Linn Energy's CEO Discusses Q1 2014 Results - Earnings Call Transcript

May. 1.14 | About: Linn Energy, (LINEQ)

Linn Energy, LLC (LINE) Q1 2014 Earnings Conference Call May 1, 2014 11:00 AM ET

Executives

Clay P. 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. – Chief Operating Officer and Executive Vice President

Analysts

John Ragozzino – RBC Capital Markets

Shneur Z. Gershuni – UBS Securities

Kevin Smith – Raymond James & Associates

David Amoss – Howard Weil

Theodore Durbin – Goldman, Sachs & Co.

Praneeth Satish – Wells Fargo Securities

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

Eric B. Anderson – Hartford Financial Management, Inc.

Operator

Good morning and welcome to LINN Energy Conference Call to discuss its first quarter 2014 earnings. Today’s call is being recorded.

At this time, I will turn the call over to Clay Jeansonne, LINN Energy’s Vice President of Investor Relations, for some opening remarks. Please go ahead.

Clay P. Jeansonne

Thank you for joining our first quarter 2014 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 will be made during this call. The statements describing our beliefs, goals, plans, strategies, expectations, projections, forecasts and assumptions are 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 such risk factors relating to our business, prospects and results is available in the company’s filings with the SEC, including LINN’s Form 10-Q for the quarter ended March 31, 2014, which we plan to file later this afternoon and any other public filings and press releases.

We plan to file LinnCo’s Form 10-Q on Friday, May 2, 2014. Supplemental financial and operational results, including the company’s statement of operations, selected balance sheet data and guidance table, are posted to LINN Energy’s website at www.linnenergy.com in the Investor Center under Presentations. Following management’s prepared remarks, we will take your questions.

I’ll now turn the call over to Mark Ellis, LINN’s Chairman, President and CEO.

Mark E. Ellis

Thanks, Clay, and good morning. Joining us today from LINN are Kolja Rockov, Executive Vice President and Chief Financial Officer; Arden Walker, Executive Vice President and Chief Operating Officer; and David Rottino, Executive Vice President of Business Development and Chief Accounting Officer.

Our capital program and efficient management of our base assets continue to deliver positive results. During the first quarter of 2014, Linn reported average daily production of approximately 1,104 million cubic feet equivalent per day, exceeding our guidance range. This growth occurred across a number of our operating regions, most significantly in California and the Uinta basin.

At Linn, our mission is to acquire, develop and maximize cash flow from a growing portfolio of long-lived oil and natural gas assets. We currently operate over 14,600 wells across seven operating regions with the majority of those wells being low decline immature in nature.

I’d like to take a moment to highlight a few of these areas across our portfolio. We are currently operating over 2,800 low decline wells in the Mid-Continent that consist of natural gas properties located in the Anadarko basin and the Mississippi shelf area, as well as mature oil-producing waterflood properties in Oklahoma and Louisiana.

In an effort to narrow the company’s focus in the Mid-Continent on this type of production profile, we are currently operating five rigs there, down from eight at the end of 2013. Four of the rigs are primarily targeting oil intervals in the Granite Wash area and the remaining rig is focused on liquids-rich opportunities in the Cleveland play located in northern Texas Panhandle. As Linn reduces its rig count in the Granite Wash, the company expects decline rates to begin to moderate in this area.

In the Rockies region, we operate over 1,200 wells located in the Green River, Piceance and Uinta Basins. Additionally, the company has interest in approximately 2,100 non-operated wells in the Green River Basin, Williston Basin and the Salt Creek Field in Wyoming. Development and optimization activities continue as planned in the CO2-enhanced recovery project in the Salt Creek Field. In addition, the company operates over 150 low-decline natural gas wells in the Piceance Basin.

In the Uinta Basin, first quarter 2014 production grew 13% sequentially to 11,000 barrels of oil equivalent per day. LINN currently operates three drilling rigs in the Uinta and expects to drill over 150 wells there in 2014. We have drilling programs underway in the Green River Basin, targeting liquids-rich natural gas wells.

Non-operated activity remains high in the Williston Basin where the company now produces approximately 7,000 barrels of oil equivalent per day, which represents an increase from the approximately 2,500 barrels of oil equivalent per day at the time of the acquisition in 2011.

Within the Permian Basin, our Central Basin and Delaware Basin positions our other areas which have desirable characteristics for LINN’s business model. Approximately half of our 2,000 operated wells in the Permian Basin are mature, low-decline oil properties, primarily consisting of water floods. In 2014, we’re focusing on three key drilling programs which consist of vertical Wolfberry, vertical Clearfork and horizontal Wolfcamp. We’re running a three rig vertical development program in the Clearfork formation of the East Goldsmith Field, which we acquired in 2013. This program is expected to generate attractive returns and has further potential upside tied to future water flood and CO2 opportunities.

In the Midland Basin, most of our acreage has been developed since 2010 with vertical Wolfberry wells and now is prospective for horizontal Wolfcamp drilling. Recently, we completed drilling our first operated horizontal well in the Midland County targeting the Wolfcamp B interval and expect to complete it in the second quarter.

Furthermore, I’d like to provide you with a brief update on the status of the Midland Basin strategic alternatives. We’re pleased with the level of interest expressed in these properties and have received interest in both trade opportunities as well as the outright purchase of these properties. All of these options are expected to increase cash available for distribution and have the potential to lower the company’s capital intensity and overall decline rate.

Our Hugoton Basin position consist of over 3,700 operated material wells. Production volumes continue to gradually increase as a result of selective capital spending on optimization projects and one-operated rig, which we expect will drill approximately 80 wells this year. Since taking over operations in July of 2012, LINN has implemented 535 maintenance and optimization projects which have added over 7 million cubic feet equivalent per day of production. LINN has also improved the efficiency of its Jayhawk natural gas processing plant and increased throughput volumes 6% to 197 million cubic feet equivalent per day for the first quarter of 2014, up from 186 million cubic feet equivalent per day at the time of the acquisition.

LINN’s California region consist of over 2,100 operated wells and we currently have three rigs drilling. Approximately 85% of our wells in California produce oil using thermal enhanced or steam processes. Almost 1,500 of the wells in the region are mature, low-declining wells located in the San Joaquin Valley and the Los Angeles Basin.

These mature assets deliver stable production volumes with shallow base declines. Our California growth assets comprise over 600 producing oil wells in the Diatomite and New Steam Floods. We have active drilling and development programs underway in both of these areas, which have delivered growth of approximately 9% quarter-over-quarter and 83% year-over-year.

Our other operating areas include over 1,700 low-decline mature producing wells in Michigan and Illinois. In addition, the company operates over 500 shallow declining natural gas wells in East Texas. We will continue to focus on and undertake high-return low-cost optimization projects across these various operating regions.

Turning to guidance, in 2014, we expect to grow organic production approximately 3% to 4% year-over-year after normalizing for impacts of ethane rejection. The mid-point of guidance indicates an average production of approximately 1,095 million cubic feet equivalent per day for the second quarter of 2014 and an average of 1,105 million cubic feet equivalent per day for the full year. Additionally, the company’s overall decline rate should decrease over time with a slower pace of capital spending.

In closing, we began the year highlighting our keys to success for 2014: first, maximize value of our Permian Wolfcamp position; second, continue to make accretive acquisitions; third, reduce capital intensity, while increasing capital efficiency; and finally, improve the balance sheet and realize interest cost savings. We continue to make progress and I am confident we will succeed in accomplishing these goals, which we believe will provide further stability to the distribution.

I would now like to turn the call over to Kolja for his financial update.

Kolja Rockov

Thanks, Mark. During the quarter, Linn’s oil, natural gas and NGL revenues were approximately $939 million. We reported a net loss of approximately $85 million or $0.27 per unit for the first quarter 2014, which includes a non-cash loss related to changes in fair value of unsettled commodity derivatives including the reduction of put option premium value over time of approximately $219 million or $0.67 per unit.

The company for the first quarter generated net cash provided by operating activities of $434 million and paid distributions to unitholders of $240 million. For the first quarter, Linn reported a $3 million shortfall of net cash provided by operating activities, after distributions and discretionary adjustments. Positive production results were offset by slightly higher transportation expenses due to increased natural gas prices experienced during the quarter.

Linn amended its revolving credit facility in April 2014 to extend the maturity to five years or April 2019. The number of lenders increased from 41 to 42. Linn’s credit facility has a maximum commitment amount of $4 billion and a borrowing base of $4.5 billion, which have remained unchanged. As of March 31, 2014, Linn had approximately $2.1 billion available under its revolving credit facility.

The administrative agent for the credit facility is Wells Fargo Bank and Royal Bank of Canada serves as a syndication agent. Barclays, Crédit Agricole, Citi and the Royal Bank of Scotland serve as co-documentation agents. In April 2014, Linn also extended the maturity on its $500 million senior secured term loan to April 2019, consistent with the maturity of its revolving credit facility.

In addition, Berry, an unrestricted wholly-owned subsidiary of Linn, amended its revolving credit facility in April 2014 to extend the maturity to five years or April 2019. The number of lenders increased from 38 to 40. Berry’s credit facility has a maximum commitment amount of $1.2 billion and a borrowing base of $1.4 billion, which have remained unchanged. Following these amendments, Linn’s credit facility, term loan and Berry’s credit facility have maturity of April 2019.

For the full year 2014, we expect production volumes to remain on track and operating expenses to be slightly higher than our previous guidance which is due to modestly higher transportation expenses. Additionally, the company has changed its 2014 natural gas liquids price assumption from 40% of the forecasted crude oil price to 36% for the balance of the year.

We have continued to make progress in 2014 and I’m confident we will succeed in accomplishing our full-year goal which includes maximizing value for our Permian Wolfcamp position, continuing to make accretive acquisitions, reducing capital intensity, while increasing capital efficiency, and improving the balance sheet and realizing interest cost savings. We believe that achieving these goals will increase cash available for distribution.

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 John Ragozzino with RBC Capital Markets.

John Ragozzino – RBC Capital Markets

Hi. Good morning guys.

Mark E. Ellis

Good morning, John.

John Ragozzino – RBC Capital Markets

Looking back earlier in this month, there was a notable well that was announced on Howard County and the Wolfcamp. Is there any other significant data points that you guys can point to us that would maybe provide a little bit of additional validation to the value of some of the counties which have yet to be significantly de-risked?

Mark E. Ellis

Well, John, I think we see the same amount of public information you see. There’s been a number of wells reported and there’s been a number of transactions that have concluded in the area in and around where we have acreage. So I think those are the data points that if you’d have looked at.

John Ragozzino – RBC Capital Markets

Alright. And then as far as the first operated well that you guys drilled, can you share any of the internal modeling assumptions that you’d put in place as far as EURs or perhaps the AFB or the expected return that you are looking for?

Mark E. Ellis

Yeah. Sure, John. Let me let Arden answer the question.

Arden L. Walker Jr.

Yeah, John, we have an estimate. We think its conservative based on some of the offset operator to result in the area where we are drilling. This is a well just North of the Midland Airport, our first well.

We are estimating around 500,000 barrel EURs anywhere – somewhere around 1,000 barrel a day kind of IPs, so we’ve seen offset area results that are significantly better than that and we are probably a little bit conservative. But this is our first well, so we are bidding – drawing mode at this point in time.

John Ragozzino – RBC Capital Markets

Alright and then looking at the guidance for the remainder of the year, there was some mentioning of widening crude differentials both in the Williston and in Permian basin. I haven’t taken a recent look at the Williston basins details, but clearly there’s been a significant blow out in the Permian, what are you guys assuming for the remainder of the year as far as those specific regional pricing differentials?

Kolja Rockov

Yeah, John, this is Kolja. The guidance we gave for oil in aggregate was 450 off of NYMEX and it came in at 574 off of NYMEX. We projected it to stay relatively in that range, so in the Permian its middle 3s high – middle 3s to high 3s in terms of the differential. And the impact for the quarter it was about 8 million from what we guided and it’s about 33 million for the year. So not insignificant, but room for improvement should those moderate over the year and I think we’ve been conservative with the guidance.

John Ragozzino – RBC Capital Markets

So you are expecting some compression of the current Midland Basin difference. So I’m looking at the 750 number right now.

Kolja Rockov

Right. No, I mean that’s the average for the balance of the year, John.

John Ragozzino – RBC Capital Markets

Okay

Kolja Rockov

So it has that in the front and lower in the back similar to what the actual curve is.

John Ragozzino – RBC Capital Markets

Alright. And then I guess one more philosophical question if you will. Looking out maybe one, two, three to five years in the future, if we kind of hold things steady and that the investor program, where do you, how do you see the decline curve of the overall portfolio taking shape? And then also taking at a step further with respect to the midcontinent region if we were to just kind of continue the current activity levels, what is that progression look like from the current levels in going out three to five years?

Mark E. Ellis

Yeah, John. Great question. I can’t give you an absolute numbers over the next three to five years but I can tell you the actions we are taking this year are consistent with the goals that we set out at the beginning of the year. We are trying to accomplish reducing capital intensity, reducing overall decline in the system. By reducing capital in the granite wash, one of our higher declining areas, that’s going to serve to moderate the decline as we go out to end of the year, successful trades out of high declining assets such as what we are doing in the Permian and capitalizing value on that will also serve to reduce the overall decline profile of the organization.

And then in addition to those two, we are also looking at a number of other areas, where we think we have acreage that’s perspective and a couple of key plays that other industry parties are active in. And we are cataloging those opportunities and taking advantage of that to potentially monetize those acreage positions and try and acquire some mature long-lived assets to further reduce our overall decline structures. So I think all the actions we’re taking, it will take a little bit of time to see the full impact of that but they are all movements in the right direction.

John Ragozzino – RBC Capital Markets

Alright and then just I think I might have missed this one quick last one. The 10 million a day for the second quarter that was related to maintenance – that’s kind of an item that I haven’t seen you guys come across before, can you give a little more detail as far as what’s driving that, what’s going on?

Mark E. Ellis

Yeah. I mean, let’s talk about guidance for the year real quick. I mean, if you look at the first quarter, we had great first quarter came in at the high end of the guidance range to actually a little bit higher than the high-end generated by 1.5% growth quarter-over-quarter when you normalize for ethane rejection. So I have to give a lot of credit for our operating folks, it is an excellent job in the first quarter.

When you look to the second quarter, it’s not uncommon for a lot of the plants coming out of – third party plants coming out of the winter season to go through turnaround to do some of their schedule maintenance.

We almost always have that schedule in our second-quarter and that’s what’s occurring here, it’s really Permian, Texas, Panhandle a couple of key areas that we have some plant downtime and it’s not our operating plants, third party plants that are going to their schedule maintenance.

Now when you look at the bulk of the guidance for the year, unfortunately I guess we don’t give third and fourth quarter guidance nor monthly guidance but if you were to look at the program through the remaining part of the year and you go into the fourth quarter, you would find that our exit rate is around 1130. And that’s new information that we wanted to provide you because I know a lot of folks are having trouble seeing where the growth is coming from in this organization when they see the annual guidance number at only 1105. So you don’t really see it unless you see that particular monthly performance numbers.

So 1130 is an exit rate when you compare that to the ethane adjusted year-end pro forma rate of our two companies, unadjusted its 1109, adjusted for ethane rejection it’s about 1087 and when you compare that 1087 to 1130 therein lies the 4% aggregate growth over the course of the year. So I hope that’s helpful for everyone to understand where the growth is coming from this organization.

John Ragozzino – RBC Capital Markets

Thanks very much. I will let somebody else hop on.

Mark E. Ellis

You bet. Thanks, John.

Operator

Thank you. Your next question comes from Shneur Gershuni with UBS.

Shneur Z. Gershuni – UBS Securities

Hi. Good morning, guys.

Mark E. Ellis

Good morning.

Shneur Z. Gershuni – UBS Securities

My first question, I was wondering, if we saw on the potential asset sales for a little bit, I was wondering if you can sort of give us a bit of expanded color as to, you know, the stages of the process, are the data room still open, are they closed now, given the rounds of offers and so forth? I was just wondering if you can sort of expand on that or give us a little more color on how that’s progressing at this stage?

Mark E. Ellis

Yes, sure, I will try. As you know, we started the process about mid-January. We have eight distinct packages out there. We broke it into multiple packages really to help the execution of the process and allow potential buyers or trade partners to come in and kind of build a program that works best for them and works for us as well.

I have to tell you we’ve been very encouraged by the level of interest and the amount of properties and what we’ve seen from a property trade standpoint encourage that the companies are bringing forward the types of assets that we want to look for. So that’s all been extremely encouraging.

I can’t update you too much more, obviously, well, let me say this we started out and still are preference to trade. We have a number of parties that would love to do the cash purchase and we made that available to the standpoint of thinking of doing a Like-Kind-Exchange in 1031, if there was the right property for us to turn around and acquire.

The third level would be JV partners and that really is not something we are pursuing in earnest right now. We are really looking at exhausting all trade opportunities as well as cash sales first. So that’s really where we are. So encouraged by that I know everybody is eager to hear an announcement but rest assured we’ll announce something as soon as we have something complete, so we appreciate your patience.

Shneur Z. Gershuni – UBS Securities

Just to clarify on the three options on the second option, so there is a scenario where we see you making a fairly sizeable acquisition and basically tying that to basically (indiscernible).

Mark E. Ellis

Correct. If we went out tomorrow and bought a very large asset or bought an asset and wanted to do a Like-Kind-Exchange it would trigger 180 day clock by which we would turnaround and finance it through the sale of a portion of our Permian basin assets. And we would have essentially 180 days to consummate that deal. And it would qualify for a Like-Kind-Exchange.

Shneur Z. Gershuni – UBS Securities

Perfect. And then just one operational type question, the transportation expenses have kind of picked up and so forth, and I realize you have updated your forward guidance for this year with respect to that, but how do we think about that changing over time, is mix kind of an issue as well too in terms of where you are drilling and where you’re not, just sort of how we think about that, how that should change over the next 12 to 18 months if you have...

Kolja Rockov

Yes, if you look at roughly $20 million incremental transportation cost we put into guidance this quarter, basically it breaks into three parts. About half of that delta comes from gathering agreement that we have in the Hugoton Basin, which is based on actual.

So when we adjust on an annual basis, so that came into the mix, probably roughly $10 million of incremental transportation cost. Second item was incremental fuel cost related to mainly compression on systems and those are typically driven by what the natural gas prices are. So the higher natural gas prices we are seeing out there are driving some cost into that part of the structure.

And then finally the higher transportation cost mostly related to higher oil volumes in places like Williston basin come through as incremental cost as well. But that’s also good thing because we’re producing more oil volume. So incremental is about 20 – little over $20 million. As far as how much of that carries through into the future, the natural gas price portion obviously is dependent upon what the market does on that, but the other pieces are probably pretty well fixed.

Shneur Z. Gershuni – UBS Securities

Okay. And one final question on basis hedging, we’re seeing some improvements in some regions like for example the Rockies and so forth. Can you sort of talk about your thoughts with respect to basis hedging as you go out a couple of years, you wait for it to continue to improving as the trend has been or do you sort of sit back and – or do you just lock it in now as given that it’s potentially very attractive?

Mark E. Ellis

Yeah. Good question. We actually debated this a bit yesterday. When you look at basis, everywhere where we can hedge, we’re fairly well hedged going forward, so there’s – obviously, we’re not thinking of making any changes there. But as we look at the curves going forward, we see a lot of areas with potential alleviation of constraints which should improve pricing.

And we’re also seeing similar kind of behavior in those curves as you see maybe in the crude or it just doesn’t seem to make sense. And I think there’s just been some liquidity loss in the long part of the curve. So that kind of makes us a little more reluctant to put new hedges on with respect to other acquisitions, but our current production is pretty well covered and planned to make no changes there.

Shneur Z. Gershuni – UBS Securities

Great. Thank you very much guys.

Mark E. Ellis

Thank you.

Operator

Thank you. Your next question comes from Kevin Smith with Raymond James

Kevin Smith – Raymond James & Associates

Hi. Good morning, gentlemen.

Mark E. Ellis

Hi, Kevin.

Kolja Rockov

Hi, Kevin.

Kevin Smith – Raymond James & Associates

It is, I guess a question for Mark and Arden, the development pace of the remaining nine horizontal Wolfcamp wells as you guys have commented. How quickly – maybe what’s the thought process and how you drill those and how that impacts potential sale of the Permian assets or how does the potential sale, let’s say impact your development pace?

Mark E. Ellis

Yeah, great question, Kevin. Arden mentioned earlier, we have obviously drill – we drilled our first well, we’ve actually gotten all the way to casing point and set pipe on that particular well. Let me brag on Arden’s group, they did an outstanding job on the very first well, got the entire 10,000 foot lateral drilled encased and will be completing that well in the second quarter.

As far as the remaining nine wells, we started out with a program of 10 wells. But really what drives the timing on those is our success on the strategic alternatives. We have success in that area, trade out of some of those assets. Obviously, we’ll adjust that program accordingly.

Kevin Smith – Raymond James & Associates

So do you plan on spending another one this quarter?

Mark E. Ellis

Yes. We’re still active. We are in the process of moving to our second location as we speak. But again, the bulk of that program really depends on our strategic initiative program.

Kevin Smith – Raymond James & Associates

Gotcha. And then, has there been any new talks about the potentially divesting the Jayhawk Gas Plant or is that something you still want to keep in the fold?

Arden L. Walker, Jr.

Yeah, it is pretty critical, our operations there in Kansas, but obviously it’s one of the few of our mid-stream assets that we have. We continually look at those assets and think about are we getting – are there other options we can take with those properties.

But, for now, we’ve been focused on increasing the throughput through that facility. It’s got a very large nameplate capacity for running around just under 20 million a day through the facility.

I can tell you, at times, we removed other volumes through there as other plants have had some upsets or turnarounds. And that plant runs very efficiently in the 200s and we love to see more throughput through that facility. But, right now, it’s really viewed as a core asset for the Hugoton property.

Kevin Smith – Raymond James & Associates

Got you. And then the last one for me and I’ll jump off. What are you thinking about or how are you looking at lease operating expenses at this point, do think you kind of get all the synergies from the Berry merger through and were now in a steady rate or do you expect that to maybe decrease over the next few quarters? Or hope to decrease in building more synergies?

Mark E. Ellis

Well, Kevin we’re always optimizing LOE cost, so that’s something we look at every single day. But I would tell you that probably the biggest unknowns around LOE right now is around steam cost which are gas price related out in California.

And apart from that, I don’t really think we have a lot of moving parts around the LOE. It think it’s pretty well understood. We’ve done a good job of optimizing and we’ll continue to look for ways to reduce it. You did see a pretty significant change in unit costs from 2013 to 2014 as we layered those high margin oil properties into our mix, but we really believe we’ll have a good track record now and continue to move forward.

Kevin Smith – Raymond James & Associates

Alright. Thank you very much.

Kolja Rockov

Thanks, Kevin.

Operator

Thank you. Your next question comes from David Amoss with Howard Weil.

David Amoss – Howard Weil

Good morning, guys.

Mark E. Ellis

Hey, David.

David Amoss – Howard Weil

Mark, you mentioned some transactions recently in the Midland Basin and one in particular I’m thinking of that. It looks very similar to your acreage package.

So I guess my question is kind of twofold, you see a value in the $20,000 to $25,000 an acre for the undeveloped range depending on what you get for the production, is there any reason to think that your acreage package would be any different significantly from what happened at buying?

And then the second part of the question is when you see a deal like that in the market is there anything in particular that would keep you from being a seller into a deal like that?

Mark E. Ellis

Yeah, David. Let me first say, I’m not going to put an absolute number on what we think our acreages work and we have way too many people in there that have different views of the acreage and I just don’t want to lock that in at this point in time.

Let me also say, I haven’t seen anything in the recent information though that’s discouraging. Well results out there continue to perform quite well and the sales that have happened no surprises, the values are where they are based on that acreage,

So we’ve got acreage across a pretty broad section of that Midland basin area and the other thing I would say is what’s interesting in the process is we’ve had folks come in and they have different views at the acreage. Some – not everybody is focused in a one particular package in our group which is really beneficial for us. So that’s been very encouraging.

David Amoss – Howard Weil

Okay. Got it. And then in the first quarter you obviously see a higher gas price in the market. You went to look like its performing very well, is there anything you see in the first quarter that maybe at mid-year would cause you to shift your capital from one region to the next?

Mark E. Ellis

No I don’t think so, yet I think we started our capital pretty much based loading the Berry assets, the California asset, Uinta and they performed quite well. Quarter-over-quarter I think if you are just to look at Berry’s assets have picked up, they’re probably up 7.5% quarter-over-quarter.

So California is performing extremely well. Uinta has created a tremendous amount of growth early on. They have a fair amount of capital in the system right now and I think it’s a good number for this year. So I’m not so sure we would reallocate a whole lot but we will see.

David Amoss – Howard Weil

Okay. Got it. And then one last one. Focusing on the Anadarko basin where you have a lot of acreage, have you looked at what might be perspective for plays that are sort of being broken off like the scoop or the stack or the hoax bar and if you have can you kind of give us an order of magnitude in terms of what type of acreage you might have there?

Mark E. Ellis

Great question. We have a tremendous amount of acreage in Western Oklahoma and those are the exact plays that we are looking at right now. I know there’s a lot of companies that cover that acreage. We’ve got a fair amount of acreage in each one of those plays. We need to understand what we have in catalog of inventory I think I mentioned that on a prior question and we look to do the right thing.

Those things I’m sure others have more interest in that play than we do probably fits them better than us and if we can capture value there and convert that into a long line producing asset, we will do that all day. So that’s really what our folks in Oklahoma are looking at. They’ve done a great job of working through it so far and we continue to develop that. So that’s something we will look at once we finish our Permian work.

David Amoss – Howard Weil

Great. Thank you very much.

Mark E. Ellis

You bet. Thank you

Operator

Thank you. Your next question comes from Ted Durbin with Goldman Sachs.

Theodore Durbin – Goldman, Sachs & Co.

Thanks. Just a follow-up on the well hedges, they definitely moved here for ‘15 and beyond and it sounds like I guess is the answer still the same that we are still somewhat waiting on the disposition or what we do with the Permian acreage as well as it’s a function of the curve being backdated. It feels like it’s firmed up a little bit on the back end. I’m just wondering how you’re thinking about your hedge profile there on oil.

Kolja Rockov

Yes. Ted, I think you have it right. To do anything in advance of the strategic alternatives that we are pursuing in the Permian, I think would be premature. And yes, the curve is starting to move up, which is a positive sign and hopefully that trend continues and again when we get through the process, we’ll have to re-look at what the right amount of hedging would be in ‘15 and hopefully by that time, the curve is materially higher.

Theodore Durbin – Goldman, Sachs & Co.

And then, can you talk a little bit about balance sheet here. The longer you go, without some sort of movement on the Permian where you are with your credit metrics meeting the financing CapEx budget and then hopefully it ends up with the sales and net cash, how you think about that reduction versus say distribution increase?

Kolja Rockov

Yeah I think we are very comfortable in terms of liquidity and what we’ve said all along this year is that in terms of our goals, we have our strategic initiatives that we’ve got to complete and they are kind of in sequence. Obviously the Permian would be first. We would love to follow that up with more accretive acquisitions, portfolio improvements if possible and we think all of those things would be credit positive.

We think that the Permian strategic has the potential to be credit positive and then we would look to maybe do something with the balance sheet, but right now we feel like we have plenty of liquidity and it’s too many variables. I guess one of the things that we love to see come out of the initiatives is a reduction of capital overall, which would change how we would manage the balance sheet and how much we would have to raise going forward.

Theodore Durbin – Goldman, Sachs & Co.

Got it and just to be clear. I missed it, but you still think right now the CapEx budget is in that 15 to 16 range?

Kolja Rockov

Yes.

Theodore Durbin – Goldman, Sachs & Co.

Okay. And then last one just small one for me Uinta basis differentials, can you talk about whether you might see an improvement there going forward?

Mark E. Ellis

Yeah I’ll jump in on that one. We’ve been in the process of negotiating marketing agreements long-term out there in the Uinta basin. We currently moved a couple of thousand barrels a day via rail. Out of about 7,500 barrels a day gross that we market out of that region.

The rest of it goes to the Salt Lake City markets kind of midyear. In the last half of the year, we’re going to see probably a doubling of our oil volumes moving via rail, which will have an improvement in terms. And so we will definitely see some improvement in what we net back out there in the Uinta Basin in second half of the year.

Theodore Durbin – Goldman, Sachs & Co.

Can you give us an order of magnitude kind of where you are now versus where you’re going to go?

Mark E. Ellis

Yeah. I’m not going to comment on that. I mean it’s kind of a marketing...

Theodore Durbin – Goldman, Sachs & Co.

Okay.

Mark E. Ellis

Deal that we’re not going to give that information out.

Theodore Durbin – Goldman, Sachs & Co.

Okay. I’ll leave it there. Thanks.

Mark E. Ellis

Thank you.

Operator

Thank you. Our next question comes from Praneeth Satish with Wells Fargo.

Praneeth Satish – Wells Fargo Securities

Hey, guys. Good morning.

Mark E. Ellis

Hey, Praneeth.

Praneeth Satish – Wells Fargo Securities

Two quick questions. I guess you’ve mentioned in the past that the Berry merger has allowed you to high grade your capital budget. I mean is there any way you can quantify the average return that you expect to generate now versus where it was pre-Berry?

Mark E. Ellis

I don’t know the answer to that. But I can tell you that we really – I mean, we – essentially, when we were in the budget – as I mentioned earlier, we base loaded the Berry projects and if there was any reduction in capital, we’ve mentioned it. It’s been in our – on the Linn side and most specifically in the Granite Wash program.

Praneeth Satish – Wells Fargo Securities

Got it. And, I guess just what kind of coverage ratio or excess cash flow metric are you targeting before you consider resuming distribution growth?

Mark E. Ellis

We look at having the sustainability to generate coverage or excess cash, I guess, at about 10% excess. So the 1.1 level sustained for period of time is when we think about stepping into distribution growth.

Praneeth Satish – Wells Fargo Securities

Got it. Okay. That’s it for me. Thank you.

Mark E. Ellis

Thanks.

Operator

Thank you. Your next question comes from Ethan Bellamy with Baird.

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

Gentlemen, good morning

Mark E. Ellis

Good morning.

Kolja Rockov

Good morning.

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

Crude by rail volumes into California look poised to accelerate dramatically. Would you agree with that? And if so do you expect internally realizations in California to suffer versus Brent longer term?

Mark E. Ellis

I don’t know that we’ve got a real view on that at this point. I think the first comment you made is probably accurate, I think there will be more crude moving into California via rail. I’m not sure what that does to the base to the volumes out there in California pricewise.

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

Okay. Anything worth discussing on Michigan Utica?

Mark E. Ellis

There’s really nothing new going on there. We view that asset as an asset that’s – it’s a great for portfolio, very low decline, very low cost. We are not developing anything from a deeper interval perspective. We are producing on the Antrim shale there. We do have opportunities in some of the deeper shale formations there, but we have not pursued anything. Activity has been pretty pre-light up in that area.

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

Okay. Thanks. Kolja, you stopped buying puts – did you confirm that and are there any alternative strategies to hedging that non-PDP wedge longer term?

Kolja Rockov

You know, Ethan, I wouldn’t say we have not bought any for a little while here, a little over a year. But going forward, it still remains a component of our strategy. If we, one, made a material acquisition and two, felt like the economic viability of the puts, they’ve been more expensive than we’d like them to be in the last year, year and a half. If those two things lined up, I think we would not be afraid to do that. I think remaining significantly hedged is a priority for us.

But I do think that as we get larger, being 100% hedged may not be as important, but I think we’re going to look at it on a case-by-case basis. I mean, if you think about it, the only two material acquisitions we made since the last time we bought puts are Berry and oil puts have been expensive. You look at our ratio of oil puts versus gas puts, we have a lot more gas puts because we felt like those were more economically compelling.

And then the other acquisition we made was in the Permian, which was again oily. So, I think there’s been more volatility in gas recently, which is driving down the cost of gas puts and if we were to make a major gas acquisition, can’t tell you that we would or wouldn’t, but it would certainly be part of the discussion.

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

Okay. That’s very helpful. With respect to the trading relationship between LinnCo and Linn, that’s inverted since the LinnCo IPO, do you view that as a market saying or validating LinnCo as a currency when they’re basically saying, we expect you to deploy that, and therefore, that’s the reason for the discount?

Kolja Rockov

I don’t know. It’s hard to say. I still think that the tripling of LinnCo’s float and the movement of prior Berry shareholders into new LinnCo shareholders is still waving on it a bit, and so we’ll just have to wait and see over time.

Although I’ll tell you in the last couple of weeks it started to narrow, so I don’t know where it will ultimately go but that’s up for the market to decide. But the nice thing is we have good optionality. I mean, not necessarily with respect to C-Corp acquisitions, but with respect to access capital we can always choose the lowest cost of capital weather that’d be Linn or LinnCo.

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

Okay. Thanks. Last question, what should my base case expectation be for third-party M&A either announced or consummated this year?

Mark E. Ellis

In terms of aggregate number of transaction?

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

Yeah.

Mark E. Ellis

We still think it’s robust. It’s going to be a robust year. It got off a little bit of a slow start; there has been a few good things across the wire. But there’s a lot of things that we know of that are coming to market or have been indicated might come to market. So we’re still encouraged it’s going to be a pretty active year. I can’t put a number on it this year in terms of aggregate amount of billions of dollars transaction get done. I don’t have a good feel for that.

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

So, I’ll just bet on more gray hair for Rottino then.

Mark E. Ellis

You got it.

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

Alright. Thank you.

Operator

Thank you. Your final question comes from Eric Anderson with Hartford.

Eric B. Anderson – Hartford Financial Management, Inc.

Yes, good morning. Most of my questions have been asked – answered already, but let me ask just a question on the longer term outlook in your opinion to the natural gas liquids, propane, ethane; where do see those prices going over the next couple of years, because obviously they’re important to you.

Kolja Rockov

Yeah, I mean, I think we’ve unsuccessfully tried to predict that many times, and I don’t know that I can offer you a whole lot of wisdom there beyond 2014 really. I mean, there is plenty of industry research that I don’t know that I can add much to it.

But I can tell you that at least for our guidance sake, we went through a very detailed analysis of exactly where we have NGL production, what components are exactly in that production stream, which piece of it’s going Mont Belvieu, which piece of it’s going Conway and the aggregate of that added up to about 36% of WTI, which is what we guided to.

If I had to guess there’s probably some potential upside to that. I think maybe in the beginning of the year we are a little ahead and now I think we maybe a little behind. So we feel pretty good about our guidance in 2014.

And then the second thing I would offer you is that, last year NGL was about 20% of our overall production stream. It’s running just over 15% now. And I think I mean, who knows what we’re going to buy. But over time I would expect that to moderate as the total percentage of our production stream. So hopefully it becomes less relevant over time.

Eric B. Anderson – Hartford Financial Management, Inc.

Okay. I appreciate it. Thank you.

Kolja Rockov

Thank you.

Operator

Thank you. And we have no further questions at this time. And I would like to hand the call back over to Mark.

Mark E. Ellis

Okay. Well, thanks everyone for your time this morning and that concludes our call.

Operator

Ladies and gentlemen, thank you for your time. That does conclude the conference. You may now disconnect.

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