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Executives

Clay Jeansonne – Vice President-Investor and Public Relations

Mark E. Ellis – Chairman, President and Chief Executive Officer

Kolja Rockov – Executive Vice President and Chief Financial Officer

Arden L. Walker, Jr. – Executive Vice President and Chief Operating Officer

Analysts

Abhi Sinha – Bank of America

Ethan H. Bellamy – Robert W. Baird & Co.

John Ragozzino – RBC Capital Markets LLC

Kevin C. Smith – Raymond James & Associates, Inc.

David Amoss – Howard Weil Inc.

Ted J. Durbin – Goldman Sachs & Co.

Praneeth Satish – Wells Fargo Securities LLC

Adam Leight – RBC Capital Markets LLC

Michael D. Peterson – MLV & Co. LLC

LINN Energy LLC (LINE) Q2 2013 Earnings Conference Call August 8, 2013 11:00 AM ET

Operator

Good morning, and welcome to LINN Energy’s Conference Call to discuss the Second Quarter 2013 Earnings. Today’s call is being recorded. At this time, I’d like to turn the call over to Clay Jeansonne, LINN Energy’s Vice President of Investor Relations for some opening remarks. Please go ahead.

Clay Jeansonne

Thank you for joining our second quarter 2013 Earnings Conference Call. In a moment, I’ll introduce Mark Ellis, our Chairman, President and Chief Executive Officer. But first, I need to provide you with disclosure regarding forward-looking statements that may be made during the call, the statements describing our beliefs, goals, plans, strategies, expectations, projections, forecasts and assumptions of forward-looking statements.

Please note that the company’s actual results may differ from those anticipated by such forward-looking statements for a variety of reasons, many of which are beyond our control. Additional information concerning certain risk factors relating to our business, prospects and results is available on the company’s filings with the SEC, including our Form 10-Q for the quarter ended June 30, 2013, which will be filed today, and any other public filings and press releases.

Additionally, during the course of today’s discussion, management will refer to adjusted EBITDA and the distributable cash flow, which are non-GAAP financial measures, and are reconciled to their most directly comparable GAAP measures in our earnings press release issued this morning.

Supplemental financial and operational information, including the company’s statement of operations, selected balance sheet data and guidance table has been posted to LINN Energy’s website at www.linnenergy.com in the Investor Center, under Presentations.

Following management’s prepared remarks, we’ll take your questions. I’ll now like to turn the call over the Mark Ellis, LINN Energy’s Chairman, President and CEO.

Mark E. Ellis

Thanks Craig and good morning. Joining us today from LINN are Kolja Rockov, Executive Vice President and Chief Financial Officer and Arden Walker, Executive Vice President and Chief Operating Officer. Let me start by saying that given the ongoing SEC inquiry, we are limited in what we can say during the Q&A session and we’ll not address any questions regarding the timing or scope of the SEC inquiry. Additionally, given the uncertainty of resolution of the SEC inquiry, we will not speculate on an expected closing date of the pending merger with Berry Petroleum. However, as I’m sure many of you saw in this morning’s press release, this afternoon, we intend to file with the SEC, our amended Form S-4 along with our second quarter Form 10-Q. As evident from our updated S-4 filing, we are still very committed to the Berry transaction.

Turning to our operational view for the second quarter of 2013, we achieved average daily production of 780 million cubic feet equivalent per day compared to 630 million cubic feet equivalent per day during last year’s period.

Now I’d like to go over a few high level observations from the second quarter and looking ahead the remainder of the year. We’ve experienced the challenging start to 2013; core capital performance, ethane-rejection and infrastructure curtailment, negatively impacted our production volumes. However, our current production volumes are up significantly from the second quarter average as evidenced by our average daily production in July of approximately 815 million cubic feet equivalent per day.

We are optimistic about the remainder of the year and expect to deliver annual production growth of approximately 8% to 10%. However, due to poor performance from the Hogshooter oil program during late 2012 and early 2013, production growth during the remainder of the year, while economically attractive does not provide the same margins as originally forecasted.

On a positive note, our efforts year-to-date to develop the Hogshooter oil interval in Oklahoma has exceeded the expectations. In addition, we are encouraged by the industry’s recent horizontal Wolfcamp results in the Permian Basin, which are in close proximity to LINN’s acreage in the area.

Now, I’d like to provide an update on our regional activities. Today, in 2013, LINN has successfully drilled nine wells in the oil producing Mayfield portion of the Hogshooter play in western Oklahoma. During the second quarter, LINN had four rigs active in this play, where we own approximately 25,000 net acres. We are pleased with the performance of these wells as they have come in on line with gross average IP rates of approximately 3,800 barrels oil equivalent per day and price of approximately 70% liquids and our average working interest is approximately 44%.

In addition to the Hogshooter interval, LINN has tested two other oil producing formations in western Oklahoma. We are encouraged by the early results that the shallower oil-bearing intervals in Oklahoma and our inventory currently stands at over 100 opportunities in this portion of Oklahoma.

Also in the Mayfield area, LINN recently entered into a development agreement on approximately 3,800 gross acres offsetting some of our properties, which we believe have the potential for Hogshooter and other oil intervals.

Our knowledge and technical expertise of the play gives us the confidence to enter into this agreement and we expect to drill approximately six Hogshooter wells on this acreage during 2013. LINN continues to make progress on improving cycle times and reducing well cost in the Granite Wash and Hogshooter intervals. The average spud to sales time has been reduced from approximately 88 days in 2012 to approximately 64 days in 2013, which represents a reduction of 27% year-over-year.

Also, well costs have been reduced by 11% from approximately $9 million in 2012 to approximately $8 million in 2013. LINN continually evaluates different strategies to develop our inventory in the most efficient way. Currently, we are negotiating a format agreement on certain leases on a portion of our acreage in Osage County, Oklahoma which has Mississippi Lime potential.

Our joint venture partner will carry a portion of LINN’s cost to drill these wells and potentially drill approximately 50 Mississippi Lime horizontal wells over the next two years. This JV will allow LINN to accelerate the development of this attractive inventory while spending significantly less capital. We hold more than 450,000 net acres in the Anadarko Basin of Central and Northern Oklahoma and Southern Kansas, which could provide the potential for similar joint ventures.

Now turning to our operations in the Permian Basin, we currently operate four rigs, which are all targeting the vertical Wolfberry play. In 2013, we drilled a total of 48 wells and have reduced cost by approximately 15% to $2 million per well this year. Unfortunately, much of the volume growth in this program has been offset by continued infrastructure constraints, which have affected both our capital development program and existing production in the basin. However, several pipeline and gathering systems are expected to come into service during the second half of the year. And we are hopeful this additional capacity will alleviate some of the constraints we are currently experiencing.

And due to the increasing horizontal activity by industry players in the area, it appears that much of LINN’s acreage could be perspective for horizontal drilling to one or more of the Wolfcamp and Spraberry intervals. We estimate that LINN has over 25,000 net acres in the Wolfberry play, which could have horizontal Wolfcamp potential. We plan to participate in four non-operated horizontal Wolfcamp wells later this year and spud an operated horizontal Wolfcamp well before the end of 2013.

In the second quarter, LINN began operating its first rig in the Jonah Field. We are currently drilling the last well on a six-well pad drilling location and expect to begin completions this month. In 2013, we plan to drill approximately 18 operated wells and participate in 50 non-operated wells and majority of these operated by McMahan.

Upon taking control of operations last November, our team quickly implemented a production optimization program, these efforts for the delivered product uplift of approximately 7 million cubic feet equivalent per day from 29 production optimization projects. We expect the projected net uplift associated with both operated and non-operated activity to contribute a meaningful amount of our volume growth during the second half of this year.

In the Hugoton Field, during the second quarter of 2013, we commenced a one-rig operated drilling program and expect to drill approximately 60 wells during 2013. The initial results are encouraging and in line to meet our forecasted average 30-day IP rate of approximately 250 Mcf a day with an average spud to rig release cycle times of just over two days.

Since assuming operations in July of 2012, we’ve implemented an active optimization plan consisting of tubing repairs and pump changes among other optimization projects. Today, we’ve performed workover projects on approximately 140 wells, which is added approximately 3.5 million cubic feet per day of production.

Now as referenced in our guidance, LINN expects production volumes to average approximately 820 million cubic feet equivalent per day for the third quarter, increasing to approximately 815 million cubic feet equivalent per day for the fourth quarter. These estimates do not include the potential impact of further ethane rejection, which could total approximately 10 million cubic feet equivalent per day in the third quarter and approximately 26 million cubic feet equivalent per day in the four quarter.

If ethane rejection occurs, we expect reported production volumes to average approximately 810 million cubic feet equivalent per day for the third quarter and approximately 824 million cubic feet equivalent per day for the fourth quarter. Our decisions on whether to reject ethane are made monthly based on economics at processing location in an effort to maximize value.

In some areas, we have the right to either reject or separate the ethane, while in other regions the decision belongs to the gas processor. Any future decisions to reject ethane will have a negative impact on production volumes, but no impact on revenue. For further information about the potential impact of ethane rejection, please view our supplemental pages which are found on the website.

Now even with the challenges we experienced during the first half of the year, our production volumes have turned a corner and are up significantly over the second quarter levels. We are optimistic about the remainder of 2013 and expect to deliver annual production growth of approximately 8% to 10%.

I want to close by taking a moment to thank our employees, who are an important part of our future performance and success. I also want to thank our unitholders and shareholders for their long-term dedication to LINN. We are grateful for your continued confidence and support.

I’ll now turn the call over to Kolja for his financial update.

Kolja Rockov

Thanks Mark. I would like to address the following topics in my discussion today; second quarter 2013 results, redemption of higher coupon senior notes, our amended and restated credit facility, and 2013 full year outlook. For the second quarter 2013, LINN reported total revenues of approximately $839 million, compared to $801 million for the second quarter 2012, which includes non-cash changes in fair value of unsettled commodity derivatives of approximately $271 million and $304 million, respectively, including the reduction of put option premium value over time.

We achieved net income per unit of $1.47 per unit in the second quarter 2013, compared to $1.19 per unit for the second quarter of 2012. These amounts included non-cash changes in fair value of unsettled commodity derivatives of approximately $1.15 per unit and $1.52 per unit, respectively, including the reduction of put option premium value over time.

In addition, we increased adjusted EBITDA by 13% to $362 million for the second quarter 2013, compared to $319 million during the second quarter of 2012. On a per unit basis, our distributable cash flow was $0.65 per unit for the second quarter 2013, which resulted in a distribution coverage ratio of 0.89. As a reminder, adjusted EBITDA and distributable cash flow are non-GAAP measures. Please see Schedule 1 in this morning’s press release for a reconciliation of adjusted EBITDA and distributable cash flow to their most directly comparable GAAP measures.

Last week, we announced the monthly distribution and dividend. LINN and LinnCo announced a cash distribution and dividend respectively of $0.2416 or $2.90 on an annualized basis. LINN’s distribution will be payable to unitholders on August 14, and LinnCo’s dividend will be payable August 15. This year we retire the remaining portion of two of LINN’s higher cost bonds.

In June, we redeemed the remaining outstanding principal amount of $41 million of the 11.75% senior notes due 2017 and in July, we redeemed the remaining outstanding principal amount of $14 million of 9.875% senior notes due 2018. Combined these redemption’s retired a totaled of $55 million in principal with a weighted average coupon of approximately 11.3%.

On May 31, we sold our minority non-operated interest in the Panther asset located in Western Oklahoma in Midstates Petroleum. The Panther divestiture closed May 31 and net proceeds from the sale of the assets totaled approximately $219 million, which we used to repay borrowings under our revolving credit facility.

In April, LINN amended and restated its revolving credit facility. Consistent with our renewal practices, we extended the maturity by another year through April 2018 to maintain a five-year facility. In addition, we increased the size of the facility from $3 billion to $4 billion, while the borrowing base remained unchanged at $4.5 billion.

As of June 30, LINN had approximately $2.6 billion available under its revolving credit facility. We also increased the number of lenders in the facility from 35 to 41. LINN also has one of the largest and most diversified hedging groups in the industry with more than 25 counterparties all A rated or better. Included in the supplemental pages, posted online, LINN has provided updated guidance for both the third and fourth quarters of 2013. We project coverage in the third quarter to be similar to our second quarter results while improving in the fourth quarter.

As Mark mentioned earlier, we’re pleased to file our amended S-4 with regards to the pending Berry merger this afternoon. and I would like to remind participants on the call that we will not give any further details regarding the SEC inquiry or the pending merger with Berry Petroleum during our question-and-answer session.

I will now turn the call over to the operator for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Our first question comes from the line of Abhi Sinha from Bank of America. Your question, please.

Abhi Sinha – Bank of America

Hey, good morning, everybody. Just wanted to ask on this, we’ve seen last two consecutive quarters, your coverage ratio has dropped below 1, and if at any basis continue to drop or even stay where it is, coverage ratio in current quarter might have still be below 1, so given the circumstances, how comfortable you are feeling maintaining the distribution level?

Mark E. Ellis

Yeah, Abhi, we’ve given obviously guidance to the end of this year. We’ve posted for the third quarter, and we feel confident in terms of the guidance that we posted out there about 0.9, I think, through the fourth quarter right. And growing to 0.95, I’m sorry, in the fourth quarter.

Abhi Sinha – Bank of America

Okay. Thank you.

Mark E. Ellis

Abhi, do you have another question.

Abhi Sinha – Bank of America

Yes, I just wanted to follow-up on that and so on the Permian side, if you see there is a lot of infrastructure constraints. Are you guys making efforts to move to the Western side, which has a bit less, about 9% share versus in Eastern side?

Mark E. Ellis

Yeah, let me let Arden comment on that.

Arden L. Walker, Jr.

Yeah, we have activity on both the east and the west. We prefer to be focused on the west because infrastructure issues aren’t as bad over there. Unfortunately, we’ve got acreage in both places, so we do have a little bit of development in both areas. The infrastructure constraints that we saw in the quarter amounts about 7 million a day of impact for us, there are a number of infrastructure improvements going on in the Basin right now, new plants, new gathering systems. We think eventually there will be some improvement in the infrastructure out there, but it’s been difficult to predict when that’s going to happen. We are actively working with our Midstream Partners, to try to improve the situation, but it does continue as we speak today.

Abhi Sinha – Bank of America

All right. Thank you. That’s all I have. Thank you very much.

Mark E. Ellis

Thank you.

Operator

Thank you. Our next question comes from the line of Ethan Bellamy from Baird. Your question please.

Ethan H. Bellamy – Robert W. Baird & Co.

Let me just follow-up on Abhi’s question. So assuming the worst-case scenario on infrastructure is used, ethane rejection, drilling results, no Berry merger, do you guys envision any scenario where you’d cut the distribution over the next year?

Mark E. Ellis

Yeah, Ethan, I know you are asking us to give a forward look in terms of prediction, in terms of distribution. Obviously, a lot of moving parts that you look out the rest of this year, capital performance, you talked about transaction liquid’s prices, you’ve touched on all of those. We are in the process right now going through a long range plan. We don’t do our budget planning for 2014 until later this year and we really don’t give guidance on distribution management beyond the current quarter and obviously we have to review that on a regular basis with the Board. So we wouldn’t have any projections on that until later this year. We customarily provide guidance for 2014 late in the year 2013 and we will do that at the right time.

Ethan H. Bellamy – Robert W. Baird & Co.

Okay. Could you bridge us from the second average production levels through those targeted projection levels for the balance of the year just in terms of the where that improvement is coming from, and how much of that is from drilling results versus expectation of the issues in the second quarter? And then more specifically on that point, is there any flexibility within the guidance based on the potential for further infrastructure issues or is this just assumes everything as rosy?

Mark E. Ellis

Yeah, Arden will comment on that in more detail, but again you heard our comments. You heard the text that I read. Obviously we’re very pleased with July’s performance so far. It’s actually exceeding our expectations we even had for July. So we’re well on our way towards achieving the growth that we anticipate in the second half of the year. But let me turn it to Arden really to give you the details in terms of where that growth is going to come.

Arden L. Walker, Jr.

Ethan, in terms of your question around how much infrastructure constraints has kind of factored into our estimates for the second half of the year. We do have some improvement plans, but we do also continue to see some infrastructure constraints built into our guidance.

So we would hope to see a little bit of improvement, but that’s not the key driver to the growth profile that we see for the second half. Probably the largest driver we have going into Q3 and especially in Q4 is our activity in the Jonah Field. You may recall, we started the rig program up there in first of the second quarter and we’ve been drilling on a six-well pad, and we’ll start our completions on that first pad later in the month of August. So as we move into September and October, we’ll see the ramp up of volumes in Jonah begin, and then we’ll also be picking up a second rig in Jonah later this year that will go out at the end of the year with some additional volumes.

So the single largest area of growth for us is in Jonah Field. We also have as Mark mentioned, some completions that we just finished up in the Granite Wash, which are contributing to our volume growth right now in the Granite Wash and Hogshooter, would be come into the second half. We also have drilling programs in Williston and non-operated area up there that continue to grow through the year as well as in the Hugoton Basin, we’ve had a rig running up there and those volumes will be ramping up as we go through the rest of the year as well.

Ethan H. Bellamy – Robert W. Baird & Co.

Okay. Kolja, could you just refresh us on how you go about dividing your capital budget between maintenance and expansion, and to the point of the – your productivity from the Hogshooter locations this year, knowing what you know now about that, about those prospects. How if at all would that have changed your maintenance CapEx allocation?

Mark E. Ellis

Yeah, Ethan, good question. This is Mark, let me take that one, and I am going to do two things. I want to draw everyone’s attention to our, I guess, supplemental financial and operating results document we put on our website. There is two areas in that document that I think give a very clear description, definition and description on how we go about defining maintenance and how we go about calculating that each and every year and estimated for the subsequent year.

So I would agree the glossary of terms, you’ll see it there, you’ll see it on a table that is essentially a reconciliation table from net income all the way through distributable cash flow and is solicited at split Note 7. And I would tell you it’s very well return, I don’t think I can say it any better. But in that nutshell, when we think about maintenance capital, we take a two-fold approach. One, it’s obviously the replacement of production decline over the course of the year as well as a replenishment of proved developed producing reserves.

So it’s a two-fold test for us. We do it at the end of each and every year as part of our budget cycle. we look at actual performance over the previous period on each and every one of those plays and factor those actual results into the future projects that we look at from a capital standpoint. So at the time we’re doing that analysis, we evaluate all the most recent performance statistics we’ve had from those plays.

So your comment about the Hogshooter absolutely, if we were to look at going forward into 2014, and analyzing projects, the Texas Hogshooter portion would obviously not look very attractive right now, based on the most recent results we’ve seen in that play.

That being said, the results we’re seeing on the Oklahoma side look very attractive to us. Unfortunately, we just don’t have the same level of working interest there, but we have a very large inventory. So when we think about maintenance or capital allocation, we take the best available data at the time, evaluate our projects, plan our capital spending going forward and obviously select the best projects that meet that two-fold test from a maintenance capital standpoint.

It’s really clearly laid out in both of those plays and I strongly encourage everyone to go out and read that in our supplemental information.

Ethan H. Bellamy – Robert W. Baird & Co.

All right, thanks, Mark.

Mark E. Ellis

You bet.

Operator

Thank you. Our next question comes from the line of John Ragozzino from RBC Capital Markets. Your question, please.

John Ragozzino – RBC Capital Markets LLC

Hi, good morning gentlemen.

Mark E. Ellis

Good morning John.

Kolja Rockov

Good morning.

John Ragozzino – RBC Capital Markets LLC

As it you’ve been kind of touching upon the issue, but I really want to kind of nail things down and get a good clear understanding of all the moving parts there. When I look at the production in the last three quarters, I’ve been skating around that 800 million cubic feet a day level since 4Q. And at the same time, you’ve seen total spend upwards approaching $800 million to $900 million, and volumes were actually down when they reported, so June numbers about 2.5%. Can you just reconcile the difference between where did all the capital go, where has the production results, where are we going to end up on the production side and what degree of confidence you’ll that there is going to be some sort of turnaround in this front?

Mark E. Ellis

Yeah, John, I know your point. I think we’ve had that question a number of times, but let me try again. No doubt, the end of last year, the fourth quarter, we had, we were pretty active in the Hogshooter program. We had a lot of concentration in that play. We drilled 28 wells last year and into the first part of this year. And I will tell you about half of those wells did not meet our expectations. We didn’t realize that until fully realize the impact of that until the second quarter of this year. So it had a material impact on volumes both in the first quarter and the second quarter this year and we’ve now turned the corner in terms of volume growth.

Let me also draw your attention to a slide that we put in the supplemental document in page 2, which shows production estimates going forward. And it shows exactly, what you pointed out, first quarter, second quarter volumes are essentially flat, going back to the fourth quarter probably a little bit flat maybe even slightly down. And that is the fact that look, we had some problems in the Hogshooter program, we’ve learned from that, we’ve shifted those rigs out of that area over into Oklahoma and we are applying those learnings there and I can let Arden expand on that. But we continue to grow. We’re very pleased with where we are right now. I think on that slide it also shows you our July average rate of 815 million cubic feet equivalent a day. So we are experiencing the growth.

Our growth in 2013, I think, we’ve been pretty clear, has always been back half of the year loaded. We didn’t originally forecast it to be a tremendous amount of growth in the first two quarters mainly because of where that growth is coming from. When you think about the Jonah Field, it’s a pad drilling operation. There is a fair amount of money spent well in front of actually completions on that program. We started that effort in late-March, and here, Arden just mentioned that we won’t really see any production uplift from that program until late August. So there is a fair amount of time delay in our growth in 2013, and then that shale has taken us some time to recover from a poor program on the tail end of our Texas Panhandle Hogshooter program. Hopefully that answers your question, John?

John Ragozzino – RBC Capital Markets LLC

Yeah. So if I understand it correctly, just summing up, you guys have placed some pretty big bets on the horse I think coming in the Texas side?

Mark E. Ellis

That’s a fair way to say it. No, I would say this, over the entire program, the 28 wells, the first half of that program performed quite well. The second half did not. And because of our concentration in that play, you’re kind of into a fair number wells before you really have the full data that tells you need to move away from it and as soon as we found out that that was way that program was trending, we moved away and moved into Oklahoma and we’ve been very pleased with what we’re seeing there. I don’t know if you want Arden to update you on that anymore. You might say if you were to about the Oklahoma side.

John Ragozzino – RBC Capital Markets LLC

And that was kind of the next line of question I had. I really appreciate the detail. That’s been a very helpful response. I’ve been looking for it for a while now. And so along those lines, when you think about the things that you’ve learned over the last year with respect to the geologic differences between the Oklahoma side of the plant that Texas side of the play, how much more confident are you that you may not look back six months from now and say, well, those first 12 wells were some barnburners, but now we’ve got another set of dusters on our hands and how do we know that that’s not something that we’re going to be mocking into again?

Arden L. Walker, Jr.

Yeah, John, this is Arden. It’s actually a good question as well. Let me give you a little bit more detail. If you look at the Hogshooter play on the Texas side, if you look at the entire group of 28 wells, our initial potential for those [vertical] wells was about 1,700 barrels a day. So clearly Mark mentioned, the first group were much, much better than the second wave of wells that we drilled up there.

As we move over into Oklahoma, the results we’ve seen so far on the first nine wells we drilled have actually been quite a bit better than the average we’ve seen in Texas, even better than the average of the first 12 wells we saw in Texas. So, exceeding our expectations a bit on the Mayfield side at this point in time, but I would tell that there are some differences when you move from Texas to Oklahoma. There are two fairly thick Hogshooter intervals that there are two independent intervals that we believe we’ll be able to go after independently of each other.

The zones are a little bit higher pressured and it appears that the reservoir quality is a little better than we had in the Texas side. When we went into Texas, we were able to delineate the play pretty well from logs. There is lot of well control in the area, but we didn’t have a good control while there’s (inaudible) in the reservoir was, and as we moved outward from the area of initial completions, we found that we saw deterioration in reservoir quality and therefore initial production rates started coming down pretty dramatically. So the approach we’ve taken in Mayfield, we’ve tried to learn from our mistakes, I guess, if you want to say it that way.

On the Texas side, we have focused more on the petrophysical and reservoir quality of the reservoir and we have actually delineated the biggest acreage block we have pretty much from north to southeast to west before we go in there and start drilling everything. So, I think we’ve taken the longest exercise. I have to give our technical folks in Oklahoma City a lot of credit. They’ve done a great job of reacting and learning from our stumbles and I think we’re making really good progress on the Oklahoma side that we set up for a number of very good high-quality inventory projects on Oklahoma.

Mark E. Ellis

Hey, John, it’s Mark again. I want to go back to one thing. On the volume profile over the quarter-over-quarter, one thing I failed to mention that does show up on that slide that I referred to on page two in the supplemental document. It is the fact that we did have a sale of the Panther assets. So those volumes are out of that forecast as well, and it clearly describes the level of those volumes on those two quarters.

John Ragozzino – RBC Capital Markets LLC

Great, thanks, Mark. And then just one or two more. Arden, can you give us or just care to share a) DNC cost on the first several Oklahoma Hogshooter wells and maybe on IRR that you guys are targeting?

Arden L. Walker, Jr.

Yeah. First group of wells, first nine wells are running just under $8 million. I think we talked about an average cost of all of our Granite Wash wells in Texas this year of running around $8 million, the Hogshooter wells I’d say are slightly below that number, and in terms of rate of returns, there is a pretty decent range on the low-end probably in the 30% range to well over 100% for some of the better wells.

John Ragozzino – RBC Capital Markets LLC

All right, and just one more, you discussed a little bit of the potential on the horizontal Wolfcamp across your acreage, as I guess this is kind of a two-part question. First, are you guys in any discussions with any other operators with regarding any potential non-op projects that we may hear about in the future. And then secondly, when you think about the pro forma asset base including the Berry assets, what does that number look like when you include the Berry acquisition in terms of the acreage exposure?

Mark E. Ellis

So in terms of acreage, I want to take that part of question first, the LINN acreage position in the Wolfberry is around 25,000 net acres, if you look at the Berry acreage, it’s on the same order of magnitude. It’s not exactly the same number, but it’s the same order of magnitude. So very good position within the Midland Basin area that you kind of hearing horizontal potential kind of coming up right now.

In terms of the wells that we plan to participate in between now and the year, I think there will be four non-op wells that we will participate in with a pretty small working interest between now and the end of the year really, one of the goals there is for us to get a little bit of learning under our wells on horizontal. We also plan to pick up our horizontal rig before the end of the year and drill our first horizontal Wolfcamp well.

So it doesn’t mean that there is not other alternatives in the future for us to develop this acreage, there maybe JV opportunities et cetera, but additionally, we feel like we’ve got some acreage that has been proved up essentially from offset wells, and offset operators. And we are prepared to move forward with a bit of a program on our own, starting later this year.

John Ragozzino – RBC Capital Markets LLC

All right, fantastic thanks for all the detail, someone else up on.

Mark E. Ellis

All right, thanks John.

Operator

Thank you. Our next question comes from the line of Kevin Smith from Raymond James. Your question, please.

Kevin C. Smith – Raymond James & Associates, Inc.

Hi, good morning gentlemen.

Mark E. Ellis

Good morning, Kevin.

Kevin C. Smith – Raymond James & Associates, Inc.

I think we hit the Hogshooter pretty well, so I was curious how CapEx is running versus kind of your original, I think it is $1.1 billion capital budget.

Mark E. Ellis

Yeah, we are pretty much on trend on total CapEx. As I said we’ve actually seen some cost savings coming in from both the Granite Wash program, and the Permian programs. We’ve also got a little higher activity levels in the Williston Basin, that’s non-operated, we don’t have lot of control over this pace up there, but overall we are going to be pretty much on track as far as total capital.

Kevin C. Smith – Raymond James & Associates, Inc.

Got you, and Arden I think you’ve talked a little bit about this, but I may have missed some, but would you mind discussing how the Mayfield wells are beating your performance expectations, is it just higher IP rates or lower declines or combination of both?

Mark E. Ellis

Yeah, it would be higher IP rates. Nothing to average IPs right now if you want to break it down into the components, it’s about 1,750 barrels of oil per day and about 8.9 million a day of gas. So that’s roughly 3,800 barrel of day equivalents rate, which is 69% liquids. Our type curve is probably more on the order of 1,600 barrels of oil a day. So I think we are kind of expecting to 200,000 to 250,000 barrels MBo type EURs for Oklahoma oil side up there. So I would tell the initial results we’re getting up there in aggregate are better than we expected.

Kevin C. Smith – Raymond James & Associates, Inc.

Got you. And then can you touch on your rig count both in the Texas Pandhandle and the Granite Wash as well as the Mayfield area? That looks to stay pretty stagnant for the rest of the year or is that supposed to fluctuate a little bit?

Mark E. Ellis

Yeah, we have eight rigs running. I think we’ll be at that level pretty much through the end of this year. They are moving around a bit from Mayfield to the Texas Panhandle. We had some wells in the Dyco area, which is our northwestern portion of our acreage position, and we actually have five rigs running up there at this moment, and we have a group of wells we want to get completed in a couple of zones and they’ll be moving around between the Texas side and the Oklahoma side. Oklahoma, we’ll probably drill another 10 wells between now and the end of the year.

Kevin C. Smith – Raymond James & Associates, Inc.

Got you, and then lastly, you guys may not be able to answer this, but I guess, kind of have to ask, do you need a formal letter closing the inquiry before the Berry registration can become effective?

Mark E. Ellis

Yeah, Kevin, we’re just not going to comment on the SEC inquiry.

Kevin C. Smith – Raymond James & Associates, Inc.

Okay, fair enough. Thank you.

Mark E. Ellis

You bet.

Operator

Thank you. Our next question comes from the line of David Amoss from Howard Weil. Your question please.

David Amoss – Howard Weil Inc.

Good morning, guys.

Mark E. Ellis

Good morning, David.

Kolja Rockov

Good morning, David.

David Amoss – Howard Weil Inc.

I’d like to focus on the horizontal Wolfcamp as a couple of others have it as well. Can you talk about the four non-operated wells, the locations are already chosen. Can you give us a little bit more color on what the timing may look like before you have results? And then, in regards to spudding your own horizontal well, are you going to wait for the four non-op results to come in or could you go ahead at some point later in the third quarter and spud that well?

Mark E. Ellis

Yeah. The four non-op wells are fairly concentrated in one section. We have a real small interest in those. I don’t think we’re going to wait a lot on our own development, based on the results from that wave of wells. The first operated well is in the same area that we haven’t offset a successful offset to our acreage already. And it’s on one of our larger blocks of acreage. So basically it gives us the most room to run. It’s successful. So that’s kind of our concentration at this point. We’re also trying to sit back and really learn from everybody else’s spending in the basin right now ourselves without having to drill a 100 wells. We are able to actually get a lot of information from a lot of the industry activity out there and that’s probably the biggest focus we have at this point.

David Amoss – Howard Weil Inc.

Okay. In our all five of those locations, horizontal Wolfcamp B locations?

Mark E. Ellis

I’m not going to comment on that because I think we’re still trying to determine the appropriate targets at this point for one of them.

David Amoss – Howard Weil Inc.

Okay. And then just one more, I mean, it’s been answered already a little bit. But as you get further into this program, say let’s make the assumption that you have success because other operators have around you. At what point do you then come up with the development plan and try and ramp it on your own or maybe go to the market and see if there JV partner to come in and partner with you?

Mark E. Ellis

I think we just have to see how the results go. I mean, if we have really good results, I think that’s going to maybe take us in one direction, if we have not so good results or we are starting to be concerned about the level of capital it is going to take, to really develop it in a short space of time, then we may consider looking for some partners. I think we would consider both alternatives.

David Amoss – Howard Weil Inc.

So maybe early 2014 timeframe?

Mark E. Ellis

Yeah, I mean it will be 2014 before we have any results on any of our stocks, so that’s probably the earliest.

David Amoss – Howard Weil Inc.

Okay, great. Thanks for the color.

Arden L. Walker, Jr.

You bet, thank you.

Operator

Thank you. Our next question comes from the line of Ted Durbin from Goldman Sachs. Your question please.

Ted J. Durbin – Goldman Sachs & Co.

Thanks. I want to ask, come back to the CapEx, it sounds like you are still running around the one range. I guess, can we talk a little bit about how that is shaping up for 2014, and if you keep the activity levels and sort of that CapEx level going, we obviously got a nice ramp in production in the back half of this year, then what would you think about for production growth in 2014 relative to say your actual rate in 2013?

Mark E. Ellis

Yeah, like I said earlier, I know that’s good information. We don’t typically give guidance beyond the current year and as I mentioned earlier, we are in the process, doing a long range plans, which feeds into our budget process and that’s information we would make available later this year when we kind of have a really good feel for what our plans are going to look like next year.

Ted J. Durbin – Goldman Sachs & Co.

Okay. Next one from me is just on hedging here, I think you didn’t add much in terms of the out years on the hedges, is that just a function of the curving and backwardation, pretty steep backwardation for oil, maybe some of the uncertainty around that, just talk about your hedging strategy there?

Kolja Rockov

Yeah, Ted, this is Kolja. Really the driver for no additional hedges is that we are fully hedged, I mean 100% on gas through 2017 and 100% of our oil through 2016, so we are very comfortable on a standalone basis as where we are, I mean we’ve noted what you said in terms of the backwardation of the curve, but that hasn’t been the driver. It’s the fact that we’re very fully hedged.

Ted J. Durbin – Goldman Sachs & Co.

Okay. And then, just last one from me, just on the acquisition front. Have your activity levels kind of pulled back a little bit given all the other things that are going on or do you still kind of have that acquisition, that machine cranked up looking for other things out there?

Mark E. Ellis

Ted, this is Mark. I can tell you there aren’t many transactions that take place out here that we look at, we don’t evaluate. We’re still very active in terms of looking at asset deals and of course corporate transactions. So we remain very active in terms of monitoring the market and evaluating things. So it’s not like we’ve turned anything all.

Ted J. Durbin – Goldman Sachs & Co.

Okay. I’ll leave with that. Thanks.

Mark E. Ellis

You bet. Thank you.

Operator

Thank you. Our next question comes from the line of Praneeth Satish from Wells Fargo Securities. Your question, please.

Praneeth Satish – Wells Fargo Securities LLC

Hi, good morning.

Mark E. Ellis

Good morning.

Praneeth Satish – Wells Fargo Securities LLC

Just a couple of quick ones for me. I know this has been asked in the past, but I’ll ask it again. How do you feel about selling LINN’s good portfolio rehedging the costs with swaps, is that something you would consider it came down to it or are there any restrictions that would prevent you from doing that?

Mark E. Ellis

I think we can do that. I don’t think we have any current plans to do that. I guess that we’re fully hedged and very happy with the positions we have.

Praneeth Satish – Wells Fargo Securities LLC

Okay. And then, I noticed that the NGL price realizations came down quite a bit this quarter more so than what we saw at Belvieu and Conway, which is strange considering that you guys are rejecting ethane. Is there anything specific going on there and it looks like the guidance has a little bit of an increase over the balance of the year? Just wondering if you can talk about that.

Mark E. Ellis

Well, I think it surprised us the prices were as low as they were in the second quarter, right. The second quarter last year is probably the low watermark and first quarter was weakest as well as you know and second quarter surprised us, although I will tell you that through June, the oil prices really hasn’t turned the corner and gone up substantially. And as we look at July, at least the heavier part of the barrel we would expect to receive a much better price. So, like I said, it was weak in the second, we’re expecting a rebound in the third and fourth that you just have to wait and see what the price is, obviously very difficult to predict.

Praneeth Satish – Wells Fargo Securities LLC

And just last one from me and sorry if I may have missed this, but how much total CapEx was spent this quarter?

Kolja Rockov

I don’t have that number off the top of my head, $260 million.

Praneeth Satish – Wells Fargo Securities LLC

Okay. Great, thank you.

Operator

Thank you. Our next question comes from the line of Adam Leight from RBC Capital Markets. Your question please.

Adam Leight – RBC Capital Markets LLC

Good morning.

Mark E. Ellis

Good morning, Adam. Hi.

Adam Leight – RBC Capital Markets LLC

Most of my questions have been covered, but let me just – couple of follow-ups primarily on the Hogshooter? A, do you have – what’s the mix of liquids, is there big oil cut – no oil cut?

Mark E. Ellis

I guess on the Oklahoma side, the most recent step, Adam?

Adam Leight – RBC Capital Markets LLC

Yes.

Mark E. Ellis

Okay. Yeah, the 1,750 barrel of oil a day rate that I was talking about is the oil portion of kind of our average IP. Out of the 3,810 barrel of oil a day equivalent kind of number, so total liquids is about 69% of the production strength from initial rate perspective.

Adam Leight – RBC Capital Markets LLC

Okay, but the 1,750 is all oil, not NGL?

Mark E. Ellis

The 1,750, yes, is all oil.

Adam Leight – RBC Capital Markets LLC

Okay. Great. And do you have a – wells on long enough yet to get a sense of 30-day decline or beyond that?

Mark E. Ellis

Yeah, we really haven’t got an update on all of that. We do continue to see very steep initial declines, I mean the wells will fall off it, 80% to 85% initial decline instantaneously when they first come online, but then they do turn a corner over the course of the first couple of three months.

Adam Leight – RBC Capital Markets LLC

Okay. And just, do you have a sense of how much more activity you have to do to de-risk this area to lineate it?

Mark E. Ellis

In terms of the Hogshooter, I think we’ve done a pretty good job of de-risking at least the central core area that we are developing in right now. I mean, as I said we’ve drilled kind of on the north and the south and the east and the west portions of it. We have a farm in that we did in the area, they kind of fills in the center of our acreage block there. And so that I think is relativity de-risk at this point in time. We kind of view it as development, very low risk development at this point in time.

Adam Leight – RBC Capital Markets LLC

Okay. That’s good for me. Thanks.

Mark E. Ellis

Thanks, Adam.

Operator

Thank you. Our next question comes from the line of Michael Peterson from MLV & Co. Your question please.

Michael D. Peterson – MLV & Co. LLC

Follow-up question on M&A, if I could. During the transition period with the commission inquiry and the pending Berry transaction, does that preclude another transaction for you? First question. And then the second point on that is, any color you’re willing to share on what you’re seeing in the A&D markets?

Kolja Rockov

Yeah, kind of difficult to, we said we’re not going to answer any questions about the Berry merger. So it’s kind of hard to answer your preclude, but as Mark mentioned earlier, we are very active in the A&D markets. They’ve been a little bit slower this year than we would have anticipated and we’ve definitely been very active and not that uncertain things – there are uncertain things, but I think our focus this year has really been on the acquisition that we have pending.

Michael D. Peterson – MLV & Co. LLC

Understood, and I recognize certainly all the moving parts. I just wanted to clarify that you haven’t fully pulled back from those markets and that you just have a lot of other things going on, is that a fair characterization?

Mark E. Ellis

Yeah, we have not pulled back at all. We’ve been very active evaluating things. As you know we’ve had some delays this year, but that hasn’t changed our approach to the A&D markets at all.

Michael D. Peterson – MLV & Co. LLC

I appreciate that. Very helpful, that’s all I have. Thank you.

Mark E. Ellis

Thank you.

Operator

Thank you. This does conclude the question-and-answer session for today’s program due to time constraints. I’d like to hand the program back to Mark Ellis for any closing comments.

Mark E. Ellis

Okay. Well, I’ll just say thank you very much for your time this morning and this concludes our call. Thanks.

Operator

Thank you, ladies and gentlemen, for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.

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