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Executives

Jeff Mobley – IR

Nick Dell’Osso – CFO

Steve Dixon – COO

Gary Clark - VP, Investor Relations and Research

Analysts

Doug Leggate – Bank of America Merrill Lynch

Arun Jayaram - Credit Suisse

Brian Singer – Goldman Sachs

Charles Meade – Johnson Rice

Neal Dingmann – SunTrust

Dave Kistler – Simmons & Company

David Tameron – Wells Fargo

Biju Perincheril – Jefferies

Scott Hanold – RBC Capital Markets

Joe Magner - Macquarie Capital

Bob Brackett - Sanford C. Bernstein

Matt Portillo - Tudor, Pickering, and Holt

Michael Hall – Robert W. Baird

Marshall Carver - Capital One Southcoast

Joe Allman - JPMorgan

Chesapeake Energy (CHK) Q4 2012 Results Earnings Call February 21, 2013 9:00 AM ET

Operator

Good day and welcome to the Chesapeake Energy Corporation 2012 Q4 and full year earnings conference call. [Operator instructions.] At this time, I would like to turn the conference over to Mr. Jeff Mobley. Please go ahead, sir.

Jeff Mobley

Good morning and thank you for joining our call today to discuss Chesapeake’s financial and operational results for the 2012 fourth quarter and full year. Hopefully you’ve had a chance to review our press release and updated investor presentation that we have posted to our website.

During the course of this call, our commentary will include forward looking statements regarding our beliefs, goals, expectations, objectives, forecasts, projections, and future performance and the assumptions underlying such statements. Please note that there are a number of factors that could cause our actual results to differ materially from such forward looking statements.

Additional information concerning these factors is available on our earnings release and the company’s SEC filings. Additionally, we may refer to certain non-GAAP financial measures, so we encourage you to read the full disclosure and GAAP reconciliations located on our website and in this morning’s press release.

I would next like to introduce the other members of our management team, who are with me on the call today: Steve Dixon, our chief operating officer Nick Dell’Osso, our chief financial officer; and Gary Clark, our vice president of investor relations and research.

Before I turn the conference over to Steve, however, I would like to share with you a few comments on a leadership change at Chesapeake. As you know, Aubrey McClendon, the company’s co-founder and CEO will retire from the company on April 1, 2013, and after leading the company during our first 80 conference calls, he is now stepping aside to Steve and Nick to lead this call.

In addition, a search is currently underway for a new CEO, and the board plans to complete this search by that time. Aubrey has had a remarkable career founding and leading Chesapeake, and has created one of the most valuable and innovative companies in the global energy industry.

Two of Aubrey’s most important accomplishments are the tremendous asset base that has been amassed by the company and the talented and dedicated organization he built to develop these assets. The culture and capabilities of the company Aubrey created, and the standards of excellence he championed, have been distinctive and inspiring, resulting in a company with extraordinary potential.

But his legacy will ultimately be the realization of that potential through the success and value that we all help deliver after his tenure as CEO concludes. With those thoughts in mind, and on behalf of nearly 12,000 employees at Chesapeake, we want to sincerely thank Aubrey for his visionary leadership and for his 24 years of tireless service to the company, the shareholders, the employees, and to the industry.

With that, I’m going to turn the call over to Steve Dixon, who is working with Nick Dell’Osso to guide the company through this period. I thank them, and all of my Chesapeake colleagues, for their continued dedication and focus as we work collectively to develop Chesapeake’s world-class asset for our shareholders. Steve?

Steve Dixon

Thanks, Jeff. I’m pleased to report substantial progress at Chesapeake this quarter, on three key objectives: improving our production mix towards more liquids, reducing per-unit production cost, and achieving our targeted capital budget reductions. Nick will talk more in depth about both the capital budget achievements and our cost discipline in a few minutes, but suffice it to say, I’m proud of what our operational teams have achieved and the path that we are on.

Clearly we have amassed an enviable collection of assets across 10 of the top 15 key onshore plays in the U.S., and now the task at hand is to convert a decade of industry-leading new play investments into improved shareholder returns. And we are well-positioned to do this, even more efficiently and effectively than ever before.

Over the past three quarters, Chesapeake has demonstrated that we have the people, properties, and processes in place to drive liquids production higher while also containing per-unit expenses. Furthermore, I’m energized by the opportunity to greatly improve our capital efficiency in the quarters ahead.

To this end, during the past year, all of our asset teams have been retasked and incentivized to shift their focus from acreage capture mode to meeting budgets and delivering higher returns on capital. Focusing our operations on the core of the core enables our drilling program to increasingly target the best parts of each play, which should translate into better well results and very impactful capital efficiency improvements.

Through focused pad drilling, our equipment mobilization times will compress, water handling logistics will be simplified, road and pad construction costs will decline, pipeline connection times will shorten, and many other economies of scale will be realized. We are targeting capital efficiency improvements of at least 15-20% as we transition to pad drilling.

Before I get to the operations, I’d like to take a minute to discuss our reserve changes during this past year. 2012 was a noisy year for reserve bookings, as low gas prices resulted in the removal of nearly 5.4 Tcf of reserves, primarily in the Barnett and Haynesville shales. We look forward to the return of these reserves when gas prices recover.

Additionally, we removed 1.4 Tcfb of reserves for non-price related factors. This is primarily as a result of the SEC five-year rule, given our change in rig allocations and the high grading of [spud] locations into our shift from natural gas to liquids. Importantly, production revisions to our crude reserves were positive, 131 Bcfb, as our individual well performance in aggregate exceeded our prior estimates.

With regard to the commodity mix, at year end 2011 our crude reserves were approximately 17% liquids and 83% natural gas. At year end 2012, this mix improved to 30% liquids and 70% natural gas.

Turning now to our asset base, I will highlight two plays that best illustrate the operational excellence being achieved at Chesapeake. First, the Eagle Ford Shale, which was once again the growth engine for our liquids production. Fourth quarter liquids production averaged 50,800 barrels per day. That’s up 38,500 barrels per day, or 314% year over year, and up 8,000 barrels per day, or 19% sequentially, versus the third quarter.

This was in spite of outages at Regency’s Tilden processing plant and barge delays for pipeline loading in Corpus Christi that impacted fourth quarter production by approximately 2,500 barrels per day. And as a reminder, approximately 82% of our liquids mix in this play is oil, and only 18% NGLs.

Looking forward, we have budgeted our outlook a year-end exit rate of approximately 70,000 barrels of liquids per day from the Eagle Ford. Achieving this near-40% growth target is subject to several factors, most notably the operational performance of certain midstream processing plants and the addition of natural gas gathering and compression systems, which have restrained our growth in each of the last two quarters.

That said, we are highly confident in the productive capacity of our Eagle Ford play, and believe that intermittent midstream issues would only impact the timing, not the ultimate delivery, of our production targets.

During the 2012 fourth quarter, we connected 98 wells in the Eagle Ford. Looking ahead, our goal is to connect approximately 400 wells in 2013, which is roughly the same quantity as we did in 2012. This is while running 14 fewer rigs than last year.

We were able to achieve this by connecting wells currently in inventory as infrastructure catches up, and also by benefitting from reduced spud-to-spud cycle times. We continue to make very meaningful progress in driving cycle times and well costs lower. Our average spud-to-spud time during the fourth quarter was 18 days. That’s down more than 30% from 26 days in the 2011 fourth quarter, and over this same time period, average per-well drilling and completion cost also fell roughly 30%.

And cycle times have continued further to decrease in 2013. Notably, we just recently drilled our fastest Eagle Ford Shale well to date in just under eight days. The asset team had done an outstanding job in this region, and I look forward to accelerating capital efficiency gains in 2014 when the percentage of our wells drilled on existing well pads is expected to increase over threefold from this year.

Moving on to the Utica Shale, we continue to focus our drilling efforts in the wet gas window of the play inside our joint venture with Total, where we hold more than 450,000 net acres. I’m pleased to announce that within this area, we are projecting average EURs per well to range from 5-10 Bcf depending on the area and the phase of the play targeted.

To date, we have drilled 184 wells in the Utica, 45 of which are currently producing. Production in the Utica was fairly minimal in the year in 2012 due to infrastructure constraints, but we are anticipating a significant ramp up during 2013, perhaps reaching 55,000 BOEs per day by the end of the year.

Helping us to achieve this goal will be gas processing infrastructure additions at Dominion’s natrium processing plant in Marshall County, West Virginia, which is scheduled to go online in April, followed by the first of three processing trains at Momentum’s Kensington plant in Columbiana County, Ohio, which is scheduled to go online midyear ’13, with the second train operational before year end.

Like the Eagle Ford, Chesapeake is generating significant efficiency gains in the Utica. Spud-to-spud cycle times have decreased 37% year over year from 35 days down to just 22 days. Average per-well drilling and completion costs have followed a similar path, and were down 27% year over year.

In terms of drilling results, I would particularly like to highlight a well we recently drilled in Carroll County. It’s the [Co 34-12-41H]. This well experienced 24-hour IP of over 2,200 BOE per day, with a liquids cut of approximately 33%, assuming full ethane recovery. We believe we’ve captured the industry’s largest position in the Utica, and look forward to solid results in this play for years to come.

Additionally, I’d like to summarize our results in the Anadarko Basin, where we are focusing on five plays: the Mississippi Lime, the Cleveland, the Tonkawa, Granite Wash, and Hog Shooter. These plays continue to provide steady liquids production growth. At December 31, we had 29 rigs running in these plays, and combined fourth quarter net production averaged 104,500 BOE per day, which is up 7,500 BOE per day in the third quarter, or 8% sequentially.

The production mix from these five plays combined continues to get oilier, with 39% coming from oil in the fourth quarter as compared to 36% in the third quarter.

To characterize the year ahead company-wide, the shift to liquids is progressing in line with expectations and we continue to anticipate 27% liquids growth in 2013. As planned, our natural gas production is now in decline, and our current guidance implies a 7% year over year decrease in reported natural gas production.

When adjusted for voluntary curtailments and the impact of our 2012 and projected 2013 asset sales, we believe the organic decline in our natural gas production will be closer to 9% year over year, assuming midpoint of our current guidance.

As we look at the balance of 2013, there are two major objectives we plan to accomplish. First is to continue to execute and build on the strong liquids production growth and cost discipline trends that are already firmly in place. Second is to complete two-year asset divestiture program that we have previously laid out to fund our capital investment program, reduce our financial leverage, and focus our operational efforts on our best plays to enhance returns on capital.

Along these lines, my operational teams have been fully engaged in the asset sales program since the outset, and I am confident they will not miss a beat in executing the program that has been set before them.

Lastly, I would like to thank all the employees of Chesapeake for their hard work, loyalty, and determination as we move through this challenging period of low gas prices and a leadership transition. Our employees have always been, and will remain, our best asset, and I look forward to sharing their success in many years to come.

I’ll now turn the call over to Nick.

Nick Dell’Osso

Good morning, and thanks, Steve. We are pleased with our 2012 fourth quarter results, and the substantial headway we made in terms of growing oil production, refining our focus, and reducing costs. Adjusted earnings per share of $0.26 exceeded consensus estimates of $0.14 per share, and our production and EBITDA topped consensus estimates by a substantial margin as well.

Our strong performance was driven primarily by oil production volumes, improved oil price differentials, and solid execution on the cost side of our business. We produced 8.9 million barrels of oil in the quarter. Only 0.3 million barrels, or about 3% of which, was attributable to the stop of production from the portion of the Permian sale that closed in October.

Quarter over quarter, our significant growth areas were in the Eagle Ford and mid-continent regions, where we continue to generate high-quality oil growth, which is reflected in our strong oil price realizations.

During the fourth quarter, our company-wide differential to WTI was a positive $0.26 per barrel, which is greatly improved from our third quarter differential of WTI minus $4.15 per barrel. Our outstanding marketing team warrants recognition for helping us achieve these favorable prices through securing access to premium pricing markets via pipeline, opportunistic entry into oil trucking in certain areas, and favorable lending arrangements.

Importantly, less than 10% of our oil production is considered condensate, as defined by an API gravity of 50 degrees and above. Condensate oversupply concerns have been raised in the marketplace recently, and I believe Chesapeake has a good plan in place to successfully navigate this issue.

It’s also worth noting that our total liquid stream by volume for the quarter consisted of 66% oil, 34% NGLs, a favorable mix that further strengthened realized revenue. We achieved this mix in spite of the sale of our Permian assets, which continued a much higher percentage of oil than NGLs.

On the cost front, the fourth quarter was the first full quarter of the year where our decline in activity began to show up materially in our reported results, with our drilling and completion costs down approximately 30% year over year.

We averaged 88 operated rigs for the quarter, and spent $1.596 billion on drilling and completion costs compared to 122 operated rigs and $2.275 billion in the third quarter of 2012. By December, our monthly drilling and completion capex run rate was down to approximately $500 million, and we expect our drilling and completion spend to remain roughly in line with this rate throughout 2013.

Further, we came in on budget for January 2013 as well. This puts us on track to spend approximately $6 billion for the full year 2013, net of drilling and completion carries from joint venture partners, as compared to $8.8 billion in 2012.

I’m also pleased to note that production expenses came in at $0.83 per Mcfe, down $0.01 per Mcfe from the prior quarter and down $0.05 per Mcfe year over year.

G&A came in at $0.23 per Mcfe, down $0.10 per Mcfe from the prior quarter, and down $0.12 per Mcfe year over year. This decline included the impact of filling a portion of our additional overhead to the full cost pool due to changes in the [copus] rules, so while we do not expect G&A to remain at these very low levels going forward, our cost structure initiatives are clearly starting to bear fruit as demonstrated by the significant reduction we’ve made to forecasted G&A as well as other cost items in our outlook on schedule A of the earnings release.

I’d now like to quickly review some of the significant events of 2012, a year that was heavily impacted by continuing low natural gas prices. Chesapeake entered the year focused on continued rapid growth of our oil and NGL production to provide a more balanced source of cash flow generation going forward.

We were running a total of 164 rigs in January of 2012, when the extremely warm winter and resulting rapid and severe drop in first quarter natural gas prices prompted us to further reduce our activity levels. As a result, we ramped down our drilling program to just 85 rigs by the end of 2012.

Fortunately, we were able to rely on our liquids-rich portfolio to buffer the significant impact to 2012 cash flows created by the natural gas price decline and were also able to close on the sale of nearly $12 billion of asset sales during the year.

At the end of the year, we were still able to achieve an 84% increase in oil production and a 54% increase in total liquids growth, setting us up for a more balanced 2013 and beyond production profile, and importantly, holding production on some very valuable oil leases in the process.

To recap the year, our biggest asset sales consisted of exits from the midstream business and the Permian Basin. Our midstream exit enabled us to redirect the company’s strategic focus and capital resources into our upstream oil and gas operations.

As a reminder, we originally entered the midstream business at a time when the midstream industry’s knowledge and appetite for capital growth and unconventional assets was limited. Entering midstream proved to be profitable and strategically important. However, given the changing dynamics of the NLP space and the increasing maturity of our operations in unconventional resource plays, we concluded that it made strategic sense to exit this business in 2012.

I’m pleased to report that we recorded a total pretax gain on our midstream sales, including our gain on the sale of our equity interest in CHKM, or ACMP, earlier this year, of approximately $1.3 billion. The Permian sales also represented a significant basin exit for us, but one that again helped to strategically and financially refine our focus. While the Permian is a liquids-rich basin, it was not going to be allocated a significant enough amount of capital within our broader portfolio in the coming years relative to our other assets.

With respect to 2013, I’m pleased to report that we are in a completely different position from a liquidity and funding perspective than one year ago. We began 2013 with an undrawn revolver with $4 billion of availability, which, if necessary, could cover our approximate $4 billion funding gap in 2013, which is derived from our updated outlook in this morning’s press release.

We look forward to soon announcing progress on our Mississippi Lime transaction, which will further reduce the funding gap previously mentioned, and have closed on, or have under PSA, more than $200 million in aggregated other asset sales so far this year. Importantly, the company and the board of directors remain committed to reducing Chesapeake’s financial leverage.

Let me now walk you through some highlights from our outlook, on schedule A of our press release. First, we are reiterating our liquids production growth for 2013 and are very pleased with our results to date. For 2013, we forecast our oil production and differentials to remain strong. We now project that our oil production will account for more than 51% of our 2013 oil and gas revenue.

Turning to NGLs, I would like to note that we are not forecasting any ethane rejection in our production numbers this year, but certainly acknowledge that some could occur. Additionally, our NGL growth will be highly contingent on the timing of processing infrastructure in the Utica. Therefore, our line of sight on NGL production is less clear than that of our oil production.

That said, NGLs are projected to account for less than 10% of our oil and gas revenue stream in 2013. Therefore, our exposure to soft NGL markets and potential processing delays is not particularly material.

Next, I would like to address something that our organization is very proud of, given the work put into it. We are lowering our cost per unit expectations across the board: production expenses, production taxes, and G&A. We remain focused on these metrics and believe that our increased operational emphasis and diligence in this area will help us deliver further reductions ahead.

These cost changes, combined with unchanged production from previous guidance, have allowed us to increase the bottom end of our range of cash flow expectations, despite a reduction in expected average 2013 natural gas prices.

In our revised outlook, we are reiterating our $6 billion drilling and completion, and our $400 million lease hold budgets for 2013. Last quarter, we removed our guidance around oilfield service and other capex spending following the midstream operations. However, to provide a little color there, we expect our field services capex to be lower in 2013 than in 2012, and we are not looking to add any new capacity to that business, beyond orders for equipment placed earlier last year.

Finally, I’ll address our hedge position for 2013. You’ve no doubt noticed that we put on a significant amount of gas hedges for 2013, and feel good about being 50% hedged on the gas side for 2013 at an average price of $3.62 per Mcfe. We are almost fully hedged on the oil side at $95.45 per barrel for 85% of our 2013 production, and have also added a material amount of oil hedges in 2014 at an average price of $93.67 per barrel.

We believe these incremental hedges go a long way toward derisking our 2013 and 2014 cash flow expectations, despite the fact that we are somewhat bullish on gas markets from this point forward.

With that, operator, we’ll now open up the call for questions.

Question-and-Answer Session

Operator

[Operator instructions.] We’ll go first to Doug Leggate with Bank of America Merrill Lynch.

Doug Leggate – Bank of America Merrill Lynch

I’ll start off with Nick, or whoever wants to take this one, on the asset sales. Nick, it sounds like you’re pretty close to the the Mississippi Lime disposal. Could you share with us any color in terms of whether this is solely an acreage deal or the format in terms of joint venture or whatever? Or particularly, if there’s any production associated with your likely transaction?

Nick Dell’Osso

I’m going to hold back on giving you any specifics on the transaction given we’re in the throes of working on it. But I would say that there is some production associated with it, and we have included the impact of that in our outlook.

Doug Leggate – Bank of America Merrill Lynch

Maybe a follow on related, then. One of the biggest criticisms, perhaps, of the company is still the outspend, or the overspend. And you highlighted the liquidity position since the beginning of the year, at least the end of last year. However, if you don’t achieve the $5-7 billion of asset sales, it wouldn’t really help you. So can you help, or provide any kind of color, as to how the board is influencing the spending decision versus the potential ultimate scale of disposals, and any comfort you can give us on the line of sight as to how you get to such big numbers, $5-7 billion this year?

Nick Dell’Osso

Well, we and the board are very focused on our budget for the year, which as you noted has multiple elements. It has our spend. It also has asset sales and other costs associated with it. We’re focused on the end game of where we will come out. We’re focused on deleveraging. And all of those things have to work together.

We’re also focused on the fact that through this year we continue to hold [by] production some very valuable liquids [acreage]. With every well we drill, with every acre that we hold, we become more flexible in our drilling program, and that’s a great thing in the short term. And we are happy and would consider using that flexibility if needed.

Now, that being said, we have great confidence in our asset sale program. We have good line of sight into what we plan to accomplish, and we think the outlook that is in front of you all today, with the $6 billion drilling program, and completing of asset sales in 2013, is something that is achievable, and that we believe we will achieve this year.

Doug Leggate – Bank of America Merrill Lynch

Last one is for Steve. You have not changed your liquids guidance now for quite a while, but it seems that the oil piece of the liquids growth is running at least ahead of what we were expecting. Can you just help us understand, what is drilling to core to the core mean in terms of type curves, because you really have not updated us there since 2010. And if you could just speak to how you see the risks through your liquids in particular, your oil growth, as we move through the next 12 months?

Steve Dixon

We are focusing our capital program on liquids, and drilling our very best locations, and that’s starting to [gin] those results. Probably the Eagle Ford is certainly the biggest driver, where most of our capital is, and where we’ve had the greatest success. And it continues to impress and improve. And hopefully we’ll get some more results quarter over quarter going forward.

Doug Leggate – Bank of America Merrill Lynch

No change to the type curve? In the Eagle Ford in particular?

Nick Dell’Osso

We haven’t provided the type curve since 2010.

Doug Leggate – Bank of America Merrill Lynch

That’s what I mean. It seems to be pretty out of date.

Nick Dell’Osso

Our results we think show great growth there, and great performance. [talkover] continue to deliver to you guys out of the Eagle Ford, and out of all our liquids plays.

Operator

We’ll go next to Arun Jayaram with Credit Suisse.

Arun Jayaram - Credit Suisse

Nick, I wanted to ask you, obviously you have a $4 billion outspend this year. Wanted to see how the Marcellus could tie in to the deleveraging of your balance sheet. Obviously you have a big acreage position here. I’d argue it’s probably the highest multiple business in the U.S. E&P. The company’s obviously focused on liquids. Why not think about monetizing a piece of the Marcellus?

Nick Dell’Osso

We’re looking at a number of alternatives on the A&D front for this year. We have a pretty good plan in front of us. We have had a couple of non-core acreage packages in the Marcellus out of the market that we had said we were going to do in our third quarter.

And we continue to do that across the board, look for the places within our portfolio where we are going to be the most efficient, given the footprint that we have, and where we have the best results, and know that we have acreage that would be more valuable to someone else. Very good acreage that can be drilled for a great return, but within our portfolio, as we’re going to allocate capital, can be delivered to someone else for a better return in up-front cash to Chesapeake. So we’re doing that in the Marcellus, and we’re doing that across all of our plays.

Arun Jayaram - Credit Suisse

And in terms of what we have line of sight on today, it’s the Mississippi Lime and an acreage package in the Eagle Ford, in terms of upstream asset sales? Is that fair?

Nick Dell’Osso

Those are the two biggest that we’ve talked about publicly. That’s correct.

Arun Jayaram - Credit Suisse

And switching gears a little bit, you guys recently talked about a 10-year agreement on the methanol front. I just wanted to get some details on that, and perhaps are you seeing more industrial customers looking to do similar kinds of things?

Nick Dell’Osso

We are seeing a lot of interest from industrial customers. There’s been a really big increase over the last couple of years, but recently it’s been even probably a more concerted effort by industrial customers to talk to us about some creative ideas.

And we’ve found the methanol transaction to be very attractive for us. It links our ultimate delivery to a price of a commodity that’s closer tied to crude, so we can take some gas exposure and tie it in a way that correlates it more to a crude price. And it’s something that brings additional demand onto the U.S. market for natural gas.

So we think that we have a great price structure locked in there, one that achieves a very favorable price for Chesapeake and still provides us with enough exposure to upside to make it interesting beyond the price at the outset of the deal.

Arun Jayaram - Credit Suisse

And one quick one for Steve. Where is your Haynesville production today versus at the peak?

Steve Dixon

I know it was down pretty hard quarter over quarter. Gross, we’re down to 1.3 from 2 Bcf a day.

Arun Jayaram - Credit Suisse

Down by about a third. Okay, that’s helpful.

Operator

We’ll go next to Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

First, on the oil mix, can you just talk about how, if at all, you expect your oil mix to evolve and change in three areas: the Mississippi Lime, Eagle Ford, and in Utica? I noticed that the Mississippi Lime, that oil as a percentage of the total ticked up during the quarter. In the Eagle Ford, it ticked down a little bit. And just also wondering when you talk about 5-10 [Bcfe] whereas in Utica, what percentage oil versus NGLs versus gas you would expect?

Steve Dixon

I’ll start with the Utica. That’s still pretty early and results change pretty quickly across the play. Yields have a pretty wide range, and so that’s why we gave a wide range. So I don’t really have a number to give you on that.

Nick Dell’Osso

The Mississippi Lime and the Eagle Ford, we don’t really expect the mix to change there over time. We have pretty good insight now with those basins having pretty material amount of production. So we feel good about that production mix being reasonably constant over time. There will be fluctuations of course, as you bring on different packages of wells, but we don’t expect any material differences.

Brian Singer – Goldman Sachs

And those, in places like the Mississippi Lime, would be consistent with the 40-45% that you saw in the third and fourth quarter? Or do you expect some sort of degradation over time as wells decline?

Nick Dell’Osso

We had 46% gas in the fourth quarter in the Mississippi Lime, so then 45% oil and the rest being NGLs. And again, we don’t anticipate any trend difference there over time.

Brian Singer – Goldman Sachs

And then just strategically, to the degree that gas prices surprise to the down side, can we expect that Chesapeake would sell more assets than it would be presently expected, or reduce capital? Or borrow against the revolver?

Nick Dell’Osso

I’m sorry, could you repeat the question?

Brian Singer – Goldman Sachs

Yeah, if gas prices surprise to the downside, should we expect that Chesapeake would reduce capex from current guidance, sell more assets than expected, or just utilize the revolver and increase debt?

Nick Dell’Osso

You know, the first answer there is that 72% of our revenue is hedged for 2013. So short term impacts to commodity prices won’t have the impact that it did have on us last year. The second answer is that, again, we’re very focused on deleveraging over time. So I’ll just probably leave it at that. We have a lot of leverage we can pull to get there, and we’ll continue to be focused on delivering on asset sales, be focused on staying within our budgets and reducing our leverage.

Operator

We’ll go next to Charles Meade with Johnson Rice.

Charles Meade – Johnson Rice

I recognize that you guys are still in process on a Mississippian sale, but could you give some parameters on the deals that you’re looking for, both in terms of scope, whether it’s over your whole 2 million acres, or timing?

Steve Dixon

Charles, I just would really like to not take questions on a pending transaction this morning.

Charles Meade – Johnson Rice

That’s certainly understandable. The other thing I wanted to ask you guys about, maybe this is better for Steve. I really liked the slides you guys put together on the takeaway in the Marcellus and Utica. I think you mentioned that the Marcellus takeaway is going to be limited through year end ’13, where there’s going to be incremental capacity come along, but do you view this as more of the last significant hump to get over as far as takeaway, or do you view this as the first of many hurdles that you’re going to have, or that the industry’s going to have in the coming years, as far as takeaway?

Steve Dixon

You know, there’s a number of projects, as you’re well aware. Some of those projects are more focused on getting us premium market access versus just capacity and then some, of course, do provide important capacity relief. Today, there’s planned a total of additional 3 Bcf of capacity additions, as we’ve noted in that slide. And some of them have just come on pretty recently.

There will be periods of time where capacity will get ahead of the deliverability of the basin, and there will be periods of time where the industry catches up with it. It’s going to be an evolving push and pull that will continue over time.

But I think pretty quickly here, particularly with gas prices where they are, and rig count where it is, you would get to a point where you wouldn’t have long term capacity constraints before too terribly long in the basin.

Operator

We’ll go next to Neal Dingmann with SunTrust.

Neal Dingmann – SunTrust

Just wondering, on the Utica that you mentioned, looking at that 5-10 Bcf that you gave, could you give a little bit on what type of type curve you’re expecting there? Or I guess what I’m looking at more specifically is what kind of first-year depletion, or if you can give us any depletion levels around those 45 wells that are producing?

Steve Dixon

We are constrained there, and really haven’t been able to produce these wells as we would like. So that’s why we gave a big range in Bcfe. So I’m afraid it’s just too early to tell.

Neal Dingmann – SunTrust

And the 55,000, is that just for later this year, assuming that you have most of this midstream tied in? Can you maybe walk through it a little bit as far as kind of what you’re expecting on the takeaway there, how to see that progress in the Utica?

Steve Dixon

Yes, to reach that, we need all three of those plants up and running before year end, which they are on target and expect that to happen.

Neal Dingmann – SunTrust

And then just lastly, you mentioned about how good your Eagle Ford results certainly have been. Just wondering, is it just the result of trying to contain the cash flow outspend as far as why cut those rigs there? To go from 34 to 17 rigs on such a great area, just want to hear your comment about if that looks like expectation would be to run kind of run around that going forward?

Steve Dixon

Fortunately, most of that is in efficiency gains. We are still able to produce the same amount of net wells. And it’s also not to outrun our infrastructure. So this is just the right well count to both hold our acreage and be more efficient with our capital.

Operator

We’ll go next to Dave Kistler with Simmons & Company.

Dave Kistler – Simmons & Company

Just looking at your ’13 capex, can you kind of break out what percent of that is dedicated to maybe four drilling commitments? Or asked differently, what percentage is fixed obligations, [HBP] drilling, etc., and what percentage is flexible?

Nick Dell’Osso

You know, we don’t generally provide that breakout. Suffice it to say, we are focused on holding by production our Eagle Ford and other liquids plays that still have some work to do there. Those also happen to be our highest return plays. So that’s really why we don’t focus on looking at it that way.

We’re really more focused on what Steve described a few minutes ago, which is allocating our rigs to make sure that we’re focused on returns, both near term and longer term returns. We don’t want to get in front of infrastructure. We want to focus on the efficiencies that we’re creating. And we want to try to drill the best wells.

So there are a couple of places where we’re going to go hold some leases, and take care of some commitments, but that’s really not what’s driving our rig allocation this year as much as it is trying to be most effective and efficient at growing our liquids production and focusing on returns.

Dave Kistler – Simmons & Company

And then you mentioned in your comments that you achieved about $12 billion in divestitures in ’12. When I’m looking at the cash flow statement, it’s highlighting about $10 billion. Can you walk me through the disconnect, or what’s rolling over into ’13, just based on announcement dates and closure dates, etc., just so we can get a sense of how that feeds into your guidance of $4-7 billion for ’13?

Nick Dell’Osso

Just to reconcile the 2012 number, remember that one of the things we included in that ’12 is the sale of the preferred interest in our Cleveland Tonkawa asset, which shows up in the financing section. So there’s no rollover into ’13 of that ’12, and the ’13 number is focused on new projects that we’ll be talking to you guys about.

Dave Kistler – Simmons & Company

And then one last one. If you could kind of give us an update in terms of maybe drilled uncompleted wells or drilled and completed but not tied in in sort of the Marcellus and I guess the Rockies as two potential large growth areas for this next year, that would be great.

Steve Dixon

In the North Marcellus, there’s still a couple hundred wells to be turned on that we want to get in line this year.

Nick Dell’Osso

One of the things I would point you to, Dave, is on page 14 of our release we break out our well costs and we had broken out last year the costs on unproved properties, which would be basically dollars that we had spent on wells that were not yet put into the pool, because they were not yet proven.

That becomes effectively a balance over time, and so you’ve seen the last two quarters that’s a negative number. So net-net, we are decreasing the number of inventory wells in the company at this point, and we’ve done that in the Marcellus and we’ll continue to do that across the company with a few instances where we’re adding to it into our plays. But net-net, we’re in a decrease mode.

Operator

We’ll go next to David Tameron with Wells Fargo.

David Tameron – Wells Fargo

In the Marcellus, can you talk a little about the pipeline? Is that an issue with the specs for the BTU content? Or can you talk a little about that bottleneck there? And then when do you guys expect ATEX to come on?

Nick Dell’Osso

We can project a certain amount of ethane, and then at some point we do need that pipeline to alleviate our takeaway from the basin, but at this point, that’s really about capacity as much as it is anything. So we do think that ATEX will come on beginning of ’14. Late ’13, beginning of ’14.

David Tameron – Wells Fargo

We’ve just heard from other operators and other interested people that ethane’s going to be a big bottleneck getting out of the Marcellus over the next couple of years, even with additional pipeline capacity. What’s your snapshot of the current situation up there?

Nick Dell’Osso

We have taken out a pretty good bit of capacity on ATEX, and so we’re feeling good about our ability to move it out of the basin to the Gulf Coast, which should get us to the best market available for ethane in the U.S. We do also have a small amount of [FT] going up to [Sarnia] as well.

David Tameron – Wells Fargo

Jumping over to the Utica, the EURs you put in the press release, that 5-10 Bcf, could you maybe just talk about what production mix is assumed in that number, and then how variable it is across the acreage position? Just an update overall on the Utica?

Steve Dixon

It is pretty early, and a very limited well set, so that’s why we gave such a big range. And it does vary across the play, so that’s all the guidance we can really provide at this time.

David Tameron – Wells Fargo

All right. Last question, Nick, you commented on the condensate oversupply. Can you just expand on that a little bit, and what you’re alluding to there?

Nick Dell’Osso

Just pointing to the fact that we are always focused on getting premium pricing for our products, and paying attention to what our product mix is, and what the supply demand dynamics are for the subproducts, if you will, in the marketplace.

And given the questions that were raised this week by a number of analysts around condensate pricing, we just wanted to comment on it. In particular, in the Eagle Ford, our average gravity in the basin is about 45 degrees, and then I just wanted to give the color that condensate is less than 10% of our total mix of oil across the company. So we just thought that was helpful color to provide.

Operator

We’ll go next to Biju Perincheril with Jefferies.

Biju Perincheril – Jefferies

First, on your production guidance, are you assuming less asset sales in the new 2013 guidance? Or is it the same amount of asset sales as previously assumed?

Nick Dell’Osso

It’s approximately the same. The mix has changed a little bit here and there, but we always attempt to show our expectations of asset sales into our guidance unless we tell you otherwise. And we had that the last time, and we have it again this time. So we show you, at the top of that page, the expected production impact of what we’ve assumed to be sold in 2013.

Biju Perincheril – Jefferies

So the difference in the footnote, then, I assume is the asset sales estimated completed, especially the Permian?

Nick Dell’Osso

Right. The last time we gave an outlook, it would have been inclusive of production for the end of 2012 as well as ’13.

Biju Perincheril – Jefferies

And then your gas production declined in the fourth quarter. Was there anything special in those numbers, is that an organic decline rate that we saw in the fourth quarter?

Nick Dell’Osso

Well, we did have our Permian sale in the fourth quarter, which was significant. There was a lot of gas produced out of the Permian. And we did manage some [FT] commitments in the Barnett as well, which had a minor impact, but was something that was not organic.

Operator

We’ll go next to Scott Hanold with RBC.

Scott Hanold – RBC Capital Markets

A little bit on Utica again, and I’ll try to skin the cat a different way. When you step back and look at the Utica today versus what you all thought a couple of years back, it seems like it’s a little bit more gassy, and the core is a little bit smaller. Is that a fair statement?

Steve Dixon

Well, the gassy part may not be bad. Those are higher IPs and can be higher rates of return. And we’re very pleased with the results that we’re getting. So nothing bad to say, and no shrink in the core. It’s just early, and the results are so variable on the product mix, that it’s difficult to give.

Nick Dell’Osso

We did give a couple of specific well results in our release today, so you guys can look at that, and probably draw some conclusions from there. There’s a lot to learn about this basin still. Our number of penetrations relative to the number of wells that we’d ultimately drill is very small. And we don’t yet have the processing capacity to flow things at full rate yet, and there’s just a lot to learn. So that’s the reason we’re being a little bit less informative here, just because we feel like we need to learn more before we can say more. But so far, we’re very, very pleased with the play.

Scott Hanold – RBC Capital Markets

What if this does turn out to be a little bit gassier? Do you see the economics of Utica being a little bit better than the Marcellus? And would there be a lot of excess gas coming out of the basin? And you did previously, I think, Nick, in your comments, indicate that you all are pretty bullish on gas prices. And certainly when you step back and look at you guys locking in a lot of your hedging and your production in 2013, it kind of sends a different message. Can you kind of square the circle around that one?

Nick Dell’Osso

Sure, I’d be happy to. When I say we’re bullish on gas prices from here, I’m thinking not just about the next couple of months, and just 2013, but really thinking further out on the curve as well. There’s very little contango in the curve, and we don’t think that accurately reflects the amount of development being put into natural gas today.

Nor does it reflect the potential increases in demand that are becoming less potential and more real around export and around other industrial uses. Our 50% hedging program for 2013 is really about derisking our plans. We saw some prices that were respectable within our 2013 plan. Know that we have a plan that exceeds cash flow and want to make sure that we protect as much of that cash flow as we can. So I don’t think they’re inconsistent, and just to be short term protective while still being long term bullish, I think, makes sense.

As far as the volumes for the Utica, Steve will probably have more color there, but it’s a good basin, and when markets tell the industry to produce gas, there will be some gas that we can look to the Utica to deliver.

Scott Hanold – RBC Capital Markets

So then I would assume your bullishness, more on the forward-looking, on gas prices, is more of a demand-driven than a supply-driven story? Because certainly there’s ample opportunities to ramp up gas pretty quickly in several areas.

Nick Dell’Osso

We certainly have the ability to ramp up gas when we desire. I think ramping down and ramping up always takes a little bit longer than the financial markets would like, but we have a lot of wells you could go drill in the Haynesville that are on existing pads. You have a lot of wells you could go drill in the Marcellus on existing pads. And then certainly in the Barnett as well. And many in the industry have the same dynamic.

So the industry can respond to demand here for a long period of time, and we’ve got a lot of capacity to do that, and the Utica will be another leg to that stool. But the industry also is doing a pretty good job of giving itself the flexibility of how to respond and when to respond to that demand by holding its acreage by production.

Operator

We’ll go next to Joe Magner with Macquarie Capital.

Joe Magner - Macquarie Capital

Just maybe one more attempt at Mississippi Lime. I realize you don’t want to discuss the details, but there have been some different structures talked about in the past, through this plan to pursue a lump sum JV. And then that changed to maybe breaking it down into smaller packages. Any direction on where you’re headed with the just kind of overall concept there?

Nick Dell’Osso

I think I’m just going to say again, we don’t really want to discuss a pending transaction. But we hope to be able to discuss it in great detail with you guys soon.

Joe Magner - Macquarie Capital

Okay. And then in terms of your overall position there, can you provide any breakdown between Kansas and Oklahoma? On the acreage side as well as on the number of wells that have been drilled and the production split between the two states?

Nick Dell’Osso

There is a map in our slide deck, so you can see the breakout, at least visually, by acreage in the play. But you can also see that all of our rigs are in Oklahoma at the moment, as we continue to learn more about the Kansas part. Page 28 of our investor deck.

Joe Magner - Macquarie Capital

And then any anticipated charges or impacts related to firm midstream transportation and processing agreements that are in place given the sale of your midstream interests?

Nick Dell’Osso

We reiterated our guidance around gas differentials, and that takes into account the revised structure of those contracts. Those contracts are basically similar to what we did internally. It’s basically a cost of service approach. So we can work with [Access] to direct and tell them the capacity we need, and there’s a cost of capital approach to setting the fees over time. So we were doing that internally, and that’s really how our contract has been codified with them to do it externally. So based on those fees, we reiterated our guidance. We had planned for that when we set this guidance up initially, and it’s still the same.

Joe Magner - Macquarie Capital

Any insight into the search process? Level of interest? Or any expectations on timing of when a candidate might be identified?

Nick Dell’Osso

No, I think I’ll have to let the previous comments by the company and the board stand there for now.

Operator

And we’ll go next to Bob Brackett with Bernstein Research.

Bob Brackett - Sanford C. Bernstein

I had a question on asset sales. What are you assuming for the timing of these dispositions in your production guidance?

Nick Dell’Osso

They’re layered in throughout the year, as we expect the sales to occur. So they’re all timed as we think the sales will occur, and the impacts will hit our financials.

Bob Brackett - Sanford C. Bernstein

So you’re assuming half of them are done by the middle of the year?

Nick Dell’Osso

I really don’t want to get that specific this morning. Again, we’ve lined them out with the processes that we’re running, some of which are underway now, some of which will be underway soon. And that’s just how we have it layered in. And the Mississippi Lime is, of course, the nearest term, and it is forecasted into our outlook to be the nearest-term impact.

Bob Brackett - Sanford C. Bernstein

And of the $200 million that you’ve either closed or have PSAs for, what are those? Can you give us basins or packages that those might be?

Nick Dell’Osso

Mostly acreage. There’s not a lot of production in that. And it’s just packages and non-core acreage.

Bob Brackett - Sanford C. Bernstein

Any color on which packages?

Nick Dell’Osso

There was a little bit of DJ Basin in there, and a little bit of Marcellus and a few other things. It’s a gathering of a few different ones.

Bob Brackett - Sanford C. Bernstein

And on the working capital, I noticed it ticked up a bit. What’s your long term plan for that working capital going forward?

Nick Dell’Osso

Our working capital tick up, a lot of it was driven by the fact that we used a current tax asset attribute to offset some gains from our midstream sale. That was in excess of $600 million in the quarter. One thing I would point you to is that our payables were down pretty materially.

Our working capital is a microcosm of our company, as I’ve noted before. As activity levels come down, our payables will come down. As commodity prices go up, our receivables will go up. We do, of course, have partners in a lot of our wells, and so you have offsetting effects of as commodity prices go up, we have greater revenue payable, and as our activity levels come down, we have less receivables from partners on operating capex. But overall, it’s really actually trending in the right direction when you consider the movements for taxes, etc.

Bob Brackett - Sanford C. Bernstein

And the Utica 5-10 Bcf equivalent, what’s the well cost and lateral link stages on that sort of well?

Steve Dixon

Well costs have come down significantly this last year. We’re down to low to mid-$7 billion per well. The lateral links are over 5,000. Don’t have that average with me, but they’re long laterals.

Operator

We’ll go next to Matt Portillo with Tudor, Pickering, and Holt.

Matt Portillo - Tudor, Pickering, and Holt

I was curious if you could provide us with your current rig count and specifically how we should think about your rig averages in the PRB, Haynesville, and Barnett for 2013?

Nick Dell’Osso

We detail our current rig count on page eight of our slide deck, and so you can see that we have just about 82 operated rigs. That’s adjusted for Permian. So from there, you asked about which basins again?

Matt Portillo - Tudor, Pickering, and Holt

The PRB, Barnett, and Haynesville. I’m just looking on slide 15. You guys have that as about 16% of your drilling and completion capex, and I think the PRB was accelerating as of Q3. So I’m curious where the rig count is there. And then just curious on your Haynesville and Barnett rig count. I know you guys were at two rigs. Is that going to pick up in the back half of this year?

Steve Dixon

No, we’ve got both the Barnett and the Haynesville flat at two rigs, and the Powder River is at 10.

Matt Portillo - Tudor, Pickering, and Holt

And then just a couple of other quick questions from me. In terms of the Eagle Ford, can you give us an update on the uncompleted well count?

Nick Dell’Osso

We don’t have that number with us this morning. It’s a very dynamic count, as we are running a number of rigs there, bringing on a lot of infrastructure every day. But we’ll continue to have a decent number of wells in inventory, in the Eagle Ford, making lumpy but good progress all year. There will be times where we bring on a piece of infrastructure that will allow us to connect a bunch of wells at once, and so again, it’s pretty lumpy, but it will be a challenge throughout this year, one which we think we have forecasted appropriately in our plan.

Matt Portillo - Tudor, Pickering, and Holt

And my final question, just on the spending side, could you give us any color on a specific number for your spending on OFS midstream and other for 2013?

Nick Dell’Osso

It is down a good bit from last year. The only growth on oilfield services that we have in this year is a couple of rigs we had ordered early last year that are being delivered. These are really high-value rigs that are going to be used primarily in the east that are very efficient and great assets for us. And we have our last two frack spreads that I think are both already now delivered. So the vast majority of our COS spending is down. It’s significantly lower than last year.

Matt Portillo - Tudor, Pickering, and Holt

Is there any color on the magnitude of that reduction? Is it 50%? Is it 75%? Is it 25%? Just trying to get an idea of the magnitude.

Nick Dell’Osso

More than 50%.

Operator

We’ll go next to Michael Hall with Baird.

Michael Hall – Robert W. Baird

Just wanted to dive in a little deeper on the Eagle Ford. Just first on the efficiency gain, cycle time improvements you’ve been seeing, just curious how much further you think you can take that. And then what percentage of activity is currently on pads versus [unintelligible] capture in 2013 versus 2012?

Steve Dixon

In 2013, we are not able to do a lot of pad drilling, because we’re still in HBP mode. That will be completed really in the second half of the year. So that will change throughout the year, so we may be as little as 15% now, to really by the end of this year, once we’re complete, it will basically be at 100%. And so we do anticipate for 2014 to have pretty significant additional improvements in our efficiency.

Michael Hall – Robert W. Baird

And then on the proposed acreage sales in the Eagle Ford, were there any lease-hold expiration issues that might be considered in evaluating that deal?

Steve Dixon

No, the core part of it can all be easily held by production.

Operator

We’ll go next to Marshall Carver with Capital One Southcoast.

Marshall Carver - Capital One Southcoast

On the Utica, you talked about the 5-10 Bcf per well. Across what percentage of your million net acres do you think you can get those recoveries? How much has been derisked at this point?

Steve Dixon

Were you referring to the Total JV box, which is about 450 net? We think there is a lot of gas, but mostly dry in the remainder of it, and so there’s been very few tests in it, but our geologists think there’s a significant amount of gas in place. But would probably be on the high side of that on a Bcf basis.

Marshall Carver - Capital One Southcoast

On the production mix in the Utica, could you at least give us the production mix for the year-end target that you mentioned? And is that a gross or a net number that you mentioned?

Steve Dixon

That is a net number. But it’s a function of wells that we get hooked up on, because there’s such a variable on the mix. But you can look at the wells in our press release and get kind of an idea from those IPs what we’re seeing.

Nick Dell’Osso

We are attempting to drill as close to infrastructure through the year as we can, and so I’d like to think that the wells that we showed you there are going to be representative of at least a good bit of the wells we drill this year. They won’t be all like that, but there’ll be a lot.

Marshall Carver - Capital One Southcoast

And do you have the expected number of wells to be put on production over the year?

Nick Dell’Osso

Don’t have that with us this morning.

Operator

We’ll go next to Joe Allman - JPMorgan.

Joe Allman - JPMorgan

A question on the funding gap. So if you just look at your total spending, not just the items you give guidance for, but total spending, and you compare that to your expected cash flow, what’s your estimate of the funding gap for 2013?

Nick Dell’Osso

About $4 billion.

Joe Allman - JPMorgan

So then, on the low end of what you’re going to sell, you’ll hit your capex, and on the high end, you’ll hit your capex plus you would pay down debt?

Nick Dell’Osso

That’s correct.

Joe Allman - JPMorgan

And is it still the company’s goal to get long term debt down to $9.5 billion?

Nick Dell’Osso

Yeah, I think we’re absolutely focused on getting the company deleveraged financially, and we’re very intent on getting to investment grade metrics, getting to a much stronger balance sheet. We picked $9.5 billion a couple of years ago. That’s still a pretty good number when you look at it from an investment grade metrics standpoint. But we’re two years more now from when we set that goal and we’ll always probably look at it on a pretty fluid basis. It could ultimately go lower than that, could be a bit different. But in general, significant deleveraging is absolutely the plan and won’t change.

Joe Allman - JPMorgan

And the two big assets that you’ve got out there, that you’ve identified, are the Mississippian, which you’re close to, it sounds like, and then the Eagle Ford Shale North. Will those two get you pretty darn close to the $4 billion?

Nick Dell’Osso

I’m going to let those deals speak for themselves as they happen, but we have a number of things that we’ll do this year.

Joe Allman - JPMorgan

Is it your goal, even though you haven’t disclosed it, to sell other significant assets of the size of, say, the Mississippian or Eagle Ford Shale North, that you just simply haven’t disclosed, to enable you to cover your capex plus pay down a significant portion of debt?

Nick Dell’Osso

I think it’s fair to say that some of the things we plan to sell are bigger than others, and there’s, again, a number of projects that will get us to that ultimate number.

Joe Allman - JPMorgan

And is the goal to sell as much non-cash flow generating stuff? Can you get there? Or do you need to really get into some cash flow generating assets to raise the money you want to raise?

Nick Dell’Osso

It’s a balance, but of course from a strategic perspective, you always like the idea of selling assets that are not producing cash flow today, and are going to be more valuable to someone else than they are to us, which by definition would mean that they have less cash associated with them.

Joe Allman - JPMorgan

And what’s the status of the Eagle Ford Shale North sale?

Nick Dell’Osso

We’ll be speaking to you guys about that when the time comes, and just don’t really want to discuss pending transactions today.

Joe Allman - JPMorgan

When I look at your 2013 product guidance, in the note that you have underneath, toward the top of the guidance, now you’re including about 35 Bcfe of asset sales in your current guidance. Previous it was at 140 Bcfe. You kept your guidance the same. So does that mean that the non for sale production is actually lower than what you previously thought? And if so, why would that be?

Jeff Mobley

The prior guidance really reflected the asset sales that we were expecting to complete in the last half of 2012, and reflected the production that those assets would have in 2013. Specifically, the Permian Basin sale. Our current guidance really just reflects the incremental transactions that we have for 2013.

Joe Allman - JPMorgan

I’m not sure if I fully understand. Is there kind of a reduction in your non for sale assets?

Jeff Mobley

There’s no change. It’s just reflecting that we’ve already closed certain transactions that were part of the production associated with our guidance. There’s no change.

Joe Allman - JPMorgan

Okay. So I guess you’re referring to the Permian for the most part?

Jeff Mobley

Yes.

Joe Allman - JPMorgan

So in your prior guidance, the fact that the Permian was going to be gone was already in your prior guidance, right? Schedule B?

Jeff Mobley

That’s correct.

Joe Allman - JPMorgan

So that difference between the 140 Bcfe and 35, you’re saying that’s Permian?

Jeff Mobley

Primarily. Great. Well, I think that’s about all the time that we have. We’ve gone past the top of the hour. We appreciate everyone attending our call today, and if you have follow up questions, please contact myself, Jeff Mobley, or Gary Clark. Have a good day.

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