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SM Energy Company. (NYSE:SM)

Q2 2011 Earnings Call

August 02, 2011 10:00 a.m. ET

Executives

Mr. Anthony J. Best – President and CEO

Mr. Javan D. Ottoson – EVP and COO

Mr. A. Wade Pursell – EVP and CFO

Brent Collins – Senior Director of IR and Planning

David W. Copeland – SVP, General Counsel and Corporate Secretary

Analysts

Michael Scialla – Stifel Nicolaus

Nicholas Pope – Dahlman Rose & Co.

Joseph E. Bachmann – Howard Weil

Welles Fitzpatrick – Johnson Rice

Brian Lively – Tudor Pickering Holt

Scott Hanold - RBC Capital Markets

David Tameron – Wells Fargo Securities

Subash Chandra – Jefferies & Company, Inc.

Andrew Coleman – Raymond James

Joseph Allman – JP Morgan Securities, Inc.

Operator

Good day ladies and gentlemen and welcome to the Second Quarter 2011 SM Energy Company Earnings Conference call. My name is Cindy and I will be your operator today. At this time, all participants are in a listen-only mode, later we will conduct a question-and-answer session. (Operator Instructions).

I would now like to turn the call over to your host today David Copeland, Senior Vice President & General Counsel. Please proceed.

David W. Copeland

Thank you Cindy. Good morning to all of you joining us by phone and online for SM Energy second quarter 2011 earnings conference call operations update.

Before we start, I’d like to advise you that we will be making forward-looking statements during this call about our plans, expectations and assumptions regarding our future performance. These statements involve risk, which may cause our actual results to differ materially from the results expressed or implied in our forward-looking statements.

For discussion of these risks, you should refer to the cautionary information about forward-looking statements in our press release from yesterday afternoon, the presentation posted to our website for this call and the risk factor section in our Form 10-Q that we filed later today.

We will also discuss certain non-GAAP financial measures that we believe are useful in evaluating our performance. Reconciliations of those measures to the most directly comparable GAAP measures and other information about these non-GAAP metrics are described in our earnings press release from yesterday.

Additionally, we may use the terms probable, possible, and 3P reserves and estimate ultimate recovery or EUR on this call. You should read the cautionary language that is in our slide presentation for important discussion of these terms and the special risk and other considerations associated with these non-approved reserve metrics.

Company officials on the call this morning are, Tony Best, President and Chief Executive Officer, J Ottoson, Executive Vice President and Chief Operating Officer, Wade Pursell, Executive Vice President and Chief Financial Officer, Brent Collins, Senior Director of Investor Relations and Planning and myself David Copeland, Senior Vice President and General Counsel. With that I will turn it over to Tony.

Anthony J. Best

Good morning everyone and thank you for joining us for the SM Energy Call this morning. Before turning the call over to Wade and Jav for their respective financial and operational reviews, I will cover some of the highlights from the last quarter.

I’ll speak briefly about our quarter results and comment on some of our key accomplishments during the quarter. I’ll then talk briefly about our outlook for 2012. Our comment this morning will be referred to the presentation that was posted on our company website last night.

I am starting on slide 3 of the presentation at this time. The second quarter was an outstanding quarter for SM Energy. We average 437 million cubic feet equivalent per day production for the quarter, which is a new quarterly record for the company and above our second quarter guidance.

During the quarter we announced two separate Eagle Ford Transactions. We are disproportionately selling down our non-operated properties giving us more control over our CapEx pays and spend which was a key objective of the sale down.

In addition to the non-op deal, we are selling a track of acreage in LaSalle and Dimmit Counties that is separated from our main acreage position. Now that these transaction have been announced and we have more clarity of what our remaining position in the play looks like, we can provide more detail of our plans for the rest of this year as well as preliminary plans for next year’s capital spend and production outlook.

In 2011, we expect to have approximately 50% production growth year-over-year. and in 2012 we are projected to have 35% to 40% growth giving us average daily production of over 600 million cubic feet equivalent per day by late next year. I think the additional color given to shareholders today will help paint the picture of significant growth potential of the company over the coming years.

With that I will turn it over Wade for his financial review.

A. Wade Pursell

Thank you, Tony. As Tony touched on, we had a very strong quarter and I’m going to start on slide 5, where I’ll compare our results for the quarter versus our guidance. We had record quarterly production averaging 437 million cubic feet equivalent per day which was above our guidance range of 396 to 429.

Composition of our production stream was also in line with our guidance. On the cost side, we came below guidance for all the key metrics. With regard to production taxes, we reported 1% as a percent of pre-derivative revenue significantly below our guidance of 7%, largely this difference is due to tax incentives that we were able to realize in our Eagle Ford program.

Non-cash interest expense was the only reported figure that came in above our guidance which was due to entering into a newly amended credit facility during the quarter and I’ll touch on that later.

GAAP net income was a $124.5 million or a $1.86 per diluted share and adjusted net income for the quarter was $61.1 million or $0.91 per share, a significant increase from our first quarter results.

The increase in adjusted net income is mainly driven by increased production in our commodity prices during the quarter. Our operating cash flow for the period was $3.39 per diluted share which is well in excess of Street consensus of $2.78 per share.

In our appendix, we have included reconciliation for both adjusted net income and operating cash flow back to the related gap numbers. In all this slide points out how well our company has done over the past quarter with production above guidance, lower cost on a per MCFE basis and adjusted net income and cash flow are the big Street expectations.

With that I’ll move on to slide 6 and talk about our current financial position. Our debt to book capitalization ratio at the end of the second quarter was 32% and total debt to trailing 12-month EBITDA was (0.86) times.

We’ve two pieces of long term debt outstanding as of the end of the second quarter. The first are 3.5% convertible notes which can be put to this or called by us in 2012. We are able to settle these notes on all cash, all equity or any combination in between. Our current accounting treatment is to treat these as if we will net settle these notes meaning we would settle the principal amount in cash and any remaining upside in equity. Second piece of debt on the balance sheet is our 6 and (5A)% high yield notes which we issued beginning of this year.

Moving to the next slide, slide 7, I will discuss our newly amended long term revolving credit facility. Beginning of the second quarter, we entered into a new five year mandate credit facility. With more recent reserve figures and a more favorable lending environment, we are able to exercise both the borrowing base and the commitment amount to $1.3 billion and $1 billion respectively. At the end of the quarter, this facility remained un-drawn. In addition, we were in compliance with all financial covenants.

As a final note before I turn the call to Jav, I wanted to mention that in our appendix we have included an updated hedge position summary, detailed hedge positions will be included in our Form 10-Q, which we expect to file with the SEC later today.

So, with that I will turn the call over to Jav for the operational update.

Javan D. Ottoson

Thank you Wade, good morning everyone. As Tony and Wade indicated we had a busy quarter. As you can see on slide 9, although we were infrastructure constrained in Eagle Ford and our production was negatively impacted by flooding in the in Williston Basin, we were still able to grow equivalent production of 10% quarter-over-quarter.

I will run through activity in each of our major plays and as I do so point out the key capital investment changes we are making for the reminder of the year. I will then summarize the 2011 capital changes and give you a preview of 2012 as well as the new production rate forecast for the reminder of this year and next.

I am now moving to slide 10. The Eagle Ford play is where we are investing the most capital and our recently announced transactions are driving the majority of our investment plan changes. We entered 2011 planning to sell down a portion of our Eagle Ford shale position. We had a couple of scenarios we were considering that essentially resulted in the same amount of capital investment which was $500 million.

As Tony mentioned earlier, during the second quarter we announced the signing of two transaction agreements. The first is the divestiture of our LaSalle County acreage to Talisman and Statoil for $225 million.

The second is the transfer of 12.5% working interest in the Anadarko operated portion of the play to Mitsui in exchange for a carry of 90% of our drilling and completion costs in the non-operated acreage until $680 million has been expended for our benefit.

These two transactions will result in us receiving more value while giving up less acreage then we projected at the beginning of the year. They also will close significantly later then we had expected. As a result we will invest more capital in 2011 and book more production revenue and operating cost than we had originally guided.

We now expect that we will invest $795 million in total CapEx related to the Eagle Ford shale pay. $315 million of that amount is attributable to the non-operated Eagle Ford where we are assuming we will incur nine months of capital spending at our pre-transaction working interest of roughly 27%. Post closing, SM will have 46,000 net acres in the JV area.

Moving to slide 11, which covers our operated Eagle Ford assets. Post closing of the Talisman and Statoil deal, we will have approximately 150,000 net operated acres, that are essentially contiguous with the working interest of 100%.

We have four operated drilling rigs running in the play currently. There have been a numbers of news stories written over the past several months regarding water availability or Eagle Ford well completions giving the drought that is occurring in Texas.

Though this drought may impact some other operators, we purchased water rights in the Rio Grande River earlier. So, we are not dependent on sub surface sources of water for our development. We are building water pipelines and facilities that will allow us to move this water around our acreage block which will result in lower completion cost in the future.

We accelerated some of our planned activity on this water system into this year and we believe that it will be almost entirely operational by year end. We are lowering our projection for the number of net wells, we expect to drill in 2011 from 70 to 65. We have delayed some rig activity due to the optic limitations we have experienced, so we do not build a larger backlog of restricted wells. I should note, however, that the strong well results we are seeing will still allow us to fill our late year pipeline commitments. I’ll elaborate more on both of these points in a moment.

We grew production sequentially in our operated Eagle Ford program by 6% quarter-after-quarter, a rate that would have been much higher had we not had optic infrastructure constraints which limited our ability to fully produce our wells.

Slide 12, shows our current contracted wet gas takeaway capacity through 2015. The volumes depicted here are gross wet gas volumes. You may remember that at our last call we discussed an increased optic deal with ETC which provides us with approximately 80 million cubic feet a day of additional capacity starting in mid 2013. Until then we have two agreements in place, one with Regency using enterprise capacity and one with KM/CPNO. The KM/CPNO pipe is expected to start service by September.

During the second quarter, our optic was all flowing on a Regency Enterprise system. We have been promised a maximum of 150 million cubic feet a day of gross wet capacity on the Regency Enterprise system overtime, but that capacity is dependent on a number of projects being done and they have been experiencing delays.

We anticipate that our capacity will be stepping up during the third quarter and in fact we have been a gross production rates of around 100 million standard cubic feet a day of wet gas over the last several weeks. We currently expect to touch a 120 million standard cubic feet a day, sometime in August and then step up in increments to about a 170 million standard cubic feet per day of wet gas by December.

On slide 13, we provide an illustration of how this gross wet gas capacity is likely to convert to a net equivalent reported production figure. The blue line is the total of the contracted gross wet capacity that I just reviewed on the previous slide. The flow diagram at the bottom lays out the assumptions we used which are based on our second quarter production figures.

As you can see, we currently see a roughly 20% uplift from gross gas production to net equivalent production. The red line represents how that production will be reported on a net equivalent basis accounting for gas shrink processing and royalty.

Moving to slide 14, I’ll address the performance of our wells in our Galvan Ranch area. On the bottom of the slide, there are production and flowing pressure versus time plots where three Galvan Ranch wells with production histories of around one year.

The plots are on a normal scale with a wet gas rate shown as red line and the flowing tubing pressure shown as blue lines. As you can see, even after a year of production, these wells are producing a constrained rates of around 4 to 5 million standard cubic feet a day of wet gas, at high tubing pressures. The reason the rates bounce around so much over the year is because at various times, we were more or less constraint due to our increasing well count and fluctuating transportation limits.

These wells are clearly capable of much higher rates if we could transport the production, for that we’ll have to wait for additional capacity to be available. I should note that these three wells have condensate yields varying from 13 barrels per million standard cubic feet of gas to about 30 and all three wells have high NGL yields.

We have estimated the EURs of these three wells by several methods and our approved estimates are currently between 6.6 and 7.5 BCFE. Our expected case reserved figures for these particular wells are significantly higher however and we fully expect their proved reserved estimates to move up over time. Now these three wells were early delineation wells and were drilled at fairly wide spacing.

The Galvan 10H and 14H wells shown were drilled 1,250 feet apart, which assuming at 5,000 to 6,000 foot lateral is roughly 160 acre spacing. The ultimate reserves we were booked for development wells in this area will be based on the production demonstrated by wells drilled at development spacing. We currently have four spacing pilots in operation across our operated acreage at spacing down to 625 feet, and Anadarko has an additional pilot just north of Galvan Ranch being drilled at 300 foot spacing.

We hope to have a better sense of the impact hydro development spacing might have on well economics and EURs later this year. In the meantime, these results are certainly encouraging and provide support from my comments earlier about being able to fill our pipeline space without as many wells producing.

Before leaving the operated Eagle Ford, I should note that during the quarter we completed and announced an arrangement with our friends at Regency in which they will be providing us with midstream and gathering services in the field. This arrangement allows us to focus our personal resources and capital on the drilling and completion side of our business. We still need to conclude some additional transportation arrangements to handle all our expected oil volumes and we are making progress on those as well.

Moving to the outside operated Eagle Ford shale program on slide 15, Anadarko continues to move forward aggressively and added additional rig count during the quarter. At this time, we anticipate they will run 11 to 12 rigs in the play for the remainder of the year. Our average net quarterly production in this program increased 30% quarter-after-quarter and we look forward to our continuing participation in Anadarko success.

Slide 16, addresses our Bakken Three Forks program. The big story this quarter was clearly the flooding that occurred in North Dakota. As the graph on Slide 16 shows our production in the program actually shrank slightly quarter-over-quarter, like other operators in the Williston Basin, our drilling and completion activity was impacted and we had to shut-in some production. At the peak of the flooding, we had approximately 1,500 barrels of oil equivalent per day of net production shut-in. As the flooding has receded, the amount of shut -in that production has shrunk to around 800 barrels of oil equivalent per day.

We expect most of the shut-in production due to the flooding to be back online early in the third quarter. We are setting up a third drilling rig right now in the play, however, due to the flood impact we are behind schedule on our drilling program and we will likely fall 4 or 5 gross wells shorter by plan number of 34 completions this year.

Our costs in the Bakken Three Forks are also running higher than we budgeted due to both the larger size of the completions we’re now pumping and general industry costs pressures.

Moving on to Slide 17, I will address some of our other operations. Our operated Haynesville program continued to see solid results in the Shelby Trough area of San Augustine County, Texas during the second quarter. The Ericsson 1H in which we have a 100% working interest had a seven day initial production rate of 14.8 million standard cubic feet equivalent per day at an average flowing tubing pressure of 8,900 pounds.

The Cortes 1H in which SM also has a 100% working interest, had a seven day IP at a 11.8 million standard cubic feet equivalent per day with an average flowing tubing pressure of 8,700 pounds.

I should note that each of these wells holds not only Haynesville acreage but significant uphold potential including a little volume. We believe that the resource potential on our East Texas acreage including both the Haynesville and Bossier wells could be as much as 1 TCFE. At this point, based on the performance of our wells we decided to retain our position in this play and are no longer pursuing a farm down or joint venture.

We’ve plans to run a one rig program until that work is complete, we estimate that it will take us until September of next year to finish drilling and completing the necessary wells. Once we get our acreage to HBP status we will decide the best timing for future drilling.

In the Niobrara play, we drilled three more operated wells on our acreage south of the Silo field and southeastern Wyoming during the quarter. We completed one of those wells, the Polaris 124H, where we operate the well with a 38% working interest. The well had a seven day initial production rate of approximately 950 barrels of oil equivalent per day. Our acreage position in this area totals about 26,000 net acres. Several analysts have noticed that we have also been applying for some well permits in the Powder River Basin. We’ve been adding acreage there and now have roughly 63,000 net acreage in the Powder, which is perspective in several intervals including the Niobrara.

We planned to drill several exploratory test in that area during the second half. In total, we now have roughly 89,000 net acres in Eastern Wyoming that is perspective for the Niobrara.

I am now on slide 18, in the Granite Wash we operated one drilling rig in the second quarter. We drilled several successful wells including a successful test in the Cottage Grove interval one of the shower oily washes. The root for 60H, a 44 working interest percent Cottage Grove test in Wheeler County, Texas had a seven day average initial production rate of approximately 1,380 barrels of oil equivalent per day. Our plan is to continue focusing our efforts on oily wash opportunities with two rigs running in the play for the remainder of this year.

In the Permian, we have now drilled eight 20 acres down space wells in the speedy packed deal. Early indications based on rates so far are positive, but there will be sometime before we can reach a conclusion on this Wolfcamp program and can estimate a location count for the rest of 20 acres.

In the meantime, we are moving the rig north to draw test wells on a roughly 87,000 net acre block of acreage we have accumulated in Borden, Garza and Linn counties. The area is perspective in the Mississippian section as well as the Wolfcamp shale and we will be testing both intervals in the second half.

Slide 19 then shows our revised capital investment plan for 2011. I discussed the changes in the Eagle Ford drilling program earlier, again our assumption is that we are paying our own way in a non-op activity that are pre-transaction working interest through the third quarter. Note that though our arrangement with Mitsui is for 90% carry in non-op drilling related activity after closing, we are being reimbursed for some that costs through an additional 10% carry. The other significant change in the drilling program relates to our operated Haynesville Shale program whereas I mentioned we have decided to continue drilling in order to hold our acreage.

In the non-drilling capital, most of the cost increase relates to our acceleration of water handling facilities construction in the Eagle Ford. In summary, we believe our capital investment in 2011 will total about $1.55 billion.

Moving to slide 20, let me layout early capital guidance for 2012. Our major assumptions here that we will be participating in the APC JV area, at about 14.5% working interest, but our spending will be 100% carried for the year other than a small amount of net costs for midstream facilities. We also are assuming we will complete HBP-ing our Haynesville acreage in 2012.

We have quite a bit of flexibility in the rest of our spending, allowing us to focus our activity on the portions of our inventory with the highest returns. We plan to increase activity in the operated Eagle Ford, the Bakken Three Forks and the Granite Wash.

We will be working over the next several months to determine where exactly we will invest our other operated capital. Our testing plant in the Niobrara and the Permian later this year will certainly influence this decision. Our total projected investment range for 2012 is $1.4 billion to $1.5 billion.

Moving to our production forecasts, slide 21, shows our current forecasted projections for 2011 and 2012 production. As you can see our increase capital investment program and the projected investment by others on our behalf has and will continue to result in significant production growth.

With that I am going to turn the discussion back over to Wade so that he can discuss our projected cash flows and financing for our planned investment program.

A. Wade Pursell

Thank you, Jav. So slide 22 will provide an estimate of what we expect our funding needs to be in 2011 and 2012. Top line of the table shows the capital expenditure forecast that Jav just reviewed, 1.550 billion this year and $1.4 to $1.5 billion in 2012. The next line is our current estimate of what our operating cash flow will be in those expected periods.

I should caveat that this operating cash flow estimate by saying that it assumes current strip pricing and it can change significantly as commodity prices move. And below the initial GAAP figures, we have listed out the divestitures that we have introduced during the year. As you can see a large part of our 2011 spending GAAP is addressed to this divestiture activity with the remaining amount more than covered by the 350 million of high-yield notes issued earlier this year.

In 2012, we expect to see a similar manageable funding GAAP, we have 1.3 billion un-drawn borrowing base that we can tap into as needed. For 2013 we expect to see our capital program within our operating cash flow while generating double digit growth. You might recall that this has been our stated goal during SM’s transformation over the past few years. Well in summary, we feel we’re sufficiently capitalized to fund our capital problem in the foreseeable future.

With that I will hand the call back to Tony for his closing remarks.

Anthony J. Best

Thanks Wade, thank you Jav. As you can tell from our financial and operational updates, this has been a very high activity quarter with record production and over $1 billion in funding transactions. We have been able to get through our divestiture processes and provide our shareholders with more detail and clarity to our future plans and growth potential. We look to increase production by nearly 50% year-over-year in 2011, which is a testament to the strong drilling portfolio that we have now built.

In 2012, we look to build upon that growth and get SM Energy’s production to over 200 bcf equivalent for the year. While the drilling inventory we now have is robust, we still keep an active exploration program while we continue to test new geologic formations. We’ve had encouraging results in both our Niobrara Shale in Eastern Wyoming as well as the Cottage Grove in the Anadarko Basin of North Eastern Texas. From a capital standpoint, we have been able to close the majority of our current year funding gap to the various divestitures that we have entered into so far this year.

While these proceeds will help strength the gap, we will be able to use our strong balance sheet to fund the projected gap for 2011 and 2012. With an un-drawn credit revolver at the end of the second quarter we believe as Wade mentioned that we are sufficiently capitalized to fund our projected capital programs. In all SM Energy is poised to grow significantly over the next two years with its extensive drilling inventory and strong balance sheet. And, I might add, with our expanding project slate, we expect to deliver continued growth and returns for our shareholders well into the future.

With that, we will now turn the call over for your questions.

Operator

(Operator Instructions). Our first question comes from the line of Mike Scialla from Stifel Nicolaus, please proceed.

Michael Scialla – Stifel Nicolaus

Good morning, guys.

Anthony J. Best

Good morning, Mike.

Michael Scialla – Stifel Nicolaus

Nice numbers. Can you give some impressive guidance on growth for 2012, any idea on what the production mix might look like for that year?

Javan D. Ottoson

Mike, this is Javan. I think, you have been expect that our gas percentage will fall some maybe 2% or 3%. As long as we continue to drill in Haynesville, the gas numbers are going to be, it’s going to be pretty sticky. So, they’re big wells and it drives our, you know obviously, we are in the 100% so it keeps our gas percentage around where it is. But, they will fall some over the next year.

Anthony J. Best

Mike, this is Tony. I would say you know, if you’re thinking about the spilt it’s probably 57% gas, 43% liquid and as Jav mentioned that would be trending down slightly.

Michael Scialla – Stifel Nicolaus

Okay. And the three wells that you showed in our slide presentation in Galvan Ranch are those intended to be representative of the whole area or why did you pick those, are those the three best or just the one you have the most history on, what can you talk about that I don’t know?

Anthony J. Best

Yes, they are the ones that we have the most history on as you look at those, you will see they have been on for almost a year, all three of them. The other wells that were drilled in the area are very similar, but we don’t have as much production history.

Michael Scialla – Stifel Nicolaus

Great, Okay. And the tax break you receive, the production tax break you receive for the quarter, how long do you expect that to last?

Anthony J. Best

Well, the reason that you’ll see the number lower in the second quarter is because we are able to be comfortable that we are achieving that break. So, there was some catch up in the second quarter, going forward we believe that will be able to achieve it and that’s reflected in our guidance.

Michael Scialla – Stifel Nicolaus

Okay. And then, last one from me, I just want to touch on the Niobrara a little bit, can you talk about your decision to move into the Powder and how you will compare that acreage with the acreage that you have in the DJ?

Javan D. Ottoson

Well, the Powder portion of the Niobrara, this is Javan again, is very different, its quite a bit deeper. Its more of a basis centered kind of accumulation higher pressured, over-pressured, in fact, we expect, I think it’s probably more a volatile oil type reservoir as opposed to the fairly low GUR production we produced in South Eastern Wyoming, so, it’s very, very different. There have been some good wells drilled, there is a number of additional wells being drill, there is also a number of other targets in that area in other intervals other than the Niobrara which we think we’re going to have some horizontal potential as well. We have held acreage in the Powder for quite sometime, and we have added some over the last year. We just haven’t really talked about it, but we think a position we put together now is pretty strong.

Michael Scialla – Stifel Nicolaus

Does some of that position you have does that include some of your old legacy acreage or is this all new acreage?

Javan D. Ottoson

It’s not all new acreage now we did have – we have had acreage there for some quite sometime that’s a lot of which in fact is HBP.

Michael Scialla – Stifel Nicolaus

Great, thank you.

Operator

Our next questions come from the line of Nick Pope from Dahlman Rose. Please proceed.

Nicholas Pope -- Dahlman Rose & Co.

Good morning guys.

Anthony J. Best

Good morning, Nick.

Nicholas Pope -- Dahlman Rose & Co.

I was trying to reconcile the production beat here today it looks like kind of the bigger areas where fairly in line. Did you provide production numbers for the Haynesville and Mid-Con, maybe Permian for the quarter?

Javan D. Ottoson

For the quarter, it will be posted in the Q, Nick.

Nicholas Pope -- Dahlman Rose & Co.

Okay. Then just kind of moving on, I know, you guys have talked historically about the Eagle Ford, how you kind of view the economics, I guess across the whole position from north to south, its fairly similar economics just changing profiles of volumes and components. I was wondering I guess like with Galvan Ranch, I guess some of the – again looks like improving results there in Galvan Ranch, are you seeing like sweet spots emerging or you still think like the entire position is, you are seeing fairly consistent returns on what you’re drilling?

Anthony J. Best

I would have to say that I think Galvan Ranch here is a sweet spot and I think that demonstrate not only by our drilling but by Anadarko’s drilling as well. With that said, we have had good solid results, kind of lot of other wells and other areas as well. And, we think a very high percentage of these acreages going to drill out.

As you get farther north on our other acreage to the west, you do get lower EURs, we have higher condensate yields, I would say I think Galvan wells have outstanding economics and the others may not be as high, but again, I think its going to drill out.

Nicholas Pope -- Dahlman Rose & Co.

Okay, sounds great. And, I guess, just with the Bakken, the constraints I guess that you talked about during the quarter, like how much production do you think actually was down relative to where you expected during the quarters because of the weather down time versus like kind of flood completion during the quarter?

Anthony J. Best

Well we haven’t added up on a cumulative basis as we mentioned at a peak we’re down about 1,500 barrels a day net and we are still down about 800. So, if you average those two numbers you’ve got a figure 1,000 to 1,200 barrels a day, we are shut-in for most of the quarter. It was off and we have some periods where it was again towards the high end of that range and now it lower. And, I would say that a lot of our delays, we had a couple of incidents that delayed our drilling. Obviously, a lot of you know, we had well control incident on the Janes well right toward the end of the first quarter, we took about a month off fracking until we really felt comfortable getting back in the field and going after, by that time basically the flooding had started.

So, we were significantly delayed in our completion activity which as a result will be 4 or 5 wells short by year end. So, for us it was a combination of the flooding and than of course delays in our completion activity which has impacted our production there.

I think, in fact, if you look at our performance for the quarter and consider the fact we really didn’t get much real brake on our transportation issues in Eagle Ford and we had massive flooding in Bakken and you look at our growth, it really is pretty impressive. I mean, the real, the engines of our growth where we are investing significant amount of money in our operated program, really didn’t come up that much during the quarter and yet we are still able to out perform our guidance.

So, I think once those two things kick in and we really start to ramp rates in those areas should be pretty impressive.

Nicholas Pope -- Dahlman Rose & Co.

Absolutely, I think it is and then just like one last thing to clean up, just the timing of the Eagle Ford deals, is it just, you are expecting the Mitsui deal to close at the end of the third quarter, is that the same timing for the LaSalle County position as well, that you are expecting right now?

Anthony J. Best

Our assumption is that both of them will close before the end of the third quarter.

Nicholas Pope -- Dahlman Rose & Co.

Yeah, that’s all I had, great job guys, thanks.

Anthony J. Best

Thanks Nick.

Operator

Our next question comes from the line of Joseph Bachmann, from Howard Weil, please proceed.

Joseph E. Bachmann – Howard Weil

Good morning, guys.

Anthony J. Best

Hi Joe.

Joseph E. Bachmann – Howard Weil

I had a few questions Jav, first on the CapEx, just wondering on the increase for this year, how much of that was related to cost inflation?

Javan D. Ottoson

Well, there is 20 million there that’s specifically called out on the Bakken piece. I think you could probably assume about $30 million of cost increase on the Eagle Ford side or maybe $50 million in total of that is cost increases.

Obviously, we absorb some cost increases in some of the other areas as well, but those are the big headline number, obviously we are spending most money. So, I would say about $50 million.

Joseph E. Bachmann – Howard Weil

Okay. And then, switching over to the Haynesville, can you talk about where, have you seen any kind of relief in service costs here or rigs rates are holding up because of the demand in the Eagle Ford?

Javan D. Ottoson

You know, Joe, we really haven’t seen a lot of cost reductions here yet in, it’s a little disappointing, I think it’s consequence of the 180 some rigs that are running in Eagle Ford now that, we are moving to one rig program. We have started, we have done a lot of things to try to cut the cost of our completions and our costs are coming down, not necessarily because the vendors are helping us but because we are just getting more efficient, we are drilling faster, we are starting to use some white sand in our completions in Haynesville which reduces our completion cost. So, we are using white sand and premium resin coated generally. So, we are doing things to try to get our cost down, but really haven’t seen a lot on the vendor side yet.

I would say, I think, fracs are becoming easier to get from a schedule standpoint which I would hope is a sign of the time, sign of good things. But really haven’t got a lot of price reduction yet on the vendor side.

Joseph E. Bachmann – Howard Weil

And up in the Granite Wash, what was the cost on that Cottage growth well is, some of that are cheaper and some of the other ones you drilled so far?

Javan D. Ottoson

I don’t think I have that exact, I know the number was around seven, but I don’t know the exact number and some of these wells I can tell you that deeper washes, are running eights, eight and a half, and if it’s a trouble free well, it’s probably in the sevens. Shallower washes should be in the sixes, but some of these early wells are little more expensive, we are doing a little bit of science on.

Joseph E. Bachmann – Howard Weil

Okay and last one from me just clarify what, I think you mentioned the amount of acreage exposure you had and the Permian with the Mississippi and in Wolfcamp, can you repeat that please?

Javan D. Ottoson

Yeah, I think we just quoted 87,000 acres that’s the upside and we have 13,000 or so at sweetie pack and another six or so at hop east. So, we let a little bit of the treadway acreage, the Northern acreage go just over on some acreage decisions we needed to make.

So, we had about 87,000 that we feel good about that.

Joseph E. Bachmann – Howard Weil

Great, great quarter guys, thank you.

Operator

Our next question comes from line of Welles Fitzpatrick from Johnson Rice. Please proceed.

Welles Fitzpatrick – Johnson Rice

Hey, good morning guys.

Anthony J. Best

Good morning, Welles.

Welles Fitzpatrick – Johnson Rice

On that, 63,000 net acreage on the Powder River basin, did you guys plan any near term tests in the Turner?

Javan D. Ottoson

Well, I am not aware of any near term tests in the Turner, we’ve got three Niobrara test planned this fall and we will be participating in some other things that people are doing, I am not aware of any near terms Turner tests.

Welles Fitzpatrick – Johnson Rice

And, of that legacy acreage how much bid is HBP?

Javan D. Ottoson

You know, I don’t know that number of the top of my head, Welles, we can find that out for you.

Welles Fitzpatrick – Johnson Rice

Okay. And then, you guys also mentioned that you are kind of getting excited about the Bossier, do you have any near term plans to test that horizontally or maybe the Cotton Valley on the Haynesville acreage?

Javan D. Ottoson

We are going to drill a Bossier test, I believe it will be either late this year or early next year. We had a well that we completed in the Haynesville vertically to hold some acreage very early on. In that particular block a Bossier well will hold the Haynesville. So, we’re planning on re-completing that well into the Bossier section taking it lateral but that will be probably, if not late this year early next year.

Welles Fitzpatrick – Johnson Rice

Okay, perfect. And in regards to the spacing, I think you guys had a better understanding later this year, is that sort of third quarter or fourth quarter or you just kind of a up in the air for now?

Anthony J. Best

Well, I have a list I think of about 20 different pilots between us and Anadarko that we are planning to drill on different spacing numbers, and I think, it varies wide it’s going to vary a lot depending on where you are on the acreage, I think frankly the lower productivity acreage will probably gets based to a lower level then the higher productivity acreage. So, it’s kind of an interesting issue because I mention on the call that you know, Anadarko run a 300 foot spacing test just North of us at Galvan.

So, we are going to have a wide range of date to look at, it will take us a while to understand it. The important thing I think to know though is that you know, EUR is not an economic metric, what really drives the spacing decision is going to be how much production do we get out of these wells in first 18 months or 2 years.

So, it’s not going to be forever us making this decision, we are going to look at the economics of the – essentially we will look at IPs and early time production data, and make a choice on economics. The reason I’m cautious about all these EUR numbers is because I think you got to be careful not to throw an EUR number out there that’s based on 1,250 foot spacing and then find out when you drill at the 300 feet, that EUR is lower, the economics maybe fine. But, if everybody is out there and they put that big EUR number into a model to reduce spacing you could end up with some significant overestimating reserve.

So, we are very comfortable with where we are at, we think we will have a lot of information by year end that’s going to lead us to a development spacing. And a lot other people are obviously supporting that with their own – with other data. So, I think year end is a reasonable timeframe to have a sense of it, the next three rigs we are bringing in are pad drilling rigs. We are going to be drilling multiples wells of a pad, we’ll be holding all those wells and fracking them all at once. So, I think by year end we are going to be in more of a development mode, what we know the ultimate answer on all the acreage no, but we will have a real good sense I think as we come into 2012.

Welles Fitzpatrick – Johnson Rice

Okay, perfect that’s all I have thanks guys.

Anthony J. Best

Thank you.

Operator

Our next question comes from line of Brian Lively with Tudor Pickering Holt. Please proceed.

Brian Lively – Tudor Pickering Holt

Good morning, thanks for all the additional details in the quarter, it’s really helpful. Looking at for three wells that you guys put out for Galvan Ranch, just a clarification on the preview your estimate is that post processing or is that just a wet gas volumes?

Anthony J. Best

That’s a three stream number.

Brian Lively – Tudor Pickering Holt

Okay. And on that same slide, the tubing pressures, I have kind of focused on being pretty high for a longtime, do you have a sense of what the drawdown is on those completions now or it some ballpark range?

Anthony J. Best

You know, in terms of bottom or pressure.

Brian Lively – Tudor Pickering Holt

Yeah I mean, they are fallen at $1000, $500, do you have a sense of how hard you’re pulling the information itself?

Anthony J. Best

No, Brian I don’t have that number of the top of my head, I can say it’s probably not, it’s not a lot of drawdown I mean, these are, we are not pulling these wells very hard, the choke sides are very low – I don’t know the exact bottom numbers.

Brian Lively – Tudor Pickering Holt

Right, and then that was really the point I was trying to get to it is that you mentioned on the call that these wells could flow at higher rates, and do you have a sense of where they could flow at on under you know, at $2,000 or $1,000 flow in tubing pressure?

Anthony J. Best

Well, I’ll give you, let me give you some, this is sort of anecdotal piece of data, I don’t have the exact data on those three wells, but I can tell you that I saw some or the other day on a Galvin area, right now we are producing about $60 million a day of gross wet gas out of that area. If we could get those wells to line pressure they would make about a $100 million a day.

So, there is about 40% out, if you can get to like to something like an 80 or 100 pound line pressure, I’ll really admit that’s a lot lower than where we are right now. There is a lot of shut-in capacity, I don’t have that exact volume of pressures for you but that’s a, there is a lot of opportunity here as we get additional capacity to open the chokes and be able to work. We are putting a 16 inch gas trunk line what we call the spine in, all the way through our acreage all the way from the tip of Galvan, all the way up to Briscoe and that will be completed in October. So, we will be able to real gas to both ends of our gas optic, optic capacity in a Morgan should be there shortly and we should have quite a bit more capacity available as we move into September so you know, I think we will be able to crank up rate pretty quickly here.

Brian Lively – Tudor Pickering Holt

Perfect and that really leads well into my next question, what kind of a 2012 guidance I assume that the guidance drive from your expectations on your Eagle Ford type curves plus the contract to takeaway. I’m just wondering if that 35% to 40% growth includes any intermittent or spot volumes?

Anthony J. Best

Yeah it’s a great question we’ll looked at it several different ways, we looked at it assuming that we couldn’t get anything more than our contracted capacity, and then we ran a more unconstrained case kind of an optimum case where we actually assume we could pick up some interruptible. When we look at that with respect to the capital spend on the well side, and we take that incremental capital and invested in other opportunities that we have. The rate you get are almost the same.

So, we may or may not depending on whether we can give interruptible capacity or not beyond our current firm capacity I don’t think, the overall rate for the company changes that much. There is going to be an opportunity, I think for us to go out and potentially secure more capacity but, we haven’t really baked that in necessarily to the guidance.

If we did bake it in again that’s why we have given a range of capital and range of volumes but, we can certainly – we can certainly make more gas and we’re contracted to the ship right now.

Javan D. Ottoson

Brian I think that’s a good example having a diversified portfolio where we can reallocate the capital, where we get the best economics depending on market condition you get still, you know, reach what we think will be the 35% to 40% growth number.

Brian Lively – Tudor Pickering Holt

And so, if you are able to get the interruptible volumes you’re saying that the 35% to 40% corporate wide growth estimate wouldn’t change significantly is that what you are saying?

Javan D. Ottoson

What we are saying is that that essentially you can – it depends on the dollars right, you can get to that 35% or 40% in a couple of different ways, across that capital range. Our base assumption is that we’re going to be produced to our capacity. If we can go beyond that capacity we could potentially move the money around and do it that way, and we’ll do it based on whatever the ways is the most capital efficient.

Brian Lively – Tudor Pickering Holt

Okay, that makes sense and the – just kind of the last question I have is really on other initiatives. Are you guys, what other initiatives are you guys pursuing to expand the midstream infrastructure side of Eagle Ford post the, you know ETC stuff that you guys have already released?

Javan D. Ottoson

Well we’re working on well transportation deals mostly Brian, I mean, we have several deals we’re negotiating. We need to get those in place probably for sometime late 2012, 13, right now we’re still trucking all our oil and over the long haul that’s not sustainable.

We do think – as we continue to firm up our production forecast that we need to look at late 2012, 13 again with respect to should we take some additional, I guess handling capacity assuming its available and maybe even go firm on some of that. So, you know this is just going to be ongoing brick-by-brick addition of infrastructure.

As we get more and more comfortable with our production forecast and spacing. We will continue to add commitments, going to remember every one of those things we do as a commitment associated with it as well. So, we’re going to do it in a balanced way, as Tony mentioned. The great thing is we have other – we have other portfolios that has great economics as well.

So, we can kind of balance that type of commitments we need to make a little bit knowing that you know, we had some place else to go with the capital that also has very strong economics.

Brian Lively – Tudor Pickering Holt

Thank you.

Anthony J. Best

Thanks Brian.

Operator

Our next question comes from the line of Scott Hanold from RBC. Please proceed.

Scott Hanold - RBC Capital Markets

Good morning, guys.

Anthony J. Best

Good morning, Scott.

Scott Hanold - RBC Capital Markets

Just to I’m clear and you may have said it or may not, but I’ll just ask the question. If you look at sort of your Eagle Ford Shale production what are you running at approximately rate now, I mean equivalent basis and what do you think it could be if you didn’t have any constraints in place?

Anthony J. Best

Well this last week, we are making a 100 million a day gross rig production. So that’s gross and wet gas. If you follow the slides, I forget which slide number it is right now, and there it’s about 20% up lift between gross wet to net mcfe equivalent. So, that would say that right now we are producing about a 120 million a day equivalent net production from the operated Eagle Ford, and you’ve got to add to non-op to that.

Okay, as we go forward what we said – what I said in the call as we think we touch 120 on the gross wet basis sometime in August will be somewhere around 170 by year end. You can essentially take both those numbers multiplying by 1.2 to get a net mcfe kind of a number.

By the time, you get into the next year we should be in the 200, 220 capacity kind of range again we are not accounting necessary and having all that on day one, but overtime we certainly think that will be the ballpark where we will be and seeing the first half. Again, gross wet times 1.2 is pretty easy number to get to our net.

Scott Hanold - RBC Capital Markets

Okay now I appreciate that clarifies it for me. And then you know, real quick on the Permian did you all say that the stuff being in Borden, Garza and Lynn Counties did you just pick that up recently or that stuff you all have before?

Anthony J. Best

Actually, we have had the acreage for quite some time, we’ve been drilling some Mississippian exploration wells and we’ve been planned around with the concept of drilling the Wolfcamp Shale and I think we are moving in that direction right now.

Scott Hanold - RBC Capital Markets

So, with the wells that you tested get delays this year will they be horizontal wells?

Anthony J. Best

Yes, we’ve drilled, in the Mississippian we have drilled some verticals and some horizontals that Wolfcamp Shale will all be horizontals that we drill.

Scott Hanold - RBC Capital Markets

Okay anything to say about some of the industry activity around you guys?

Anthony J. Best

Well, there is a lot of leasing out there, not a lot of drilling yet.

Scott Hanold - RBC Capital Markets

Would you be buyer of incremental leases?

Anthony J. Best

It depends on what they cost and where they are. It’s just a best big player out there, Scott that had been picking up large blocks of acreage, but like Jav said its mostly leasing not a lot of drilling just here.

Scott Hanold - RBC Capital Markets

All right, understood, thanks guys.

Anthony J. Best

Thanks.

Operator

Our next question comes from the line of David Tameron from Wells Fargo. Please proceed.

David Tameron -- Wells Fargo Securities

Hi good morning congrats on a great quarter, and for getting the Eagle Ford deal done.

Anthony J. Best

Thank you

David Tameron -- Wells Fargo Securities

Couple of quick questions the carry portion of this, I’m kind of thinking about 300 next year may be 100 for the remainder of this year, is that a loss in the 100 is that in the right ballpark?

Javan D. Ottoson

Yeah, I think it’s about should be more like 150 this year, I think and then 300 for next year seems above right.

Anthony J. Best

Yes, that’s in the ballpark, David.

Javan D. Ottoson

Yeah.

David Tameron -- Wells Fargo Securities

Okay, for Anadarko you said, they’re going to run 12 – you assume 12 rigs through the end of this year? Did you keep that flat for your 12 assumption or can you give us any color there?

Javan D. Ottoson

Our 12 assumptions is around 12 rigs.

David Tameron -- Wells Fargo Securities

Okay, all right and then --

Javan D. Ottoson

David, that 150 I quoted maybe a little too high or maybe more like 100 it should be about 50 million a month I think that’s –

Anthony J. Best

We are double checking it.

Javan D. Ottoson

We are double checking that number.

David Tameron -- Wells Fargo Securities

Okay, and then last question, Chesapeake filed a trust out there in the Granite Wash. Do guys have I know you have various working interest throughout the basin with them is there, are you aware of any portion of your acreage that’s getting rolled into this trust?

Anthony J. Best

No, David I am not.

David Tameron -- Wells Fargo Securities

Okay, that’s all I got.

Anthony J. Best

All right, thanks David.

Operator

Our next question comes from the line of Subash Chandra from Jefferies. Please proceed.

Subash Chandra - Jefferies & Company, Inc.

Yeah question on for next year operated Eagle Ford. Do you have a range of maybe how many wells you might have to put in backlog, pending capacity improvements and perhaps this number gets you know, somewhat large is it possible that you might just save a few bucks and slowdown the program a little bit and allow for the capacity to play catch up?

Javan D. Ottoson

Well, we put in the program is 95 wells which is what we think we can drill to keep up with our capacity and clearly if some for reason or other the capacity doesn’t materialize we would have to consider that and we would also be out looking for interpret for another pipes. Our current plans to drill and complete 95 wells we think that’s basically a balance with our capacity maybe a little more frankly than our total capacity by year end.

Subash Chandra - Jefferies & Company, Inc.

Okay. So, there will be no on those 95 wells you don’t expect any material backlog.

Anthony J. Best

Well, we certainly hope not.

Subash Chandra - Jefferies & Company, Inc.

All right, okay. And, this CapEx that you have in other categories I would assume none of that’s in your production guidance?

Anthony J. Best

We don’t include anything in our production guidance for exploration. We do include some volumes for the things that are in other operations.

Subash Chandra - Jefferies & Company, Inc.

Okay. How much of the Haynesville wells costing now?

Anthony J. Best

Right at $11 million.

Subash Chandra - Jefferies & Company, Inc.

And could sort of just, last question here, explain in more detail the sequential decline in lifting cost here, how much you would attribute that to the asset sales of high class properties, how much of that might be just surgeon low cost Haynesville production or how much could be just surgeon Eagle Ford or whatever do you want to put any words in your mouth?

Javan D. Ottoson

Well, there are a number of factors that are impacting, we had a long discussion of this last quarter, part of it certainly is bringing on a whole bunch of low cost production. Part of it was that a Rocky’s number ran really low the quarter because we simply could not get out to wells other than shutting them in we couldn’t get out to maintain things, so there were lot of work over that we didn’t do, WE is in that number as well.

And then we’ve consistently, and as much as we try, we have consistently over estimated the rate of growth of these operating cost and lot of that I think is just we’ve been, maybe a little too conservative about our views of the economy in general and the fact that we thought labor costs would start stepping up, steel and other factors that factor in that. We just been somewhat conservative and we just, frankly we’ve been under running our LOE on a pretty consistent basis, we keep trying to get it more in line, it’s a little tough when you’re growing as fast as we are anyway but I think we probably just been a little too conservative on some of that.

Subash Chandra - Jefferies & Company, Inc.

Okay. All that helps thank you.

Anthony J. Best

Thanks.

Operator

Our next question comes from the line Andy Coleman from Raymond James. Please proceed.

Andrew Coleman – Raymond James

Hi, great thanks a lot. I have a question for you about, just looking at 2012 just a credit facility, so you get about 300 million there roughly with 3.5 notes and then about another couple of hundred million from the CapEx, I guess needs here in the short-term I guess. I assume you’re getting some bump in your credit facility next year because of their ex-reserve bookings, but would that potentially leads you to either sell some more assets or slow down drilling elsewhere to keep less and half of that facility drilling?

Javan D. Ottoson

Yeah, it is that’s fair question. I would not anticipate getting to that point, I think you just said it very well. I expect the borrowing base to continue to increase with the reserves increasing, so that’s first of all and there will be some drill in that facility most likely next year, but I wouldn’t anticipate as getting to a point where we think we need to do, to do any divestitures.

Andrew Coleman – Raymond James

Okay, good. And then the one question on you income statement, did you guys have any capitalized interest for the quarter?

Javan D. Ottoson

Yeah, we certainly did. I don’t have that number close by.

Andrew Coleman – Raymond James

I’ll check with Brent afterwards.

Anthony J. Best

Yeah, we’ll get to you Andy.

Andrew Coleman – Raymond James

Thank you.

Anthony J. Best

Thanks.

Operator

Our next question comes from the line of Joe Allman from JP Morgan. Please proceed.

Joseph Allman – JP Morgan Securities, Inc.

Thank you, good morning everybody.

Anthony J. Best

Good morning, Joe.

Joseph Allman – JP Morgan Securities, Inc.

Jav, how many Haynesville wells or sections you need to drill to hold the acreage?

Javan D. Ottoson

We had eight more wells to drill after the two we’re on right now.

Joseph Allman – JP Morgan Securities, Inc.

Okay, that’s helpful. And then in terms back into the Eagle Ford, in your slide you said next year you expect 300 non-operated wells, what’s that number for 2011?

Javan D. Ottoson

Great question, it’s probably going to be –

Anthony J. Best

I think it was around –

Brent Collins

We – Joe, this is Brent. We – I think we said early on in the year there was going to be 200 that was obviously got a lower rig counts.

Anthony J. Best

Lower rig count, rig counts are moving up. I would say it’s 12 or 250, probably it would be a good ballpark, for next we’re just basically ended up for rig count and kind of a daily days to drill type number that’s not based on anything Anadarko has given us, I should be clear about that that’s just an estimate based on how many days we think it takes in the drill in a 12 rig count. They haven’t given us, I do not have a schedule from them on what they planned to do next year.

Joseph Allman – JP Morgan Securities, Inc.

Got you, okay that’s helpful. And then over to the DJ basin, I think what you got were 26,000 net acres there in the DJ?

Anthony J. Best

That’s right.

Joseph Allman – JP Morgan Securities, Inc.

Okay. And so how many Niobrara wells have you drilled so far and how much of that acreage have you, do you think you’ve proved up based on your results?

Javan D. Ottoson

Well, we drilled 5, the first one was very successful, second one was not so it was kind of an edgy well, the third one I think we would say at this point was very successful. We were completing two more. How much have we proved that, I guess not to – I don’t want to come across, it’s too conservative but my view unless, until we get these 5 wells complete and we have our test program pretty much done I’m not going to throw up a great big flag and say we won here. I don’t think we’ve proven a lot yet, certainly we proven the wells with the wells we drilled but I think we need to get 4, 5 wells drilled in this thing and get some real results before we declare victory.

Our intend is that assuming these wells go well, that we will have a single rig program running all year here next year that sort of that other operated capital that we talked about. But really, there is a lot of variability from what we’re seeing in the well results, we think we have a strong geologic concept of why these wells produced where they produced but it is a very unique – a very unique area, I mean the reservoir is under pressured as opposed to the Powder where it’s over pressured. We don’t know if that’s just a result of being near the Silo field or if that’s just the way it is kind of on the edge of the basin there, but I think we’re doing some interesting things with our completions to try to make sure that we get a productive well.

Lot of people are doing, people trying slick water, there is people trying energized fracs, there is people doing gel jobs. I think there is little bit of a mix there but I think once we get through these five wells we’ll have a pretty good idea of what the risks are, what the range of outcomes are and can come up with sort of a mean expected well that would then drive a development decision.

Anthony J. Best

This is Tony, I would say at this point that the testing appears to be following our modeling, so we’re cautiously optimistic like Jav says, so we’ll complete the testing then determine the development opportunities after that.

Joseph Allman – JP Morgan Securities, Inc.

Now that’s helpful. And just lastly in terms of the Eagle Ford sales, how much less acreage did you sell than what you had planned?

Javan D. Ottoson

At one point in time we said we could sell up to 30% of our position which I believe is about 75,000 acres. We actually sold right at –

Anthony J. Best

39 plus 15.

Javan D. Ottoson

About 55, 54, 55, so.

Joseph Allman – JP Morgan Securities, Inc.

Okay that’s helpful. All right, thank you.

Anthony J. Best

Thanks.

Operator

At this time I would like to turn the conference back to Tony for closing remarks.

Anthony J. Best

Thank you all for joining the SM Energy call this morning. This is an exciting time for our company as we see the transformation really kick in and we continue to see significant growth. We appreciate your interest and look forward to our next update with you in November. Thank you very much.

Operator

Ladies and gentlemen that concludes the today’s conference. Thank you for your participation, you may now disconnect and have a great day.

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