Mick Merelli - Chairman & Chief Executive Officer
Tom Jorden - Executive Vice President of Exploration
Joe Albi - Executive Vice President of Operations
Paul Korus - Vice President & Chief Financial Officer
Jim Shonsey - Vice President & Controller
Mark Burford - Director of Capital Markets
Joe Magner - Tristone Capital
Andrew Coleman - UBS
Cimarex Energy Co. (XEC) Q2 2009 Earnings Call August 7, 2009 ET
Good morning. My name is Lynn and I’ll be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Energy second quarter 2009 financial and operations 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, you may begin your conference.
Thank you, Lynn, and thank you everyone, for joining us this morning or this afternoon for our second quarter results conference call. We did issue our financial and operating results, news release this morning a copy of which can be found on our website, and we’ll be making forward-looking statements today in this conference call and I’ll refer you to the end of our press release regarding forward-looking statements.
Here in Denver on the call today we have Mick Merelli, our Chairman and CEO; Tom Jorden, Executive Vice President of Exploration; Joe Albi, Executive Vice President of Operations; and Paul Korus, VP and CFO; and Jim Shonsey, our VP and Controller. We have a lot to cover today.
So I’ll turn the call over to Mick to jump into the details.
Thank you for joining us on today’s call. We had a very solid second quarter. All of our core areas are having a very good year and as always we talk about our portfolio of opportunities, which consist of our Cana play, which is in the Mid-Continent which is our gas resource play, our horizontal oil drilling in the Permian Basin, and our 3D seismically controlled Southeast Texas Yegua and Cook Mountain play.
In each of these plays we’ve adapted and our teams have adapted to the current environment. They’ve cut costs, high graded opportunities and in each of the areas we’ve drilled some really good wells. We generated cash flow of $153 million in the second quarter, which more than funded our capital expenditures for that period. We exited June with availability under our credit facility in excess of $450 million and a net debt to cap ratio of 27%.
So, with solid liquidity and a very strong balance sheet, we believe we’re very well positioned in this current environment. As we discussed on our last conference call, we reduced capital expenditures significantly in 2009 and that’s mainly in response to high service and drilling costs, completion costs, and even operating costs.
Our 2009 program is going to be focused on our Mid-Continent Anadarko Woodford play and we’re getting good performance, Tom will talk about that later, our reserves are going up, our cost are going down. This looks like it’s going to develop into one of the better shale plays in the country.
Our Permian horizontal projects with improving oil prices and falling drilling costs and completion costs have made a lot of our horizontal drilling projects look more attractive. We’ve had a 30% increase in our production and our oil production has grown to 30% of our production, and in the second quarter, it made up 53% of our revenue.
Our Permian effort is really moving ahead in great shape. We have a strong team that develops ideas and we have a nice inventory of horizontal oil drilling. That of course is we’ve inventoried, we have literally hundreds of inventoried locations and that inventory is driven by an acreage position that’s around 700,000 gross acres of that the net is about half of it, so it would be 350,000 to 370,000 net acres.
In our 3D seismically controlled drilling in the Gulf Coast Yegua and Cook Mountain we drilled our Two Sisters No. 1 discovery well and that was the first well on a new 3D chute that we had conducted. This is really a nice well it’s producing 40 million cubic feet a day equivalent and with the liquid part of that contributing about 2,500 barrels a day.
In addition, we’re very optimistic about this area, because on that same chute, we have a number of other opportunities that we will drill as we approach the end of this year and into next year. Tom of course is going to cover more information about all of these areas in a few minutes.
Looking forward to 2010, by the fourth quarter, we expect to begin ramping up our activity in the fourth quarter of 2009 we’re going to start ramping up our activity for 2010. We have a large inventory of opportunities all of which make good economics on price decks that are significantly lower than the strip pricing right now.
We continue to restrain our spending at this time to stay within our cash flow and still watching how service costs are dropping. We’ve seen 20% to 30% reduction in costs, and so it makes a lot of the things that we’re contemplating doing very economic under strip pricing and actually acceptable under fairly low flat pricing.
As a part of our intention to ramp up our activity in 2010, we’ve begun to hedge some of our production. We view this purely as a cash flow insurance allowing us to better set an E&D budget, which we would fund from our cash flow and potentially some modest borrowings. We plan to hedge up to about half of our 2010 expected volumes.
So, with that, I’m going to turn this over to Tom and he can tell you more about our drilling program.
Thanks, Mick and good morning or good afternoon to everyone, depending on where you are, I’m going to cover our exploration results for the quarter and some of our projections looking ahead where we think we’ll be.
Operationally, second quarter was a very good one for Cimarex and all of our core areas are performing very, very well and as Mick said when we say core areas, we mean our Mid-Continent gas resource play as one, Permian Basin, primarily horizontal drilling for oil is two, and then our onshore Gulf Coast higher risk geophysically based prospecting is our third core area.
On balance when we look at these areas, we have more opportunity and more high quality projects than anytime in our history. We have an outstanding in the Cana shale play in Western Oklahoma we’ve talked about that at length over the last couple of calls. We have several highly profitable horizontal oil programs in the Permian and we’ve had some outstanding recent drilling results with future targets to follow up in our Southeast Texas seismically controlled Yegua and Cook Mountain program.
As Mick said in that program we drilled a great well this quarter it’s arguably the best well we’ve ever drilled in our history as a company. It’s the Two Sisters No 1, it’s currently producing 40 million cubic feet equivalent per day and I’ll cover that in a little more detail later in the call. I’ll begin the operational highlights with a quick recap of companywide drilling activity.
During the second quarter we brought back a few rigs from our first quarter low of just three operator rigs. We currently have seven operator rigs, three in Western Oklahoma, three in the Permian Basin and one onshore Gulf Coast. During the first half of 2009, we drilled 65 gross or 35 net wells and completed 95% of those as producers. Our sharply reduced operator rig count resulted in drilling 74% fewer wells in the first half of 2009 as compared to 2008.
Capital expenditures for exploration and development were $98.7 million for the second quarter bringing total exploration development capital for the first six months of 2009 to $240.7 million. In the second half of 2009, exploration and production capital is picking up a bit from the second quarter pace putting our forecast to capital in the range of $500 million to $600 million for the full year. I’ll say just parenthetically our organization has adapted very well from going to the 43 operator rigs we had at the third quarter 2008 to a low of just three and now seven.
That’s not our first choice of what we would like to do, our organization is wired for high volume drilling, but they’ve spent that downtime very, very productively in terms of maturing and developing new ideas, high grading our portfolio, and is reemerging getting back to drilling we have the best opportunity set we’ve ever had, so it really is a testament to our organization that they’ve used that downtime very well.
We’ll now move on to a region of our region recap starting with the Mid-Continent. The majority of our Mid-Continent drilling occurred in the Anadarko Basin Woodford Shale Cana play where year-to-date we’ve participated in 28 gross or 11 net wells. We’ve invested $122 million year-to-date in the Mid-Continent which amounts still about half of our total capital. We continue to see outstanding results from the Cana play and we’re making great progress on improving our frac effectiveness and overall understanding of the play.
During the quarter a lot of our energy has gone into certainly taking advantage of decreased cost environment. We’ve also spent a lot of energy into optimizing our completion and we definitely seen some fruits of that. So, Cana play began in late 2007 we participated in a total of 55 wells and of these wells 43 have been brought online and the remainder are either in the process of being drilled or awaiting completion.
For our 2009 drilling, our current estimates for average gross ultimate recovery is somewhere in the neighborhood of 6.4 Bcf equivalent per well, and there’s still a fair amount of debate around that average, but that’s something that we’re currently feeling very confident in discussing.
Now this average includes certain wells which we didn’t get effective fracs off or had other operational challenges, so in that average there are a range of results that go from 2.5 Bcf to 12 Bcf per well, with a majority of the wells hitting that mid-range. We’re very excited about the play we’re working hard to hold and prove up our 94,000 net acres, and number of you are hearing that number it’s a few thousand acres down from numbers we’ve quoted in the past, and a lot of that adjustment comes from some title and other defects from our recent acquisition.
We’re currently quoting our position as 94,000 net acres slightly more than half of which is held by production. So, large resource and it will be an important part of our portfolio for a long, long time. On the cost side of the play our drilling completion group; have been doing a great job.
During the first half of 2009 the companies horizontal wells had an average completed well cost of $8 million, an average horizontal lateral length of the 3,700 feet, and an average time to drill total depth of 64 days. These costs are down from the 2008 average where we had a completed well cost of $10.3 million on average. Average horizontal lateral length was 3,500 feet, and the average time to drill the total depth was 77 days.
Joe Albi will cover our drilling completion costs in more detail. Our targets going forward we’ve seen fairly significant cost reductions and our new drill estimates are even less than that $8 million per well average. Our new drill estimates are somewhere in the $7 million to $6.5 million per well, but we don’t like to talk about actual, until we’ve actually seen those in progress, but we’ve seen costs coming down, we are very, very excited about what that means to this play.
We currently have three operator rigs drilling in the Cana play and expect to drill or participate in approximately 45 gross or 20 net wells during 2009. We also expect to bring in two additional rigs in November or December of this year. So there are currently 11 rigs operating in the play, three of those operator rigs are Cimarex rigs.
We’ve had a lot of questions, moving on to the Texas Panhandle in our greater Mid-Continent region. We’ve had a lot of questions about the Granite Wash and what our position in the Texas Panhandle means with some of these recent announcements of these 20 million or greater per day wells horizontal Granite Wash wells. We have a very nice position in the Granite Wash.
We’ve been out there drilling as one of the most active operators in the Texas Panhandle of Granite Wash for a number of years. We will drill a couple of horizontal wells here for the remainder of 2009. We’re monitoring industry activity and we don’t see our acreage position delivering that kind of potential that’s recently made the splash, but we’ll be out drilling, we’re certainly watching the activity and hope to take advantage of any new developments that the play brings.
Now, I want to move on to the Permian Basin, which is one of our three main areas. Our Permian focus is on horizontal oil, because of weak oil prices, we dropped all of our operator rigs in Permian Basin at the end of the first quarter 2009. At the end of the year, of course, we all saw what oil prices did.
With costs not catching up to it, that program just didn’t have the kind of economics we demand, but with improving oil prices and lower service costs, we brought back three operator rigs drilling horizontal oil wells, and our economics in the Permian Basin now are amongst our best economics companywide, at current oil prices and current costs, and as we look to allocate capital for 2010, we think the Permian Basin will see a significant funding.
First half of 2009 Permian Basin drilling totaled 20 gross or 15 net wells, of which only 8 gross or 5.8 net wells were drilled in the second quarter. So, a lot of that activity in the first half was actual carryover from our 2008 program. We’ve invested $70 million year-to-date in the Permian, which amounts to about 30% of our total capital.
We are working on several horizontal oil plays. We have a shallow Cherry Canyon and Brushy Canyon Delaware project in Eddy County. We have a second Bone Spring horizontal program in Southeast New Mexico. We have our Abo horizontal program in Southeast New Mexico that we’ve talked at length about, and we have a number of new plays that are under development that are very, very exciting.
So, we are very bullish about our Permian program, not only plays we’ve talked about in the past, but also new plays we’re developing. As Mick said, we have a fantastic acreage position in the Permian Basin over 300,000 net acres. We recently have undergone a project; we’ve inventoried what we have to do in the Permian Basin. If we never generate another idea, if we never leased another acre, only things we currently have on our books, and that’s well in excess of $0.5 billion of future horizontal oil drilling, so very opportunity rich in the Permian Basin.
We’re also very near reaching great economics in our Third Bone Spring play and hope to put a rig back to work there, it’s all relative. We run our economic opportunities at strip current prevailing strip prices but we’re also looking at all of our opportunities companywide at a flat price case, and currently for oil that flat price case is $45 held flat. That’s a NYMEX price less than any local market deducts. So, we want to get a reasonable return at that $45 flat oil price. With the cost reductions we’ve seen with some of our recent results that are encouraging. We are seeing quite an opportunity set that meets that hurdle.
We have a new play in Southeast New Mexico in the Second Bone Spring. We recently re-entered a well and drilled the Shugart West Federal 31 1H. We had a 93% working interest in that well. It’s producing 300 barrels a day, and this looks to be a solid test of a new program that we hope will set up not only additional reentries, but also some grassroots drilling.
We have a lot of experience doing this. Our team both from a generation standpoint and operational standpoint has a tremendous amount of experience. As we’ve said in past calls, in 2008 we invested $300 million drilling horizontal wells in the Permian Basin. A lot of the flush revenue we are seeing from oil program certainly is a direct benefit of that, and we see horizontal oil drilling as a significant part of the remainder of our 2009 but also 2010 program. Permian Basin is really firing in all cylinders right now.
In the Gulf Coast, we drilled and completed three gross or 2.9 net producers in the first half of 2009, investing $46 million year-to-date, and that amounts to about 19% of our total capital. In early July of 2009, we brought on production from our Two Sisters No.1 well, that’s a 100% working interest well, 75% net revenue interest. It’s just about in the city limits of Beaumont, just outside the city limits of Beaumont in Jefferson County.
It’s currently producing approximately 40 million cubic feet equivalent per day and that’s 25 million cubic feet of gas and 2500 barrels of oil. That oil is wonderful thing to have, it actually came online with a little higher oil yield than we had predicted and at today’s oil price, and certainly the relative difference between gas and oil, it’s generating more revenue from that oil production than the gas. So it’s very, very nice well for us.
We currently estimate the ultimate production of that well is somewhere between 20 and 40 Bcf equivalent, but that’s a very loose estimate. The well has only been online for a month and we’ll be able to dial that in much more carefully as we produce that well longer. This is the depletion drive reservoir. So with that means it is like a shale well that we talk about in the Mid-Continent that’s on a very steep decline. This well should be producing flat at a high rate for sometime before we see any decline.
The Two Sisters No.1 was drilled off by newly acquired and processed 3D seismic chute that we talked about this program at length over the last number of years. We’ve been a very active operator in this trend Yegua and Cook Mountain trend of Liberty, Jefferson, Hardin County, we drilled almost 90 wells there in the six or seven years we’ve been active. It’s a constant recharge, where we purchase or shoot new 3D data. We reprocess it, we remodel it. We go through phases, where we’ll get new surveys in and hopefully have a drilling inventory off of that.
This is our first well off of a new chute. We’re very, very encouraged with the prospect set on that new chute and we’ll be drilling quite a few analog look like prospects. Our team did a great job. It was a fantastic coordinated effort involving geology, geophysics, engineering, land and production. I’m sure, Joe Albi will comment on the amazing time that our production group took and hooking that well up. They really got that well online and selling gas in a hurry from when we logged it.
We’re also very encouraged about how this well confirmed our seismic AVL or amplitude versus offset response and the quality of additional drilling prospects we have off this chute. You’ve heard us talk from time-to-time that when we drill a new well, we like to calibrate, look at additional opportunities, make sure we’re dialed in and we’re very, very encouraged about follow ups we have. So as I said, we have one rig working on this trend in Southeast Texas and it’s currently drilling an analog prospect off that same chute.
With that, I’ll turn the call over to Joe Albi, our Executive Vice President of Operations.
Thank you, Tom. I’ll briefly summarize our Q2 production results and our ‘09 guidance and I’ll touch a bit on our current drilling and completion cost and then give you an update on the focus of our production operations group during Q2.
We closed the quarter reporting average net daily equivalent production of 454 million a day. That was at the upper end of our second quarter guidance, which was 444 million to 456 million a day. Although, we were down from our Q2 ‘08 total company average of 488 million a day, as a result of our drop in activity. Our continued focus in our core areas of activity resulted again in year-over-year gains and second quarter equivalent production in both the Permian and Mid-Continent.
As compared to Q2 ‘08, second quarter ‘09 Permian production of 168 million a day was up 3% from Q2 ‘08, while our Mid-Continent production of 221 million a day was up 1% from Q2 ‘08. Our total company oil production averaged 22,706 barrels during the quarter. That was slightly higher than our Q2 2008 average of 22,471 barrels per day.
Our production was supported primarily by our Permian region, where our second quarter production of 14,300 barrels a day was up 15% from our Q2 2008 average of 12,400 barrels a day, and this being a direct result of our horizontal oil drilling programs, that Tom just mentioned.
Permian oil now comprises about 63% of our total company oil. So it’s certainly gotten on the map in that regard. The Q2 oil volumes helped to boost our total company product mix to 30%, as Mick mentioned in Q2 2009 versus 28% in Q2 2008. It continues oil does to play an important role for us. It now makes up more than 50% of total revenues during the quarter and I think Paul or Mark may touch on that.
Our total company gas production averaged 318 million a day during the quarter with the Mid-Continent now making up 60% of our gas. Despite our slowdown activity in Woodford/Caney play helped to increase our Mid-Continent second quarter gas volumes to $190 million a day and adds up 1% from our Q2 ‘08 average of $187 million a day.
At June 30, net production from the Caney play averaged $27 million a day and that’s up more than five-fold from $5 million a day a year ago. As Tom mentioned, we’re taking somewhat of a deliberate approach on our Woodford completions trying to refine our completion techniques to optimize production, and as such we still have about a half dozen of so wells that are waiting on production.
Our hopes are that our total production from that play should equate fairly closely to what we projected early in the year with our original plan and that is to end the year with an exit rate around $50 million a day from the Caney play over the last two years of drilling that we’ve had.
As we look forward into the second half of ‘09, we see a number of positive factors that should help lessen the decline that we’ve been seeing in our production during the first half of the year. First, we’ve picked up our activity in both the Permian and south Texas, stepping our operated rig count up to seven from three that we had early in the year and Tom, just went over all this.
Secondly, we anticipate picking up the pace of our Woodford completions as we continued to refine our completion techniques. Lastly, the successful drilling of our two sisters well on the south Texas, which at current rates represents about 7% of total company production. It certainly has a big impact on production and boost our confidence a bit for continued success on that chute and the two other chutes that we have planned in the area.
As such, we’re projecting our total company production decline to begin to show signs of being arrested in Q3 and Q4, with Q3 guidance of $435 million to $450 million a day and full year guidance of $450 million to $465 million a day, this is up from our previous full year guidance of $440 million to $460 million a day primarily as a result of the successful drilling of our two sisters well. This guidance also takes into account approximately $3 million a day of net production that we sold during the year and as production that generated at $22 million in net sale proceeds.
While meeting guidance of course is dependent on our activity level and that of course is dependent on continued or further product price support as well as stable or continued reductions in service cost. During the quarter, we’ve seen further reduction in many of our service cost items.
Operating efficiencies and continued drops in day rates, directional services, tubular cost, fracking, and cementing they’re all making their way down to the bottom line, and as an example, Tom hit on a few of these numbers. In November of 2008, a typical 3,000 foot lateral Cana well frac with nine stages had a completed well cost of a bit more than $10 million.
Well during the first half of this year, our costs were running around $8 million for a Cana well, even with longer laterals and more frac stages. With what we believe, we’ve seen in terms of increased efficiencies and further cost reductions. The APs we’re preparing today for 5,000 lateral frac with 13 stages are now estimated at or below $7 million.
Meeting this cost objective, which is our intention obviously, it will result in 30% plus cost reduction from the late 2008 cost levels that we had seen. Even while we’re drilling about 1,000 foot more lateral and completing four more stages. So we’re definitely seeing some cost efficiencies and reductions in seeing it benefit the Cana program.
We’re seeing similar cost reductions in the Permian. In November a 3,000-foot TVD Southeast New Mexico, Cherry Canyon well, the 2,000 foot lateral, AFE for around $2.4 million. Today that well AFE is for about $1.7 million, that’s a 29% reduction. So we’re seeing it basin to basin, and it certainly has had a big impact in us being able to pick up activity and improve our overall drilling economics.
Lastly, a few words on our production operations’ group, and their exploitation efforts, first off I want to follow up on what Tom mentioned about the Two Sisters wells. Our production group did a fantastic job to hook up that well. We had a good portion of our production facilities assembled while the rig was still on location and the well came online with facilities included, two days after it was perforated. So I commend them for a fine job and having a distinct sense of urgency to get our production on, and as we all know that was important production to the company.
During the second quarter, the group in itself with a reduced exploitation budget, it continued its focus on optimizing production, lowering lifting cost and concentrating on our base properties. Through Q2, we performed 230 projects. They totaled $16 million in capital, and our focus was on lift and low cost high impact re-completions and other projects to reduce LOE.
We placed the strong emphasis on reducing LOE. We implemented saltwater disposal projects. We optimized compression, retooled our lift assign, refined our chemical programs, and that in conjunction with reduced costs that we’ve seen in service and fuel, they have made their way to the bottom line, and as a result, we anticipate our ‘09 LOE will be reduced from 2008 levels by 10% to 15% on an absolute basis and on a dollar per Mcfe basis in the range of 4% to 8%.
As we have stated in our previous calls, our ‘09 exploitation budget was $50 million to $60 million when we entered the year with a strong level of activity slated for the first half of the year. With this only getting down $16 million in the first half you can see that to meet that range, we are going to have to pick up the pace, and the last six months of the year.
We will probably end the year somewhere near the lower end of the range, while we do pick up activity. We will be cherry picking from, what I believe is a good solid inventory of lift and re-completion projects. We have high graded them. We will do the higher impact projects obviously first, and then we have got a handful of low risk infill drilling projects in Kansas and West Texas that with current costs and stability in the price environment have surfaced their way to the project list as well.
So with that I will turn the call over to Paul.
Thank you, Joe. Apart from just cleaning up on some things that haven’t already been mentioned, I just wanted to for sure comment that after withstanding three consecutive quarters of reporting losses, it sure feels very good to be profitable again. We managed to earn $38.8 million in the quarter. Of course that’s substantially lower than the year ago quarter.
I’m sure having everyone recalls that at that time, we and everyone else in the industry were experiencing record earnings driven by record high gas and oil prices. Our $38.8 million was despite things that are hard to anticipate, which we outlined in the news release that totaled about $13.5 million pretax and about $8.5 million after-tax. So, all-in-all from an earnings, as well as cash flow perspective we are very pleased with the quarter.
Mick has talked about our debt and a little bit about our hedging, just a few additional comments about that. Our total debt at the end of June was $706 million. That included $339 million of bank debt, which actually decreased a little bit from the end of March, when it was $345 million. So, despite all of the ins and outs that you have for accounting, if you just look at it as a dollars in, dollars out more of a shoe box approach, we were actually under-spent cash flow just very slightly during the second quarter. I will add, as things have stabilized, we actually reduced our bank debt to a little bit more in July.
We ended July at $310 million, but we do expect our pace of drilling activity to increase, but all-in-all we think we’re at a pretty stable level right now. If you look at our total debt of $706 million, again we are in great shape. It’s only about $0.50 per Mcfe of proved reserves. Our debt to trailing 12 months EBITDA is still less than one. So, obviously very, very strong credit statistics. On the bank revolver itself, just to remind everyone, we do have $800 million of commitments at the end of July. We had nearly $500 million of availability under that, so, very well positioned.
On the hedging front, that’s a new thing for Cimarex. I hope you all are getting used to it. We know why we’re doing it. We really wanted to have a more robust capital program in 2010, so we are trying to put in some call it downside protection or warm winter protection, whatever you want to call it to our cash flow.
If you look at it on an equivalent basis combining the 8,000 barrels of oil per day and 140 million of gas per day that we had hedged as our date of our last report, that’s about 190 million equivalent per day. So over the next few months, certainly by the next time we report to you, we’ll probably have added on the equivalent of another 40 million a day likely to be comprised of something around 3,000 to 4,000 barrels per day and maybe of around 20 million gas per day.
Apart from that I think I should probably comment on our gas price differential, our earnings did come in above analyst expectations. We don’t try to do that we believe there’s a lot of value in earnings forecast actually being accurate and us meeting those expectations. I think the biggest surprise was that our gas price realization came in at $3.48 and that’s the unhedged price.
If we were to actually doing hedge accounting, the $3 floors that we have in place for this year in the Mid-Continent would have actually added another $0.12 to that overall realization, but still the $3.48 surprised people that was not down a lot from the $3.83 that we reported in the first quarter, and then of course in the first quarter Henry Hub averaged about $4.90 and only $3.50 in the second quarter.
The biggest reasons for that is the fact that Mid-Continent prices have really stabilized. Our Mid-Continent index in the second quarter averaged $2.59 hence we made money on our $3 floors. Actually July and August have improved to better than $3.10 in the spot market is actually north of $3.50 right now.
So the big decline that you had at NYMEX prices and Henry Hub prices was not experienced around the rest of the country, so what happened to us in the Mid-Continent with a lesser decline also happened in the Permian Basin which is our second largest area of gas production.
The other thing is that we’re kind of down in the weeds, but I know some of you are aware that some of our liquids rich gas that is sold through plants that we don’t own, we’re paid for our gas at the wellhead, and so we get a percent of the proceeds from the natural gas liquids without getting the volumes and so that comes back to this is an enhancement of our overall gas price.
So that, I hope, explains it to most of you that want to understand it in that level of detail. The real question is what’s going to happen going forward, since our differential was only $0.02 below Henry Hub in the second quarter, clearly we would expect a third quarter to be that good, and frankly, we expect it to be better than that. So we may even begin to report a positive differential in light of the fact of like I mentioned Mid-Continent prices stabilizing some let well Henry Hub has continued to come down and still experiencing very robust natural gas liquid prices.
With that, I believe we are ready to turn it over to the operator for questions-and-answers.
(Operator Instructions) Your first question comes from Joe Magner - Tristone Capital.
Joe Magner - Tristone Capital
The well producing at 40 million a day hasn’t been on that long. It’s in the same general vicinity I believe as the Mabel Oil Well you drilled a few years ago and I think that well stayed flat for 12 months to 18 months or 24 months, you might have to remind me on that. Is that something along the lines of what you’re expecting from the Two Sisters well?
The Mabel Oil Well is in Louisiana, a different formation, a different behest entirely. So we really don’t make any analogies to the Mabel Oil Well. We’re forecasting the Two Sisters well to stay flat. Certainly, I don’t know, Joe.
The encouraging thing about the well is that it has significant flowing pressure. So when it comes down to is how fast that flowing pressure drops at these rates? Right now we’re early in the game and I would say that given the pressured performance data that we’re seeing right now it certainly looks as it could hold its own for at least three months. It could hold it longer than that, but it ultimately will be a number that we’re going to get a better feel for as we produce the well for, I’m guessing another month to get some them on all pressure data and watch our point to that.
The thing too is that these guys are kind of dancing around all of this. We’ve got a fairly good size seismic anomaly. It looks like reserves are going to be. We feel good about the reserve level, but we don’t know right now is how many wells it’s going to take to do that. There maybe a little bit of reservoir separation in that anomaly. We’re not sure.
So until we get through all of that, then if we can drain the whole thing with one well, it’s going to stay flat for a year or two. If we have to drill another one or two wells to drain the anomaly, then they’re going to decline a little faster. Right now, we’re not sure. One thing we do know, it’s a hell of a well and it’s tremendously economic project.
I would say the thing that we’re really encouraged about is that we’ve got some look alike, which in the past means that about half of them are going to produce, because there’s always something else happens. We’ve done a really good job over the years, making about 50% of these things do what we thought they were going to do. If 50% of them produced you make a ton of money.
So anyway, we’re very optimistic about it. If you hear a little bit about, what are the rates and what are the reserves? We’re just too early in it right now, but the indications make us very optimistic.
We’ve had a lot of debate about this internally and we’re not being coy here. It’s just very difficult to size these things every time. We sized it volumetrically as best we can, just looking at the size of the feature and estimated thickness of the feature, but our own experience tells us that performance is really a much better tool, and it’s going to take another certainly probably another month of production before we can say something really intelligent on the size of the reservoir based on performance.
Joe Magner - Tristone Capital
So it could be better and it could lead to I guess larger offset to the natural declines you’re experiencing, but rather be cautiously optimistic at this point in…?
The good news as Mick said, if it’s on the low side, that means that the reservoirs compartmentalize and we have a second well to drill that will probably mimic and that would mimic the original well. There also good news is this is one of a very rich prospect set or how you’re drilling analog features. We’re very optimistic about, what this program is going to deliver both in terms of value and production.
Joe Magner - Tristone Capital
What’s the AFE or the well cost on this one?
We spent I believe $9.6 million to drill and complete this well. So I think if you calculate, that’s a payout that’s less than two months on a well like that.
By the way, since you mentioned the Mabel, just see it’s still producing 6 million a day four years later.
Your final question comes from Andrew Coleman - UBS.
Andrew Coleman - UBS
I had a question on the Cana play. You guys are at that 27 million a day exit rate in the second quarter, was that right?
Actually, the $27 million is our second quarter average rate.
Andrew Coleman - UBS
Can you say what the exit rate was or with those 11 wells kind of having been brought on?
Those little bit wells were brought on, Andrew those wells were also drilled during that period with first half of the year. Only a small couple wells were completed during the second quarter. So that did not contribute all to that $27 million. So seven wells waiting on completion, so those well we drilled the first half of the year all were not completed, Andrew. So the $27 million actually wasn’t too dissimilar for the average for the quarter. So we didn’t have a real big ramp up in the end of the quarter for completions.
One of the things that is going on there, when we’re talking about the Caney play and I want Tom or Joe just jump in, they know a lot more about it than I do, but we’ve really seen a significant, what we are hoping are going to be significant changes in our stimulation approach and results.
Finally, we’re finding some things that really have the potential to make some difference and we’re in the middle of that. So that’s why we’re stimulating these wells in series, and some of the things that we’re doing look like they have some good promise, and in addition to that, the drilling has really seen some interesting twists and turns.
As you know, Devon has a big position in this play and they’re a very good operator. Of course, we’re partners in a lot of each others wells, so we operate some wells that they’re in and they operate wells that we’re in. Actually, it winds up being most of what we do they’re in and most of what they do, it just kind of works out, because the way the acreage is scattered that we see each other a lot. Recently, Devon has done some wonderfully, very good job of drilling the vertical portion of their holes.
So we’re very optimistic that there’s the potential, because we learn from each other pretty quickly as you might expect we probably learn more from them than they do from us, but we learn it pretty darn fast and so whatever things they’re able to accomplish in terms of drilling the wells or stimulating them or anything else, we get the advantage of it and vice versa. So the days to drill the wells and the cost and the effectiveness of the stimulations, we’re really starting to see some of those things come together for us.
So I’m very optimistic about that and the numbers that Tom and Joe have talked about really don’t have a lot of that in them. So future, I guess this is typical of the resource play. Future looks kind of bright. We really feel like this is going to be one of the, may not be as big as some of the other plays, but it’s going to rank right up there with the quality wise with the best of the plays onshore U.S.
Andrew Coleman - UBS
If the play does start to develop and pick up a little more steam, would you hazard a guess as to what a gross rate count for the whole play might look like?
I would guess, if things continue to improve, you’ll see 17 to 20 rigs operating out there by next summer. No, that’s total industry. That’s not Cimarex, that’s industry.
The other thing is though the chapter that is, it depends on what the realizations are. It depends on a lot of things. Half of our acreage position is HBP and we’re a company that has Yegua and Cook Mountain wells to drill and we’ve got a lot of horizontal oil wells to drill in the Permian. As we move ahead in this thing, this isn’t a race to complete the Cana area. It’s a good area and we’ll put money in it, but we’ve got a lot of areas to put money in and we’re going to measure ourselves.
We may run our debt up in 2010 to some degree, because we have a lot of opportunities, but how fast we develop this and I don’t know about anybody else, but how fast we develop it is, it’s going to be a measured thing, and because we have the luxury to some extent of taking a measured approach.
Andrew Coleman - UBS
No, I don’t have an issue with that kind of having to go get after it today or tomorrow, but just kind of want to get a sense on what the future might look like. Do you think, looking at how NGL pricing is and how it affected the gas price this quarter in that region? Should I be thinking about, I guess increasing gas reserve booking potential as a result of that? Would that still filter into oil booking potential at year end?
No. The liquids and the volumes, they’re wellhead sales. So, what we record are the Mcf that go into the plants. Paul mentioned, a percent of proceeds, and all that really means is that we get paid on the basis of what comes out of the plants. So, we will get the residue, gas sales, volume and revenues and we will get the NGL liquid revenues. We will match those up against the wellhead volumes. So, really what it does is it’s the same wellhead volumes that just a higher received price.
It looks like a higher received price instead of bigger volumes.
Andrew Coleman - UBS
What was the accretion expense for the quarter? I didn’t see one listed in the financial statement.
Yes, we collapsed that into DD&A partly because of this XBRL thing that’s going on. So, we’re digging in the Q here for the exact number. Jim Shonsey has got it here for you.
That’s $0.05. It’s $0.05 per Mcfe for the quarter and year-to-date.
Andrew Coleman - UBS
I will just use that then as a rate going forward. I think it’s pretty consistent. I guess with $0.05 or $0.06 here the last few quarters. Then lastly, given the strength of your balance sheet, do you think that there will be other properties that you would be looking at? Are there things on the market that could catch your interest over the next few months if we see some distress?
We are always interested in that and from time-to-time in the past, we’ve made larger acquisitions or deals. The thing that strikes me right now is we have multibillion dollars of future drilling that is sitting there, that’s high rate of return. We see these as really good opportunities.
Each one of these areas that we are in, whether it’s our resource play in Oklahoma, whether it’s the Yegua and Cook Mountain in Southeast Texas, or whether it’s oil in the Permian, those things are high rate of return projects. So, what does that mean, it means that if we bought something, the upside in it would have to be better than what we have.
So, if we can find something that’s better than what we have, we’ll have to look at that and I hope we do. The fact of matter is what we have is pretty damn good. I can’t make a big excuse for us not spending our money developing that, which is again, the whole industry anymore is just let’s Tcfs and billions of dollars just roll-off their tongue. We really have identified way north of $2 billion or $3 billion of future drilling opportunity. So, if that’s all we are left with I’m pretty damn happy.
There are no further questions at this time. I would now like to turn the call back over to management for any closing remarks.
Thank you, everyone for joining us today. I appreciate your interest in Cimarex, and we look forward to reporting to you our future progress in the next conference call. I will look forward to seeing you at the upcoming conferences. Thank you very much for joining us today. Take care.
This concludes the Cimarex Energy second quarter 2009 financial and operations conference call. You may now disconnect.
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