where do you guys think they’ll finish? We don’t know, we’re certainly running sensitivities around a total aggregate 30% cost decrease of where we ended last year. We would love to see more than that and time will tell.

Joseph R. Albi

These prices drops have really happened over the past two or three weeks, it’s been rather sudden and I think it just falls in line with reality. You’re starting to see the rig count fall dramatically, a lot of the service companies, let’s take fracing for an example, if they had you on their books for many months, if you’re already on their books why should they lower the cost of the frac.

So, the books have been weaned down and we’re seeing dramatic decreases on the stimulation side, the cementing side upwards of 50%, day rates just within the last two or three weeks we’ve seen 10% to 25% reduction in day rates. We’re also seeing contractors be a little bit more inclined to perhaps give you a footage bid when they wouldn’t do that before. So, the climate is changing. I think it’s just starting to happen.

Gregg Brody – J.P. Morgan

You mentioned there are commitments associated with the Woodford, what are they for ’09?

Thomas E. Jorden

We currently have three rigs under long term contract and that term would have anywhere from one to three years remaining on it. We’re picking up a fourth rig here in April so we’ll have four rigs under some kind of term commitment.

Gregg Brody – J.P. Morgan

Is the fourth rig part of a previous agreement?

Thomas E. Jorden

Yes, it’s an agreement we entered in to last fall.

Gregg Brody – J.P. Morgan

What are you seeing for additional rigs? Are you seeing the terms come down or is it still a pretty tight market?

Thomas E. Jorden

We’re seeing day rates fall.

F. H. Merelli

One of the interesting points is that we have rate sensitive contracts so they’re market sensitive contracts. So, those contracts they adjust to market every six months. So, we’re tied to those rigs for over two or three years, whatever the terms are but they all have a market rate sensitive provision in them

Joseph R. Albi

That the rate will drop or go up. It does you know good to have a winner or a loser. Somebody’s blue along the way but anyways that’s more philosophical than anything else. But, the term contracts I think you’re not going to see I mean all these rigs are laid down there’s not need to term up a rig. So we’ll live through our contract commitments and when we need a rig I don’t suspect right now we’re going to have a problem pulling one in there to start drilling.

Gregg Brody – J.P. Morgan

I noticed in terms of F&D Paul mentioned what it was for ’08 do you have a sense absent provisions what it could look like in ’09 with your current capital budget?

F. H. Merelli

The finding costs, I don’t really want to get – it has so many moving parts in it. One of the things that really impacted our finding costs this year was the fact that we entered the year with $90 plus oil and we spent over $300 million of drilling horizontal oil wells in the Permian basin during that year. Now, sometime along we weren’t using $90 but we kind of felt okay about $70 and we were running downside sensitivities at $50.

Well, what happens is then you come to the end of the year and we run everything on this $36 year end price and because those programs are big and they cover large areas we had PUDs booked in there. We drilled the PUDs and then at the end of the year we didn’t PUD up the offsets. So, what happened is we spent the money drilling those wells and we didn’t book any extra reserves. As a matter of fact because the yearend reserves were lower than what we had anticipated.

It sounds like an excuse but it’s just a fact you don’t spend $300 million plus, what was it Tom?

Thomas E. Jorden

$307.

F. H. Merelli

So again, it’s an excuse and we’ll fix it and go forward but that is the heart, that and the basis blow out are the heart of our problems and frankly we never book a PUD that we won’t drill. We usually anything we book for PUDs we drill the next year. But again, I’ll say this because there is an element of what happens in the future in your question. We’ve never been involved in an honest to God gas resource play before to any extent.

So, our spots will change a little bit. The Woodford play really looks good for us. I don’t know how many of you all have studied or heard or paid any attention to what Devon has said about it but from what they said they like it too. That’s probably going to change a little bit our approach to PUDs in the future because those programs really have a lot of [inaudible] and we like the results.

Joseph R. Albi

One of the things I’d like to turn you to is those finding costs numbers also included about $325million of acreage purchases. That acreage is still here and that acreage has opportunity to put the price levels we anticipate we can either get to or that cost can get back down to if they don’t get up. Last year was a very strong year from a capital standpoint putting money towards land and that brought us tremendous opportunity for the future.

Gregg Brody – J.P. Morgan

Just on the Permian assets is the breakeven around $15 right now without thinking to economy costs improvements?

Paul Korus

It depends on the play. Some of our plays are very close to being profitable at current cost, current pricing. Some of our plays need $50 oil and some cost decrease so it really does kind of depend on the particular play. But, there’s another issue in play and that’s while we see costs coming down we’re going to defer. We’re not going to jump out there until this thing settles down a little particularly in oil.

Operator

Your next question comes from Jeffrey Robertson – Barclays Capital.

Jeffrey Robertson – Barclays Capital

Most of my questions have been answered but Tom, can you talk a little bit more about what you all can do by yourselves to lower costs on some of these wells whether it’s through different well bore designs or just getting more well experience under your belt in some of these new plays?

Thomas E. Jorden

Well, I’m just going to give you a short answer and turn it over to Joe. The drilling and completion group is under Joe’s purview and he’s done a great job getting them focused on cost but we’re looking at working with our drilling completion group in terms of hole size, that makes a tremendous difference, whether we do or don’t drill a pilot hole. Certainly, in some of our earlier wells we’ve drilled a pile whole and if you ask a geologist a pilot hole is absolutely critical and they never want to give that up but we find we can often give up a pilot hole and save a considerable amount of money.

We look at pay drilling and the efficiencies that gives. In the [inaudible] we’re looking at longer laterals. We’ve watched what they’ve done over in the Arcola basin going to considerably longer laterals and we’re considering that. Joe, do you have any comments?

Joseph R. Albi

You hit on most of them Tom. We’re challenging ourselves with let’s say casing side 7 5/8ths versus 7, 10 ¾ versus 9 5/8ths. Do we need to run a long production string or could we try and live with an intermediate string with a liner. We’re challenging where our casing points are, do we use oil based mud versus water base muds? The trade offs of benefits as far as time drilling and days saved. We’re really looking hard at our stimulation design. Can we frac with different rates or different percentages of sand or volumes of water?

So, these are all things that we’re trying to bat around at the same time service costs are dropping. What I can say rather quickly in the last month we’ve seen, as Tom mentioned, a 20% to 25% decline in that typical well cost.

F. H. Merelli

There’s one other thing too. In the Woodford well, less than 20% of the cost of that well is attributable to the day work rig costs. So, 80% of our chance to save money is associated with the stimulations and the mud and all of the other things but just the rig itself, what it costs us is less than 20% of the cost of the well. So, we have a lot of opportunities, there are a lot of things out there that can drop, a lot of services and everything and we’re starting to see those things drop.

Jeffrey Robertson – Barclays Capital

Mick, you said you have four rigs running currently?

F. H. Merelli

Yes, we have one rig running in the Permian and three running in the Woodford.

Jeffrey Robertson – Barclays Capital

One last question, on your Woodford acreage that you have purchased, did you all just buy Woodford rights or do you have rights to any other zones?

Joseph R. Albi

Woodford rights.

F. H. Merelli

Well, it depends, the term leases in general have all rights. The HBP acreage is Woodford only.

Thomas E. Jorden

The acreage block we purchased from Chesapeake was Woodford only.

Operator

Your next question comes from Kevin Smith – Raymond James.

Kevin Smith – Raymond James

I just had a few questions, also back on the Anadarko basin, what’s kind of made you comfortable to increase EURs? Is it just longer production history or better well results?

Thomas E. Jorden

These are wells that are very hard decline and then they bend and flatten out. Every one of these shale basis performs a little bit different. For those of you, and I know many of you follow the various shale places that are out there. The Marcellus shale [inaudible] than the Fayetteville or the Barnett or the Haynesville and they have their own unique production declines and their terminal rate that they’ve finally established.

We don’t have but 18 months production on any one well out there and we’re seeing some of our recent wells, we’re very encouraged, there’s a debate internally that our wells could even be a little better than we’re saying but we just don’t know right now. One of the other things that we’re finding is there’s a question about pipeline infrastructure, we’re in the closing days of laying more capacity coming out of Canadian County and some of our more recent wells have been constrained while we get that pipeline hooked up but by the middle of March that problem will be solved and we’ll be collecting a lot more data on our own wells. So, there’s a fair amount of debate.

We’re also debating what zones to be landing these laterals in, how many stages per lateral we should design, how many feet between stages, a lot of these factors have ultimate implications on the EUR or ultimate production of the well. So, we’re early time in to this.

F. H. Merelli

We are early time but the other thing that I think we probably ought to say is that when we went in to this play we had core data and the core data indicated that the quality of the rock was very, very good relative to other cores in other shales. So, it was right up there, it was a very high quality rock. Of course at that point we didn’t know whether or not it was going to be a successful horizontal shale play.

Subsequent to that in that area there have been 41 horizontal Woodford wells that have been drilled and cased. Of the 41, Cimarex has ownership and has participated in 36 of them. So, we have a lot of information, not a lot, we’re going to get a lot more, as Tom said it continues to unfold. But, we’re not totally absent information and those wells are scattered around what we think is the core area to some degree.

So, we’re moving ahead on it, we feel pretty good. You never can tell because as he said the longest production we have is 18 months. But really, at this point from everything we can see we’re very optimistic about the quality of the wells. But, we’ll have to see going forward.

Kevin Smith – Raymond James

That kind of leads me in to my next question, is it safe to assume that you participate in Devon’s 10 wells?

F. H. Merelli

Of the 41 wells that are out there Cimarex operates 17 and Devon operates 15 and of those 15 I think we’re in almost all of them and they’re in a lot of ours. There’s basically four competitors out there and it’s Devon I think and I think I read somewhere I think where they have 120,000 acres and we’ve got about 100,000 and we’re interspersed and it looks to me like we must do the core area. We have about the same kind of area because their acreage and our Chesapeake acreage is kind of next to each other, it’s intermingled.

We’ve competed to buy leases, we had an AMI, when we started this program it started with an AMI between Devon and Cimarex so we shared all of that information. I think we have most of their core information and I know they have everything that we have. So, it’s been Devon and its been Cimarex basically driving this thing ahead. There’s two other people that are drilling wells out there right now Questar has two rig running and Marathon has two rigs running so it’s starting to expand some.

But, as we view the core area of this, this is a high quality fairly – it’s not going to cover all of Southern Oklahoma, it’s a discrete high quality play we think.

Kevin Smith – Raymond James

You might have already said this, forgive me if I missed it, how many reserves have you booked in this play?

Joseph R. Albi

We have 54 b’s of true reserves booked in Woodford.

Operator

Your next question comes from Jeb Armstrong – Calyon Securities (USA), Inc.

Jeb Armstrong – Calyon Securities (USA), Inc.

First of all what are you thinking of in terms of your corporate decline rate is at this time?

Joseph R. Albi

Our base properties with the new wells that we have can decline pretty darn steep and year-over-year it’s probably close to 29% to 31% base property decline and that’s what we’re fighting every year.

Jeb Armstrong – Calyon Securities (USA), Inc.

Turning to the Yegua-Cook Mountain area, when do you think you’ll have that rig starting to drill and how many wells do you think you’ll be able to drill in that area?

Thomas E. Jorden

Our plan right now is to bring a rig in in April and start a drilling program. We have a pretty rich inventory. That said we’re still reviewing it technically. This is very detailed geophysical analysis that rifle shots based on amplitude and direct hydrocarbon indicators we are in the process of reviewing our final prospect inventory. That’s a lot of windage but what I’m really trying to say is we have to love these things and we have enough prospects that we think is going to pass muster. We’re going to have a final review of that next week.

We could easily have six or seven wells this year if we keep that rig busy. But, that’s not a promise or assurance of that. Every well we drill gives us new information and we recalibrate our data. One of the things that we’ll be doing this year, one of the things I said last year is we shot a fair amount of new data and we’re drilling our first well on it here in April. We have 92 square miles of data that we have not drilled on yet.

So, when we march out and drill on that this wouldn’t be the first time we’ve had surprises both positive and negative so we really do watch this carefully. So, we have the potential to get six or eight wells done this year but in order to do that we’ve got to love these opportunities and we’re going to need to make sure that geophysical response is very well calibrated.

Jeb Armstrong – Calyon Securities (USA), Inc.

Finally, do you sort of have a thought of what kind of acquisition you’d like to make?

F. H. Merelli

Well, the world is changed. Everybody use to make acquisitions that had brought them drilling, had lots of upside. The winner in the contest to buy it was in general the guy who put the most on the upside and everything. Pretty much now in the industry you have more opportunity than you have cash to pursue it so basically what we’ll be looking for is PDP, an acquisition that we like that has PDP and that would be pretty much it. We’re going to buy a cash flow stream out of some properties that we like and if we can buy the cash flow stream at a decent price, we’re going to buy it and if we can’t we won’t. It’s a hell of a lot simpler when you’re not putting possibles and probables and probably possibles in to your bid.

Operator

There are no further questions at this time.

Mark Burford

Thank you everyone for joining us today. We went a little longer than usual but, please if anyone has any other questions for us please feel free to gives us a call and we look forward to talking to you again in the future.

Operator

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

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Source: Cimarex Energy Co. Q4 2008 Earnings Call Transcript
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