Cimarex Energy Co. Q2 2010 Earnings Call Transcript

Aug. 4.10 | About: Cimarex Energy (XEC)

Cimarex Energy Co. (NYSE:XEC)

Q2 2010 Earnings Call

August 04, 2010 1:00 p.m. ET

Executives

Mark Burford - Director, Capital Markets

Mick Merelli - President & CEO

Tom Jorden - EVP, Exploration

Joe Albi - EVP, Operations

Paul Korus - VP & CFO

Analysts

Mitch Wurschmidt - Keybanc Capital Markets.

Nicholas Pope - Dahlman Rose

Gil Yang - Bank of America Merrill Lynch

Ray Deacon - Pritchard Capital

[Ronny Iceman] - JPMorgan

Eric Hagen - Lazard Capital Market

Operator

Good afternoon. My name is Regina and I will be your conference operator today. At this time, I would like to welcome everyone to the Cimarex Second Quarter 2010 Financial and Operating Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will a question-and-answer session. (Operator Instructions).

Thank you. I would now like to turn the conference over to Mr. Mark Burford, Director of Capital Markets. Sir, you may begin your conference.

Mark Burford

Thank you very much Regina, appreciate it and welcome everyone and thank you for joining us today for our second quarter conference call. We did issue our earnings release this morning, a copy of which can be found in our website and I will refer it to you.

We'll be making forward looking statements in this conference call. So I will refer you to the end of that press release for our disclaimer regarding forward looking statements. And here in Denver on today's call we have Mick Merelli, our Chairman, & CEO; Tom Jorden, EVP of Exploration; Joseph Albi, EVP of Operations; Paul Korus, Vice President & CFO and Jim Shonsey, VP & Controller.

So with those introductions over, let's just go and jump into the call. I'm turning the call over to Mick Merelli.

Mick Merelli

Yeah, thanks. Thanks for joining us today on the call. We had a solid second quarter. We grew production 31% over last year, hitting a record of 594 million cubic feet equivalent per day. Second quarter volumes were made up of 37,000,173 barrels per day of liquids and 371 million cubic feet a day of gas. Our production mix is 62% gas and 38% liquids and that's using 6:1 conversion. Our gas versus liquids on a revenue basis is 41% gas and 59% liquids.

We do have a strong liquids contribution in our Cana play in the Gulf Coast and of course our Permian activities. We reported second quarter earnings of a $125 million or about a $1.46 per share and cash flow from operations totaled $260 million. Our exploration and development capital investment in the quarter was $247 million.

Our six month E&D capital has totaled $430 million. For the full year 2010 the capital program will likely fall within a range if 900 million to a $1 billion. We extent to continue to fund this capital and investment for that program out of our operating cash flow.

The range is up from our previous range of 700 to 900 million. We continue to have very good results in our Permian Basin drilling and we are getting more active there. Our rig count is up. We've been acquiring acreage. We've acquired about 45,000 net acres in our Delaware basin activities so far this year; probably acquire more as the year goes on.

So we're expanding in that area. So our capital is moving ahead. We're having a good year. Of course we define that based on getting good returns on our capital invested and we like the returns that we're getting so far.

Now I'm going to pass it off to Tom and Joe and let them cover our drilling and production in more detail. And with that Tom, tell us about the drilling program.

Tom Jorden

Thanks Mick and good morning or good afternoon to everyone. As Mick said, operationally our second quarter was a very good one for Cimarex and we're feeling quiet positive about the remainder of the year and in actual future years.

All of our areas are continuing to perform very well as we've highlighted in the past. Just to recap, our three core areas are the mid-continent which is essentially our resource gas play; our Permian, which is essentially horizontal oil drilling and our onshore Gulf Coast.

We have a great balance of opportunities and as we always remind you, we are ready to return focus, but right now with the high relative value of oil, we are adding capital towards our higher return Permian Basin horizontal drilling.

Our current guidance estimate for capital is between 900 and a $1 billion would break down to about equal 45% between Mid-Continent and Permian, and then approximately 10% of that total capital should be spent in our Gulf Coast. So, that's change from prior. The most significant change there is our Permian capital has ramped up over previous estimates and really is going toe-to-toe with our Mid-Continent, Cana and another obligations that we're pursuing aggressively.

So, I'll cover and summarize some of our drilling activity. Our overall exploration and development activity for quarter, we drilled and completed 89 gross or 55 net wells in the first half of 2010, of which 84 gross or 52 net were successful. At quarter end, we had 33 gross or 16.5 net wells that were in the process of being completed or awaiting on completion. So we still have a fair backlog of completion activity.

In the Mid-Continent, we drilled and completed 49 gross or 24.2 net Mid-Continent wells during the first six months of 2010 and 100% of those were producers. At quarter end, we had 17 gross or 6.7 net wells that were in the process of being completed or were awaiting on completion. For the Mid-Continent, first half 2010 exploration development capital totaled 200 million or about 46% of our projected total capital.

In our western Oklahoma, Cana-Woodford Shale play, we drilled and completed 35 gross or 15.6 net wells during the first half of 2010. At quarter end, 15 gross or 6 net wells were being completed or awaiting on completion in this area. So, we're on track to get about 35 net wells drilled and completed this year.

Since our Cana-Woodford drilling began in late 2007, we participated in 123 gross or 51.6 net wells and out of those total wells, 92 gross or 38.8 net were on production at quarter end and the remainder were either drilling or waiting on completion.

Second quarter 2010 net production from the Cana play averaged 75 million cubic feet equivalent per day versus the second quarter 2009 average of 24 million cubic feet equivalent per day. So, we've seen our results ramp up there. We are very, very pleased with continuing improving results out of our Cana play.

Our Woodford drilling to-date in our Cana play has been one well per section and we've spoken extensively about that in the past. In order to determine optimal spacing, we initiated an infill pilot program. We have done this jointly with a partner and the tests consist of nine total horizontal Woodford wells being drilled and completed within one square mile. Five of those wells were spaced 500 feet apart and the other four wells were spaced 660 feet apart.

Our initial results are encouraging. We've about 45 days of flow back. We're still waiting on significant data coming in but we can give you a little bit of flavor of our results. We'll continue to monitor the performance from these wells to determine if these results support 80 acre or the tighter spacing is actually 64 acre spacing. If that were to happen, the results would significantly increase our view of the resource potential for our Cana play.

Of the infill wells we've drilled after our 45 days of production, our first 30-day average of those wells is somewhere between 5.1 and 5.4 million cubic feet equivalent per day and that's an average and includes the wet gas stream and the wellhead condensate. We're seeing results that are very, very encouraging that said we're still watching those wells, we have a lot of data that we've collected, that we have yet to analyze and just to give you a flavor what that is, we recorded extensive MicroSeismicon those wells to try to map the fracture efficiency, the degree to which the fractures of adjacent wells, may or may not be interfering with one another but fracture wing link, now we haven't the results that MicroSeismicdata yet.

It was a complex job with different receiver strings and vertical and horizontal wells and it's still in processing. So, one of the critical pieces of data from that pilot project being the MicroSeismicjob still, we haven't seen even preliminary results on that. We also put tracers on our wells and we haven't seen any results from our tracer data so that's a critical piece of data that we have yet to see and then we haven't yet brought back our parent wells to see what extent they'll come back or what the extend the in-field drilling has affected them.

So, our MicroSeismicdata or tracer data bring the parent wells back and then just saying a little longer performance of those infill wells are critical to us before we wanted to be definitive but we will say that our initial results are quite encouraging and look like certainly we've got some nice 30-day average flow rates out of those infill well on an 80 and 64-acre pilot project.

I'd like to touch on a couple other areas in the Mid-Continent and just give us some highlights. Staying on Cana, what we've discussed our Southern acreage and our quandary as to whether that will ultimately be economic. We have about 10,000 acres of our total acreage positions in the Southern extent of the play. We drilled our Oaks Well that well is somewhat encouraging, it's currently making 2.3 million cubic feet gas a day and 55 barrels of condensate a day, that's given us encouragement enough to continue to keep that area alive, we're releasing lands to the extent we can, we are evaluating that to see if we'll drill additional wells down there but certainly we're not relying of and that was the risk in the project if we haven't had some encouragement.

We continue to optimize our completions, our track fracs are -- we're going back to 13 stages after experimenting with going to as many as 20, we didn't see the kind of uplift with that those additional hydraulic facture stages that we're looking for, what we did there, we had the lateral link the same, we reduced our stage link to get more stages in the borehole, didn't see any improvement there, so we've dialed that back. We've also cut our job size down a little bit, we were at one point, up to as much as 250,000 pounds per stage of profit, 340,000 gallons of slick water per stage and we're currently dialing at down to about 120,000 pounds per stage of profit and that's 40-70 resin-coated profit and we're about 180,000 gallons of slick water per stage and we think that's not going to leave to any degradation of results to dial that back.

Our current cost in the Cana play, our AFEs is somewhere between 7.1 million and 7.5 million to drill a complete these wells, that's something that we put a lot of energy on to see if we can get that down. Right now, we're focusing, we've been putting a lot of efforts into geo steering our wells and we're making sure that we're targeting particular subsets of the Woodford reformation and we're looking to see if we can relax that a little bit and drill these wells a little faster. So, we're still in the process of optimizing, the Cana play continue to be a strong focus of ours, our results are very encouraging, both from our continued improvement of results from our parent wells with also our initial results of pilot project are something that, although we are still studying it, we are encouraged by it.

Moving on in the Mid-Continents, the Texas Panhandle, in the first half of 2010 we drilled 8 gross wells or 6.2 net wells, 7 of those were Granite Wash and one was, one was Morrow. Second quarter drilling included our George 17-4H well, where we had a 61% working interest, that's a horizontal Granite Wash well in Southern Hempfield County. That actually offsets our huff well and we have talked about in past. That was brought into production in late June, it averages 7.9 million cubic equivalent per day about 6.9 million cubic feet of gas and a 180 barrels a day oil in the first 25 days.

We were encouraged by that that was actually a shorter lateral then the huff, but still very nice result. Now moving on to the Permian Basin, in the first half of 2010, we drilled and completed 33 gross or 24.7 net Permian basin wells, 94% of those were completed as producers. At quarter end we had 15 gross 38.8 net wells that were in the process of being completed or were waiting completion.

First half 2010 exploration and development capital for the Permian totaled a 155 million or about 36% of our total capital. So, as you can see first half we were about 36% of total capital, I said earlier we are projecting 45% of our total capital to be for total year for the Permian, so that tells you that we're ramping up our activity in the Permian. We got some great plays, we're very exited about and as Nick also said we're off on some very active leasing projects in Permian basin.

Starting off the Northern portion of our South Eastern Mexico Eddy Chaves County is Abo program. We've had some new results come in there, we have two wells that were currently - two rigs that were are currently drilling, we have a 3D seismic shoot that we are currently acquiring data on in that play. That Abo program continues produce very, very nice results and really glad to have it.

Recent Abo wells are brought in production includes our Valley Forge 20 State Com 4H. Came on 590 barrels of oil equivalent per day and there we have a 50% working interest. We have over 35,000 net acres in the Abo and we see multi-years of drilling, as I said we have two rigs running and should keep two rigs there for the foreseeable future.

Moving on to out Central Eddy & Lea County First & Second Bone Spring program, that's one that we've talked about in the past that's a new program in Cimarex in 2009 and has become our most active program in the Permian basin.

Recent Bone Spring Horizontal oil wells include our Parkway State Com 2H. Where we have a 58% working interest, came on a 970 barrels of oil equivalent per day. Our Southern California 29 Fed 15H, there we had a 100% working interest, that well came on at 1,100 barrels of oil equivalent per day. And those are 30 day average rates.

So, we are seeing some outstanding results in our horizontal oil play in Eddy and Lea County. Moving on further South in Eddy country in our White City area, we're also evaluating the Bone Spring potential. That's an area that historically was a more of a vertical well gas play. We then turn it into Shale horizontal Delaware play we've talked about that in the past and then we are evaluating net acreage for the first and second Bone spring, we have talked in the past, we have drilled a horizontal Avalon shale well. We're currently valuating that well. But we're encouraged with the results.

We're having outstanding results in the Permian. We're seeing great returns and as I said, we're picking up activity and we see that as an increase on our operating rig count from five, beginning of the first quarter, to 12 operating rigs currently. With the increase in rig count, we expect to drill approximately 100 net wells in 2010, which is a 33% increase over the assessment of 75 net wells.

Our 100 net wells fall within our major plays. We'll have 30 of them in the Bone Spring play, 15 of the in the Abo play, and 40 wells in the (inaudible) drilling vertical wells.

Moving on to the Gulf Coast, and the Gulf Coast for first half of 2010 and in our southeast Texas Yegua/Cook Mountain terrain, we drilled 7 gross or 6.6 net wells, of which 6 or 5.6 net wells were successful and the Gulf Coast first half of 2010 exploration development capital totaled 72 million or about 17% of our total capital.

Out Gulf Coast drilling has been primarily there with City of Beaumont, in Jefferson County where we had 5 gross or 4.6 net wells, all of which were successful. In the second quarter, we brought on our Manion Gas Unit No 1 and our Jefferson Airplane No 4 wells. Our Manion Gas Unit No 1, is currently producing 6.7 million cubic feet a day a very nice well full of smaller features. It's producing out at the same, Kirby Sand. There is our Two Sisters, or Amazon Queen or Nine Dragons well. So, I would continue to be encouraged by the results we're seeing there.

Our Jefferson Airplane Complex, we're monitoring it. We've had some issues with some sand production there. We brought some of our wells to lower rates to control our sand production. Our higher productive wells are in compared to drainage there. So, we're having to manage that compared to drainage situation and manage our sand production. So, it's been a bit of balancing act in the Jefferson Airplane Complex. But, overall I would say our wells are performing as expected.

Since quarter end, we brought on our BP Fairfield well and that's a smaller feature in the Yegua Sand that was currently making 5.2 million cubic feet a day. We're also bringing our FE well online. That's another very smaller Kirby feature. And then we talked about our deeper prospect. We're currently drilling our Tallapoosa prospect. That's a well named with JB Gordon No 1. That's a deeper prospect. It's much higher risk. It's higher potential. It actually sits some 1,500-2000 feet our Kirby Sand. As we talked about in the past, we see a deeper set of geophysical anomalies in our date set that we're very anxious to testing.

We had several follow-up ideas at Tallapoosa prospect. We're going to be successful. But again, the fact that we have had such good success on this survey doesn't do anything to de-risk or de-project it. It really stands alone with its own ground for risk profile. But that well's underway. We're very excited to see that well down and if we're successful, it would lead to some follow-up drilling. So, we currently have one rig drilling in our southeast Texas Yegua/Cook Mountain play and studies as she goes, we will see what happens.

We've said in the past, we're always trying to extend that plays. We're working on some new ideas to extend that. That's a play that's been a core part of our business for many years and will be for the foreseeable future.

So, very nice results so far this year. All three of our core businesses are performing well. We are ramping up our Permian activity but we like that balance. We certainly liked the results we're seeing in our mid-continent program, dominant of our Cana resource gas play. Our Permian program is firing on all cylinders. That's internally generated opportunities and we've had some outstanding results and then our Gulf Coast program continues to perform as expected and we still have a fair amount of drilling to do there.

So with that I'll turn it over to Joe Albi, our Executive Vice President of Operations.

Joe Albi

Thank you Tom and thank you all for joining us today on our call. I'll hit on our second quarter production results, update you on our 2010 guidance, touch a bit on our production group activities and then follow up with a few comments on where we see current service costs. As Mick mentioned, Q2 was another good solid quarter for us with the continued success that we had in each of our core areas. We reported average net daily equivalent production of 594.4 million a day and despite being somewhat impacted by pipeline and facility shut ins, we really set some nice marks during the quarter.

We came in at the upper end of our projected guidance of 570 to 600 million a day. We set a new company record for quarterly production. We had our fourth consecutive quarterly increase in production since we slowed down our activity in late 2008 and early 2009. We were up 140 million a day or 31% from our Q2'09 average of 454 million a day and we were up nearly 10 million a day as compared to Q1'10.

In comparing second quarter '10 results to second quarter of '09, we saw nice production increases in both gas and oil and NGL liquids. Our Q2'10 gas production of 371.4 million a day was up 54 million a day or 17% from our Q2'09 average of 318 million a day while our Q2'10 oil and NGL production of 47,000 barrels a day was up more than two fold from the 23,000 barrels a day that we reported in Q2'09.

As compared to Q1'10, on an equivalent basis, we were up in each of our core areas. In the mid-continent, our second quarter production of 248.4 million a day was up nearly 10 million a day from our first quarter average of 238.8 million a day. Our Gulf Coast onshore production of 183.2 million a day was up 2 million a day from our Q1 average of 181 million a day while our Q2 Permian production of 155.1 million a day was up slightly from our Q1 average of $154.5 million a day.

Now I want to spend just a little bit of time discussing our Q2 numbers as they compare to Q1. At first glance you'll see that our reported gas production of 371.4 million a day was down about 5% from our first quarter average of 391 million a day. Our reported oil production of 26,400 barrels a day was down 5.7% from our first quarter average of 28,000 barrels a day but our reported NGL production of 10,800 barrels a day was up 151% from our Q1 average of 4,300 barrels a day.

Digging deeper into the numbers, three factors really come to surface. First, as Tom alluded to, beginning in April and continuing into June we intentionally reduced the production rates of three of our Beaumont wells to protect the wells from reservoir management standpoint.

In April we saw early signs of potential fine sand flow production in our Jefferson Airplane number 1 well. We did extensive modeling of the reservoir and wellbore flow conditions and we made the decision to cut that production from not only that well but also two other Jefferson Airplane wells during the quarter.

The rate reductions occurred ongoing from April through June and although pinching back the wells reduced our production during the quarter we announced just deferred production from these wells and minimize or anticipated declines in Q3 and Q4.

Secondly, we experienced a number of unanticipated pipeline and facility related shut-ins during the quarter which deferred upwards of 10 to 15 million a day of production during the quarter and the majority of these occurred in South Texas and Permian.

And thirdly, our increased natural gas liquid production was a result of real three things, increased Cana and other process gas drilling activity, contract amendments in South Texas and the Permian and our continued focus of maximize the delivery of our South Texas gas into the markets to provide processing.

But when the dust settled our intentional rate reductions in the Jefferson Airplane wells and the pipeline facility shut-ins reduced our second quarter oil and gas production from the levels we saw in Q1 while our focus on processing resulted in a increased production from natural gas liquids in the second quarter as compared to Q1.

In the end of equivalent basis we are up for the quarter and essence just shifted some production from Q2 into Q3 and Q3.

So, looking forward with the modeling of activity in each of our core areas we have increased our production guidance to the remainder of the year. All three of our core areas provide us with catalyst for continued production growth. During Q2, we saw our Cana program deliver another quarter of production growth growing our mid-continent gas production by 8 million a day from Q1 to Q2 from a 188 million a day in a Q1 to 196 million a day in Q2.

We anticipate the program to continue the production growth during the year and ultimately getting near that number I think we quoted in our last conference call where we'll see total Cana production get upwards of a 100 million a day by the end of the year.

We picked up our activity in the Permian, as Tom mentioned we have got we have gone from five rigs in March to a current level of 12. The results of that activity really is expected to been seen here in the last half of the year and not so much here during Q2.

And our current rig schedule for South Texas includes a good number of leads that if they are successful they can certainly help us in the tail end of 2010 and certainly through 2011.

So, as a result we have increased our production guidance projections for the remainder of the year and despite selling about 3.5 million a day of production at the end of Q2, closing date on that transaction was June 30.

Our guidance for Q3 production is estimated at 585 to 815 million cubic feet equivalence per day that's up by healthy 33 to 39% from our Q3, '09 average of 442 million a day.

And for the year we have increased our 2010 guidance once again, projecting total company net equivalent production of 585 to 609 million a day for the year. That's up from our guidance last quarter of 575 to 595 and up significantly from our beginning year guidance of 540 to 570 million a day.

It also represents a very respectable 26 to 31% increase from our 2009 average of 463 million a day. With our continued focus on oil and liquid rich gas we anticipate that we will exit the year with oil and NGL production making up about 38% of our total company production which is about where we reported last quarter and that again is 8 percentage points higher than the 30% we averaged in 2009.

While shifting gears to our production operations group, our emphasis during Q2 was once again focused on improving our operating efficiencies. And in doing so, we managed to keep our lifting cost inline with that of Q1.

Now although we're seeing some cost pressure in items such as saltwater disposal, compression, pulling-unit cost, our second quarter average lifting cost of $0.84 per Mcfe was virtually flat to our first quarter average of $0.80 per Mcf.

We also fell in the low-end of our second quarter guidance range of $0.80 to $1. At current levels we're operating at a 24% decrease from the $1.11 per Mcf average that we saw in 2009. So we have managed to keep in our hip pocket a lot of the cost reductions that we're able to derive at the end of '09 and coming into '10. Although, we plan to continue our focus on cost efficiency with the likely cost pressures that we're seeing, we saw no reason to change our previous 2010 guidance estimate of $0.80 to a $1 for the year.

As was the case again in Q1, our second quarter exploitation activity was focused on lift projects in both the Permian and Mid-Continent. So re-completion activity in southeast New Mexico, Southern Oklahoma and Texas Panhandle and a half dozen or so infill drilling projects in West Texas and Kansas.

Through June, we've deployed about $22 million towards our exploitation efforts and are staying with our projection from last quarter that will end the year somewhere near the low-end of our -- we're giving you a guidance budget of 50 to $75 million for the year.

And finally on the drilling and completion cost side, over the last six months we've seen anywhere from 5 to 20% cost increases in items such as rigs, cementing, rentals and mud. But frac cost continue to really be the wild card for us with cost pressure directly related to crew availability.

There's so many net moving parts to this cost component that it's hard for me to quote you an exact increase in the costs that we're seeing. But depending on the area, the size and the scope changes in our frac design, we've seen anywhere from 10 to 100% plus increases in our frac cost over the last six months.

We've also experienced delays in scheduling some of our jobs. Frac costs for the most part seemed to be putting the most cost pressure on our total well costs. That said, through careful planning and continued operating efficiencies we've managed to minimize our well cost increases, while getting the sales without any extensive delays.

In Cana, Tom had quoted AFEs of 7.1 to $7.5 million. Depending on debt, that number can range upwards of $8 million but the bottom line is from Q1 to Q2, we're seeing about $1.5 million increase in our total well cost in Cana.

Our 6,000 foot vertical Blinebry/Paddock well AFEs of $1.7 million are up slightly from the $1.5 million we were recording in Q1, while an 8,000 foot New Mexico Bone Spring horizontal well with a 4,500 foot lateral is now AFEing at about 3.8 million or about $200,000 higher than Q1.

So we're seeing may be 4 to 8% total well cost increases but through efficiencies we've managed to keep a good bit of control on our cost. So our challenge obviously as we move forward is to continue to improve our operating efficiencies so that we can keep our well cost in line, keep the rate of returns that we're seeing where they are and continue to expand our activity and get the results that we're currently seeing.

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

Paul Korus

Thank you Joe. I just want to recap a few things and then address some of the questions that we've had from calls this morning. Recap mid-year status for Cimarex, great shape, $329 million of net income, $3.84 per share, 573 million in cash flow. If you annualize those numbers you could see that we are well on our way for over 1.1 billion of cash flow in annualized earnings per share of over $7. So great shape from that perspective.

At the same time we have no bank debt and we have a 142 million in cash in the bank as on June 30th and as Tom and Joe have described for you, operationally great year. Production is up 30%, very steady. We're on track for probably what might be our largest percentage increase in crude reserves we've ever had, a good rates return and low finding costs. So that's a pretty healthy score card I would say.

On the other hand, since we are making more money, we've had to increase our estimate of what we're going to go for income taxes this year from about 100 million to a 120 million. As a result you saw in our second quarter numbers that we trued up the split between our current and differed tax items to reflect that about 65% of our book tax provision which usually runs around 36.5% will be differed with the remaining 35% being our best estimate of what we think we'll have for current taxes. So that's what we ended up with for the six months results with a lot of movement between the first and second quarter. And that's what we would expect to see as we finish the year.

The other item that I think we got some questions about this morning was so called adjusted earnings. We are kind of down the middle of the fair way and we report GAAP earnings because we know the rules for those. Adjusted earnings are somewhat in the eyes of the analyst. But the way we would look at that, it mostly revolves around the hedging.

You saw that in the first quarter using market-to-market accounting we had 52 million of hedge gains in the first quarter because prices went down and brought all our hedges into the money. So we basically recognized much of the earnings in the first quarter.

In the second quarter we only had 3.3 million of mark-to-market gains on the derivatives. That's because prices went down a little bit further. But anyway, if you net all those things out, you could say that had we been using effective hedge accounting treatment, our revenues would have been about $16.6 million higher in the second quarter and then we would have not had the 3.3 million of mark-to-market gain, in which case out pretax income would have been about $13.3 million higher. In turn net income would have been around 8.4 million higher and earnings per shares about $0.10 higher or a $1.56 as opposed to the reported $1.46. So that's the way we would look at the adjusted earnings figure and I think some of you are and some of you aren't but the kind of guidance or explanation we would give around that.

I think that's all I need to say. So would be happy to begin entertaining questions.

Question-and-Answer Session

Operator

(Operator Instructions). Our first question comes from the line of Mitch Wurschmidt with Keybanc Capital Markets.

Mitch Wurschmidt - Keybanc Capital Markets.

Hi, guys. Congratulations on the quarter.

Mike Merelli

Thank you, Mitch.

Mitch Wurschmidt - Keybanc Capital Markets.

Yeah, just, I was looking at the Bone Spring and Abo results. They keep getting better and better each quarter and I'm just curious. Can you talk a little bit about what you're doing differently or is it the area, the play you're in or how repeatable you think that is?

Tom Jorden

Mitch, its Tom. Much as I'd love to cite our efforts, a lot of that is the rocks. We're really in some very nice areas. We're getting these wells completed efficiently. I think our team in Midland has done a great job operationally, getting these things done. But, it's really just nice rock. We're finding and we're testing some new areas and they're very prolific and we're just tickled pink with the results. When we first got on this play we were talking about results that were considerably lower than what we're achieving.

So we're increasing our own estimate, pre-drill. Of course that means that some other people are paying attention. Lands got a little more expensive. There are some play entrants. If you follow the industry as I know you do Mitch that there are a lot of other people now talking about that Bone Spring play in Southeastern Mexico. So, it's just really worked out well for us and to that I attribute good geology and good operational execution.

Mitch Wurschmidt - Keybanc Capital Markets.

That's great. It's helpful. Can you talk a bit about, maybe EURs you're seeing on some of those wells? Like you kind of mentioned well costs. Where are you kind of coming in on some of the EURs or the average you should be looking at?

Tom Jorden

We're currently -- when we got started in this, we were talking about the EURs between 200 and 250,000 barrels. For the areas we like, which is most of the trend, our EURs now are coming in between, I would just 550,000 barrels on an equivalent basis is our current model. And we think that's sustainable. We think that's where our results speak to.

Mitch Wurschmidt - Keybanc Capital Markets

And, that's for about I guess the $3.8 million well?

Mike Merelli

Well it depends on depth. Joe quoted 3.8. That would be, it goes deep to shallow as you go from west to east. So that's probably 3.8, 4.2 maybe, yeah.

Tom Jorden

Current AFEs for a deeper well are running around 4.1

Mitch Wurschmidt - Keybanc Capital Markets

Okay, great. That's really helpful. Can you break down like what the rig count; you mentioned 12 rigs in the Permian. How does that break down between the Bone Springs and some of the other plays and kind of how do you see that going into 2011? Any color on that would be great.

Mike Merelli

Yeah you bet Mitch. There are 12 rigs. We have three of them in the New Mexico Bone Spring play. Two of them are in our Abo trend. We have two of them drilling vertical Paddock wells. We have three rigs on White City, testing various things. And then we have one in our Third Bone Spring play down at our low in-field and one kind of bounces around drilling some miscellaneous wells.

We haven't poured our 2011 plans yet. That's a process we typically kick off in October. I will say that I've spent little time with our Permian Group and they are wanting to increase activity fairly significantly and I think you would probably see that proportionately. We like all those plays.

So, we really like the Bone Spring play, the Abo play, the Paddock play. So, I think you'd seen, that ratio probably hold solid. But I would expect and again, I'll caution to say we haven't done our 2011 planning yet. But I would expect that will be increasing our Permian capital, I would say, 20% or more for next year.

Mitch Wurschmidt - Keybanc Capital Markets.

That's great. And then, thinking about the inventory you guys mentioned 45,000 acres picked up in the Delaware Basin. I assume that's Bone Springs potential as well. Could we get maybe a number on total potential acreage that could be perspective for the Bone Springs?

Joe Albi

Bone Spring mentioned several different plays. We have our Bone Spring that we're playing in Eddy County is second third bone spring. First Bone Spring is the Avalanche Shale and so I will say that of our acreage that we currently tabulate, we think exposure to that Avalanche Shale play, we probably have 100,000 or more acres that's potentially sitting right in the middle of it. So as I say that I'm going to caution that there is more that we don't know about that play than we do know about that play but there is some drilling going on and it does sort of subsume about 100,000 acres that we think will be exposed to that play.

In the New Mexico Bone Spring play, we have about 38,000 net and about 65,000 gross and that's a very difficult number to really put a stake in the ground on because that's changing all the time. We're leasing aggressively. We find ourselves through trades and using the force pooling that we leverage our position to increase our working interest but we've gotten multi years of inventory and we really like those plays.

Mitch Wurschmidt - Keybanc Capital Markets.

No, I really appreciate all the answers guys. Congrats again. I'll jump off and let somebody else jump on. Thanks.

Mike Merelli

Thanks Mitch.

Operator

Our next question comes from the line of Nicholas Pope with Dahlman Rose.

Nicholas Pope - Dahlman Rose

Afternoon guys.

Mike Merelli

Hi Nick.

Nicholas Pope - Dahlman Rose

Hey, on the asset sale that you all made during the quarter, what exactly did you sell and how much reserves are attributed to that?

Mike Merelli

They were our assets predominantly in Mississippi because that followed us for 10 years at least. He probably didn't know we had assets in Mississippi. So that was the bulk of the proceeds and the associated reserves are about 8.7 Bcfe.

Nicholas Pope - Dahlman Rose

Okay, that's helpful. And then just, could you give more detail about the pipeline curtailments that you'll saw during the quarter, I guess where they were located and do you have an idea of like what the -- how much that impacted the production during the quarter.

Joe Albi

This is Joe Albi. Our best estimates for production reductions during the quarter, I think I quoted 10 to 15 million a day. A majority of that occurred in the Beaumont area and it was a situation where there was some maintenance repairs going on number one and number two there was a small pipeline rupture that needed to be tended to. So that had the biggest impact on us. We also had maintenance shut ins in the Permian that also were playing a big role in that whole shut in period. It's hard for me to give you a dead on number because we re-pensioned our Beaumont wells at the same time that we had the shut ins ongoing. So if I use before shut in versus after shut in, it gives me a range of potential impact for the quarter.

Nicholas Pope - Dahlman Rose

Okay, that's no problem. And were any of those pipeline impacting the quarter end numbers. You don't provide the last week and the operations update?

Mike Merelli

No

Joe Albi

That all happened in June for the most part. April through June.

Nicholas Pope - Dahlman Rose

Okay, that's all I had. Thanks a lot.

Joe Albi

Operator

Our next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Gil Yang - Bank of America Merrill Lynch

Hi, could you comment on what the cost of the Granite Wash wells that you are drilling are?

Joe Albi

Well this is Joe Albi, the current well cost for a Texas Panhandle Granite Wash wells is running around $5 million and that's up about $0.5 million from where we were in Q1 most of that is on the completion side and due to increased stimulation cost.

Gil Yang - Bank of America Merrill Lynch

And how long are those laterals, how deep are they?

Tom Jorden

Yeah the 11,000 laterals are about 5000 deep, it kind of depends where you are, it kind of that's going to vary from 8 to 11,000 feet and laterals if we can get a 5000 per laterals we'll try. 4,500 feet is probably more realistic given land constraints, where you can put your rig.

Gil Yang - Bank of America Merrill Lynch

Okay a lot of other operators have drilled well. They are sort of in the teens 20s of IPs, is there -- do you think the lower IP that you had in your well was because of shorter lateral or is that the area you are in or any other?

Tom Jorden

This is Tom, we offset our huff well which had teens rates so it's -- we do have that kind of potential in the area. As I said the reason George Well was reduced rate was really two reasons. We are drilling a San Channel, we in the lateral we ran out of sand and we stopped lateral a little short because we though we were out of sand and then when we were running our casing we stuck the casing and didn't get all the way in and off about another 500 feet of lateral.

So, there is about 2,500 foot effective length in that well and that certainly accounts for the reduced rate.

Gil Yang - Bank of America Merrill Lynch

Got you. Okay. In the Cana test, could you give us an idea for the parent wells, what the 30 day average was?

Joe Albi

Gil I am sorry, operator we are having, it's not coming too very clear here on our end.

Gil Yang - Bank of America Merrill Lynch

Can you hear me better now or?

Joe Albi

Gil I can barely hear you. Go ahead Gil please.

Gil Yang - Bank of America Merrill Lynch

For the Cana wells the parents wells that the down spacing wells were tested that were nearby. Can you give us what the 30 days rates were for those wells?

Tom Jorden

For the parent wells?

Gil Yang - Bank of America Merrill Lynch

Right.

Tom Jorden

I will say I don't have that in front of me. I can give you that if you want to call, I will say our model for parent well in that core area would be about 4.8 million cubic feet a day of wet gas. So, that would be not in the equivalent rate but actually a high btu gas stream, our model in that area will be just slightly under 5 million cubic feet a day that's what we would expect.

For the particular two wells that were on those sections that were on those sections I don't have that in front of me. We didn't quite achieve that with our in-field but we really didn't expect to, I mean our model going forward we were looking for something 70% better than a parent well and we would call that encouragement and we certainly that encouragement.

Gil Yang - Bank of America Merrill Lynch

Okay got it, so the 5.1 to 5.4 is equivalent volume.

Tom Jorden

That is the equivalent volume that includes the methane stream, the NGL volume and the wellhead condensate.

Gil Yang - Bank of America Merrill Lynch

Got you. Okay. Thank you very much.

Operator

Our next question comes from the line of Ray Deacon with Pritchard Capital.

Ray Deacon - Pritchard Capital

Hey Tom I was wondering if you look at the Gulf Coast production and just kind of look a the sustainability of that area.

Tom Jorden

Ray I am sorry.

Ray Deacon - Pritchard Capital

Yes, I'll just get the telephone, oh sure.

Tom Jorden

We're apparently having some difficulties. Give us one minute and we'll try to dial in from a different phone. Well you hear us now?

Ray Deacon - Pritchard Capital

You did that pretty quick, so but -- hey just one quick question, it was -- in terms of the Gulf Coast I guess people seemed concerned about potential declines there, if you I guess -- am I understanding right that you think you can keep production flat if you kind of drill average wells what you've seen historically through the end of the year, is that -- does that sound about right?

Joe Albi

Well, this Joe Albi. What all we can really go on is what we know as far as the existing wells and your productive capacity is are and what we've modeled for Q3 and Q4 is that the anticipated decline that we thought we'd see a year ago, we're not seeing it now and that's a combination of couple things. Pulling back our wells like we did in the Jefferson Airplane Complex, number one; and number two, we had a great good string of productive wells along the way. What I can tell you is that if we have success on that rig line that there's a pretty damn good chance that we keep the flattery and even increase it. That it all comes down to the wells that we ended drawn from here.

Ray Deacon - Pritchard Capital

Okay, got it. And can you -- I know it's early with the Bone Springs but I guess can you quantify what the rates return will look like for it's sort of a typical Permian well that you would drill since the all way 2000s I guess.

Joe Albi

Well, in rate -- of course I will say again Bone Spring is several different plays but for our second Bone Spring, third Bone Springs, horizontal oil program and Eddy, Lea County, we're typically looking at current oil pricing and we ran a forecast in the share pricing and then we look at downsize sensitivity, our share pricing is whatever the future prices, that they will make decision and then the downsize sensitivity is $45 NYMEX held flat forever, less local market deducts when you look at there's a local market will take the hit for that.

We're typically looking at rates to return that are 50% or better for this horizontal wells that current oil pricing and then if that $45 flat, that's play is it's not a typical to be looking at flat pricing that's somewhere between 25 and 35% rate of returns. So, now I would like to that the return to that play but assuming it's also very important to us as it does have certain robustness to that downsize sensitivity if we saw collapse in oil prices.

Ray Deacon - Pritchard Capital

Got it. Great, thanks very much.

Operator

Our next question comes from the line of [Ronny Iceman] with JPMorgan.

[Ronny Iceman] - JPMorgan

Good morning, guys. Back to the Cana, with going back to 13 stages and cutting back on the frac size, have you quantified what the impact is to the EURs, especially in the quarter?

Joe Albi

We think there's no impact. That's why we changed it, we've done a lot of science talk here and continue to do a lot of science and one of the things that we experimented with a shortening, I'm really getting into the weeds here but you ask the question and we have an answer.

We are four clusters per stage and initially our clusters were about 80 feet apart so we had four of them per stage and stage was 353. We experimented with shortening that cluster spacing down the 50 feet and going with stages that were about 250 feet apart and that's how we were getting more stages in the lateral.

We were just shortening the space between clusters and the idea was that each cluster will generate an independent hydraulic fracture and that we thought we could generate more of them without interfering with one another.

The goal is you would like to put those things as close together as you can but there is a point where if the get too close together they interfere with one another. In other words, if you get too close, two cracks you are trying to open up we are actually closing one another because they are just too close.

We went about shorter cluster spacing, we completed quite a few wells with it and didn't see any statistical uplift, didn't see really any benefit whatsoever and so it was more expensive, it was more operationally intensive to do that and we doubt that back. We would think that with our lighter treatment we will see no degradation in EUR.

I know that sounds a bit lot but we have a lot of data for that we have a lot of data for that.

[Ronny Iceman] - JPMorgan

In the quarter what are you carrying right now as going forward in EUR?

Joe Albi

Well our type curve which is for a new drill is about 8.8 bcf of wet gas I don't want to say wet gas, I mean we have associated natural gas liquids that will come out of that stream and we have about 62000 barrels of oil and the first 30 day average of that well would be about 4.8 million cubic feet a day of a wet gas stream and of course that goes in the processing and if gets natural gas other than that.

[Ronny Iceman] - JPMorgan

Okay. Thank you guys.

Operator

Our next question comes from the line of Eric Hagen with Lazard Capital Market.

Eric Hagen - Lazard Capital Market

Just a follow-up on Ronny's question on the Cana, now that you are going to be pumping smaller jobs in fewer frac stages, are we still going to see well costs around 7.1 to 7.5 or is it potentially going to go down a bit?

Tom Jorden

Well we are seeing, this is Tom and Joe is going to comment on that as well the operations group proposed to Joe and said he keeps his finger on that pretty tightly. We are looking at from our standpoint in exploration to drill these wells little faster by not staring them as much. So, we certainly like to try to shave some days off but we are seeing some upward pressure in our stimulation cost.

Joe Albi

Yeah I would say a good safe range right now to use will be 7.5 to $8 million total and like Tom said a lot of the hinges are on how we directionally drill these, we could potentially cut some costs there and by going back to the 13 stages that has helped. It's by saving another 700 - $800,000 up the total stimulation cost.

But again you got a lot of components going at the same time so we're trending water around 7.5 to 8 million.

Eric Hagen - Lazard Capital Market

Okay great. Thank you. And then in the Avalon shale Tom, you said you had 100,000 acres. Is that a net or a gross you are talking about?

Tom Jorden

That's a net number but again I wanted to give my standard caution that's acreage that I can probably on a math show how Avalon shale wells are been drilled and if I drew a big oval around that our acres sit inside that.

We are still early days evaluating our level of interest in that play and so I would discourage you from taking that 100,000 acres dividing it by 8 per well number and extrapolating that because we don't that internally.

Eric Hagen - Lazard Capital Market

Okay. Thanks Tom. Just can we do that math? What kind of spacing are you using currently in the Abo and Bone Springs?

Tom Jorden

Well, the Abo is really 168 per spacing and that's also true in our New Mexico Bone Spring. If you really held my feet to fire asked me to justify, should it really be 200 or should it really be 100, we haven't done a lot of work on that yet. But we're pretty solid at 160.

Eric Hagen - Lazard Capital Market

Thanks. And then the Abo just to connect sort of completed the Permian, how much acreage you think you have there? I think you said about 40,000 and Bone Spring, and add something, but what about the Abo?

Tom Jorden

You know, the Abo, we have about 35,000 net and most of that is Cap Rock Township. Actually the number is 39,000. We're acquiring small interest here and there. I wish I could tell you that we had the potential to pick up a lot more acreage in that play, kind of geologically limited. It's probably never going to be three times of that.

Eric Hagen - Lazard Capital Market

Okay. I am sorry. I had one more on the Third Bone Spring in West Texas. What's the rationale for just running one rig there is it? Or the wells less productive, is it more expensive or is kind of the?

Tom Jorden

We didn't lay leasing play there. This has been kind of a quite year for us but we attempted to flange up our position with leasing. That play has become much more competitive. There are some operators out there that had been not pursuing that play. They have a lot of acreage and they've now stepped up and drilling wells and making nice wells. That play is economically little tougher than others. We like the returns on that play. It looks very good. But that is deeper. It is more expensive drilling and so, if you looked at the return of that play, it's not as solid as some of the stuff over in New Mexico. That said, the play we generated internally, we really like it.

Eric Hagen - Lazard Capital Market

Great. Thanks a lot Tom. Thanks for all the details.

Tom Jorden

You bet.

Operator

At this time, there are no further questions. Are there further remarks?

Mark Burford

No. Thank you for joining us today everyone. We look forward to reporting to you for the results. Any follow-up questions, please give us a call. Take care. Thanks a bunch.

Operator

Ladies and gentlemen, this does conclude today's conference call. Thank you all for participation and you may now disconnect.

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