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Chesapeake Energy (NYSE:CHK)

Q3 2013 Earnings Conference Call

November 6, 2013, 9:00 a.m. ET

Executives

Jeffrey Mobley - IR

Doug Lawler - CEO

Nick Dell’Osso - CFO

Jim Webb - General Counsel

Gary Clark - VP, Investor Relations and Research

Analysts

Dave Kistler - Simmons & Company

Doug Leggate - Bank of America Merrill Lynch

David Heikkinen - Heikkinen Energy Advisors

David Tameron - Wells Fargo

Scott Hanold - RBC Capital Markets

Arun Jayaram - Credit Suisse

Neal Dingmann - SunTrust

Peter Kissel - Howard Weil

Michael Kelly - Global Hunter Securities

Matt Portillo - Tudor, Pickering, and Holt

James Sullivan - Alembic Global Advisors

Joe Allman - JPMorgan

Operator

Good day everyone, welcome to the Chesapeake Energy Corporation Q3 2013 earnings conference call. Today's conference is being recorded. At this time, I’d like to turn the conference over to Mr. Jeff Mobley, senior vice president of investor relations and research. Please go ahead, sir.

Jeffrey Mobley

Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2013 third quarter. Hopefully you've had a chance to review our press release and updated investor presentation that we’ve posted to our website.

During the course of this call, We will be making forward-looking statements which include statements regarding our beliefs, goals, expectations, 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 the forward-looking statements.

Such factors are identified and discussed in our current earnings release and the company’s SEC filings. In addition, we are under no obligation to update the forward looking statements made during this call and you should not place undue reliance on such statements. We will also refer to certain non-GAAP financial measures during the call and we encourage you to review the GAAP reconciliations located on our website and in this morning’s release.

I would next like to introduce the members of management who are here on the call with me today: Doug Lawler, our chief executive officer; Nick Dell’Osso, our chief financial officer; Jim Webb, our general counsel; and Gary Clark, our vice president of investor relations and research.

We will next turn to prepared comments from Doug, and then we will move to Nick’s comments, and then to Q&A. Doug?

Doug Lawler

Thank you, Jeff and good morning. We’ve had an exciting third quarter, one marked by significant transformation and the implementation of a new strategy for Chesapeake. As a reminder, our new strategy has two fundamental tenets: first, financial discipline, and second, profitable and efficient growth from captured resources.

This strategy, combined with our world-class assets and talented employees, provides the foundational elements for Chesapeake to achieve our goal of delivering top-quartile performance. The company has now aligned its structure to deliver differential value to our shareholders through disciplined cash flow growth rather than an activity-focused, land-driven capital program.

We have recently completed an extensive review of the entire asset base and I’m very pleased with the value-creation opportunities that exist in our portfolio. Through the transformation process, we’ve maintained our focus on improved operational efficiencies and reducing capital intensity. This statement is supported by solid third quarter financial results and oil production growth.

Another key takeaway for the quarter is our continued progress regarding capital discipline. In the third quarter, our drilling and completion capital spending was approximately $350 million less than the second quarter. We have also reduced our land acquisition spending and our production costs.

We still have significant opportunities to improve our capital allocation and efficiency and reduce our cash costs, which we believe will result in greater returns and greater cash flow. For the quarter, Chesapeake reported adjusted earnings per share of $0.43, which compares to $0.10 per share in the third quarter of 2012.

Adjusted EBITDA was $1.325 billion, up 29% year over year. On the production side, oil growth led the way, up 23% year over year, while total production growth, on an organic basis and adjusted for asset sales, in the third quarter was approximately 8% year over year.

Net oil production in the third quarter increased to 120,000 barrels per day, or roughly 4,000 barrels per day greater than in the second quarter. This is despite the sale of assets in the Mississippi Lime and Northern Eagle Ford Shale, that contributed approximately 15,000 net barrels of oil per day in the second quarter. Oil production growth in the third quarter came primarily from the Eagle Ford and to a lesser extent the Utica, Mississippi Lime, and the Southern Marcellus.

The percentage of production from liquids plays increased to 27% during the quarter and the percentage of realized revenue was 65%. We expect a continuation of this trend due to the ongoing ramp up in the Eagle Ford and the Utica, and the continued focus of our capital program on liquids drilling.

In light of better than expected oil production during the third quarter, we are again raising our full year 2013 oil production outlook by 2 million barrels to a range of 40 million to 42 million barrels. With one quarter left in the quarter, you’ll note that the midpoint of our guidance implies a projected decrease in oil production from the third quarter to the fourth quarter of approximately 9,000 barrels per day.

I’d like to point out a few factors underlying this anticipated sequential decrease. Accelerated inventory reduction during the second quarter in the Eagle Ford, along with one month of oil production from assets that we sold at the end of July, provided additional oil volumes in the third quarter, while weather and infrastructure issues in the Eagle Ford during October have slightly reduced oil volumes for the fourth quarter.

Additionally, as part of our focus on discipline, we have reduced our rig count at the Eagle Ford throughout the year. This short term break has allowed us to concentrate on optimizing the drilling program going forward as we transition to a pad-based program, which we expect will lead to improved cycle times and improved project economics.

We have also increased our focus on well scheduling, which we anticipate will minimize downtime associated with simultaneous operations in the future. We expect that these factors will combine to provide a brief pause in the growth rate in the Eagle Ford oil production during the fourth quarter, with an expected return to sequential organic growth in 2014. We look forward to sharing a more detailed outlook with you early next year.

Now I’d like to switch gears and discuss capital spending. I’m very proud of the asset teams for coming in under budget for the quarter while still meeting or exceeding our production targets. Drilling and completion expenditures were approximately $1.25 billion during the third quarter, roughly $180 million less than budget and $350 million less than the second quarter.

Spending on new lease hold was $45 million during the quarter, or approximately $50 million below budget. The lower than expected capital expenditure level is partially attributable to fewer wells drilled and completed in the quarter. We are also beginning to experience capital efficiencies and lower average well costs resulting from improved operating performance, most notably in the Eagle Ford, where our drilling on single well patches decreased from approximately 65% in the first half of the year to 40% in the third quarter, and we anticipate this percentage will be approximately 25% in the fourth quarter and 15% or lower next year.

Turning to asset sales, through the end of the third quarter, we have received proceeds of approximately $3.6 billion. During the fourth quarter, Chesapeake anticipates completing additional asset sales for net proceeds of approximately $600 million. Additionally, we continue to pursue other asset sales transactions that may close in the first half of 2014.

The proceeds from sales are anticipated to be directed toward reducing financial leverage and complexity and further enhancing our liquidity. We expect that further transactions will be driven by portfolio optimization rather than near term funding needs. As previously noted last quarter, we currently do not see any need to issue equity, and we will continue to drive greater efficiencies into our capital program. These efficiencies and cost leadership are an important part of our ongoing effort to match capital expenditures with cash flow.

To conclude, I’m very pleased with the organization’s ability to deliver on its near term production and cost targets at a time when multiple transformational initiatives have been in progress. Some of the results of these initiatives are already being realized while we expect others to be realized over time.

As previously noted, we will be providing our 2014 guidance in early 2014, after we have completed our assessment of the optimal allocation of capital within our portfolio for the year. We expect to continue delivering organic production growth next year, and we plan to do so with a lower capital program than in 2013.

I’ll now turn the call over to Nick Dell’Osso, our chief financial officer, for additional financial and performance information. Nick?

Nick Dell’Osso

Thanks, Doug, and good morning. As Doug noted, the third quarter was a strong quarter for production, asset sales, and capital discipline, which enabled us to lower 2013 capital expenditure guidance and leave production guidance relatively flat while at the same time making substantial improvements in our balance sheet and liquidity.

We ended the third quarter with nearly $5.2 billion of liquidity, consisting of $4 billion of undrawn corporate revolver, approximately $215 million of availability on our oilfield services revolver, and approximately $1 billion of unrestricted cash.

Our liquidity position improved by approximately $430 million compared to the end of the second quarter, and by approximately $840 million from year-end 2012. Long term debt net of cash ended the quarter at $11.7 billion, down from $12.4 billion at the end of the second quarter and $12.3 billion at the end of the year.

In line with our strategy, we continue to reduce financial leverage and complexity and have a number of initiatives underway in the fourth quarter of this year that will continue into next year. For example, we recently repurchased some assets that were subject to sale leaseback arrangements with financial counterparties including surface real estate in Fort Worth as well as a package of drilling rigs.

Turning to costs, our production expense in the quarter was $0.76 per Mcfe as we continue to do a good job of managing LOE despite our ongoing transition to liquids. Accordingly, we are reducing our full year 2013 production expense guidance range by $0.05 to $0.80 to $0.85 per Mcfe.

Looking ahead, we are focused on optimizing production and returns, so some of the initiatives we believe could be very positive to our program, such as work over expenses and increased usage of artificial lift, may result in some upward pressure to production expenses from current levels as we get into our 2014 development program.

Longer term, we aim to further optimize our per-unit production expense even as we transition to a higher mix of liquids in our production stream. To accomplish this, we have established a cross-functional team specifically charged with identifying and implementing LOE reduction and optimization measures.

With respect to G&A, many of you have seen the announcement surrounding our workforce reductions during September and October. These were difficult but necessary actions to align the organization with our new operational structure and strategy to achieve profitable growth from captured resources. We have also been implementing other non-workforce-related G&A initiatives over the last year that will result in further cost savings, the full effect of which we will highlight for you with our 2014 outlook.

On the hedging front, we have been actively locking in oil and gas prices for next year via swaps and collars, as well as opportunistically covering a portion of our short oil call position. We have entered into swaps covering 2014 production to establish an average natural gas price below our $4.23 per Mcf on approximately 640 million cubic feet a day of production. On the oil side, we have swaps with an average floor of $93.79 per barrel covering about 60,000 barrels per day.

With regard to our long-dated oil call position, we have taken advantage of low volatility and the decline in oil prices in recent days to buy back approximately half of our outstanding short call position in 2014 and approximately 35% of the position in 2015. This will free up hedging capacity and provide us flexibility to enter into more downside oil price protection when and if the market provides an attractive opportunity to do so.

I’d like to conclude with some comments about our natural gas differentials, and in particular Northeast basis. Our company-wide natural gas differentials for the quarter came in at $1.46 per Mcf, which is an increase of $0.17 per Mcf compared to the second quarter.

This increase is primarily attributable to the temporary maintenance related basis dislocations that we and other operators experienced in the Marcellus during the quarter. We have adjusted full year differential guidance in our outlook to reflect the basis widening we have seen in the Marcellus and to a lesser extent other basins.

Chesapeake has firm transportation contracts for approximately one-third of the 1.4 Bcf per day of new capacity going in service in the Northern Marcellus during the fourth quarter, as we look to route production into more favorable markets.

Thank you for your time this morning, and we will now open up the call for questions. Operator?

Question-and-Answer Session

Operator

[Operator instructions.] And we’ll take our first question from Dave Kistler with Simmons & Company.

Dave Kistler - Simmons & Company

Real quickly, just thinking about ’14 and the progress you guys have had with cost reduction so far, can you highlight for us, or just give us a little bit of indication, of where you think you could see the biggest area for continued improved reduction in cost or capital efficiency?

Doug Lawler

I guess the way I would answer that for you, in light of not being able to give the particular guidance by area for 2014, is that a lot of the initiatives that we have undergone have been what I call cost management. And I believe that we have cost leadership opportunities in all of the areas in which we invest. And those cost leadership initiatives are going to provide us significantly better returns and better margins in 2014 as we go forward in our program.

So rather than focus on one particular area or highlight what area might benefit from the specific initiatives, I believe that all the areas are going to benefit and it’s because of the focus, it’s because of the supply chain synergies and the opportunities to capture efficiencies that the company has previously been unable to do as we move to a more efficient well-disciplined drilling and completion program on multi-well pads.

Dave Kistler - Simmons & Company

And then just based on your comment of moving to multi-well pads, can you talk a little bit about maybe what that means to production? Not so much the trajectory as you highlighted organic growth, but more so should we expect the production becomes lumpy, or the particular areas - perhaps the Eagle Ford or the Utica - will see really lumpy production? Just trying to get a handle on that going forward.

Doug Lawler

Sure, that’s a good question. As you would expect, when you move to multi-well pads your cycle times can increase a little. But overall, based on the focus that we have, I think that we’ll continue to see some lumpiness in the program, but I don’t think it’s going to be too different from what we’ve seen in the past, and my hope is that with the better planning, the better cycle time in aggregate, structuring, as I mentioned in my notes about the scheduling initiatives that are in place, I’m hopeful that that will completely offset whatever multi-well pad drilling and completion operations could result in as far as lumpiness.

Dave Kistler - Simmons & Company

And then maybe just one more in the Eagle Ford. Given the production growth that you saw, some of the other hiccups, can you just talk about the wells that you did complete? Kind of laterals, costs, anything that you did differently that contributed to the strong production growth there?

Doug Lawler

We had about 140 turn in line wells in the Eagle Ford during the quarter, which was outstanding performance. We’re getting into an efficiency mode and attacking the wells and how we can expedite the production, shortening the cycle times, planning for the next completion and the infrastructure. So it really is a combination of all those different things that are resulting and seeing some improved performance there. I’m excited about what the Eagle Ford has to offer for us, as you are aware. We have the industry leading oil growth rate in the Eagle Ford, and it’s very competitive and we expect additional really good things to come from the Eagle Ford.

Operator

And we’ll take our next question from Doug Leggate with Bank of America Merrill Lynch.

Doug Leggate - Bank of America Merrill Lynch

Doug, I met with you and your team not so long ago, and my understanding is that you’ve got a bunch of task teams or task forces in [town] where you’re looking at stretch goals to bring operating costs down by something on the order of 50%. That’s a big goal. I’m just wondering if you could give us an update as to how you see progress there and the likely timeline for delivery. And I’ve got a follow up please.

Doug Lawler

We see huge opportunity there, and that’s something that’s going to take place over time. Capturing the innovation and the ideas of our field staff, the use of automation in our operations, and all the different things we have available to us, competitive things such as our data systems that we have here in Oklahoma City, how we can optimize drilling, completion, and production operations are all really really exciting things that I believe will continue to help us on our production cost.

So we have set some very aggressive targets. We are performing well on our lease operating expenses and production costs. I’m encouraged by the progress the teams have made to date. But we’re not satisfied with it, and we see huge opportunity there. And we’ll be striving for a pole position with respect to our lease operating costs compared to our peers.

Doug Leggate - Bank of America Merrill Lynch

Could you remind me too, the progress to date, Doug?

Doug Lawler

I haven’t provided that yet. We’ll be putting that information in when we share our 2014 guidance.

Doug Leggate - Bank of America Merrill Lynch

One other one from me. I don’t know if this is one you’re able to answer with any eloquence, but what I’m trying to do is reconcile lower spending with your comments in your press release suggesting that you will still have growth next year. So can you help us with the order of magnitude as to what the core of the core well profile looks like compared to, let’s say, the average wells that you had been drilling to try and hold acreage? And I guess the key areas like the Marcellus, Utica, and Eagle Ford would be the ones we’d focus on.

Doug Lawler

As you’re aware, the single well pad drilling, the HBP focus to keep the lease hold and continue the test the acreage that we have under lease initiatives have been significant in the past several years. But it has not been efficient. And so the production growth recognized from these single well pads and as we’ve delineated the acreage has not been the most efficient production growth.

That said, we still have to demonstrate our ability in the core of the core to show higher quality, better returns, and offset the inefficient production growth decline that will be taking place in the next few years. And so that really is the crux of the evaluation process and how we’re focusing where the capital can be directed to capture the best margins and the best returns, and to continue to show and demonstrate competitive growth.

So there’s really not any other advice I can provide for you there at this point in time, other than the comment that I made that we expect to see positive production growth next year with the lower capital spend.

Doug Leggate - Bank of America Merrill Lynch

Is this the kind of thing you’ll be able to add more color on when you provide guidance?

Doug Lawler

Absolutely.

Doug Leggate - Bank of America Merrill Lynch

Okay. And the final one from me, if I may, the $600 million of disposals planned for Q4, can you quantify any volume impact associated with those? Sorry if I missed that in your remarks. And maybe an update as to how you see the order of magnitude on further disposals, let’s say first half of next year.

Doug Lawler

Just to be clear here, we’re only talking about probably an impact of one month from the transactions that are slated for the fourth quarter. So the production impact of those this year won’t be significant. It’s safe to say our asset sale program is still focused on assets that we consider to be outside of our primary development plans and focus areas.

We have a lot of great assets, as you know, and some of those are coveted by others, including at times others that operate those assets. And so this is just a chunk of assets here that we’re selling that shouldn’t have an impact on fourth quarter production in a material way, and really shouldn’t impact the trajectory going forward in a material way, on what’s being sold.

Doug Leggate - Bank of America Merrill Lynch

And order of magnitude for next year?

Doug Lawler

On this package, no. I don’t want to give an order of magnitude on it, because like I said, it’s not going to have a material impact on the trajectory.

Operator

We’ll take our next question from David Heikkinen with Heikkinen Energy Advisors.

David Heikkinen - Heikkinen Energy Advisors

You all provide really good details in your press releases in each area as far as wells completed and activity levels. Could you give us kind of an outlook as far as pace in each area, of what we should be reading at year-end just to help us kind of illuminate the slowdown in the Eagle Ford and what your exit rate would be from a rig count might be helpful as well, in each region?

Doug Lawler

We’re in that process right now, of narrowing down and focusing on what exactly those rig counts are going to be. At present, we’re in the 60 rig range, and I think you can expect that through the rest of the fourth quarter. As we look to provide that guidance in 2014, we’ll be more specific about ranges in the Eagle Ford and the other areas.

I think the question is very good, but without being able to provide more detail on it, what I can share with you is we are focused on it very very intently and making sure that the capital that we have to spend is absolutely directed at the best spot to provide the competitive growth metrics that we believe we need to achieve.

So your question is good, but you’re a couple of months ahead of us in being able to provide that information.

David Heikkinen - Heikkinen Energy Advisors

If we just think about a run rate then, you’ve pulled down to 60 rigs, you slowed down a little bit in the Eagle Ford, just because of the month of October. Everything else kind of runs the same. I guess the problem is in the Utica with the Natrium fire, probably that slows down as well. Can you give us an idea of what your current Utica production is maybe?

Doug Lawler

We’ve been working closely with Dominion, and as we’ve looked there at that fire and how it’s impacted this, we had provided information that suggested we were going to be in the $330 million net exit rate there for Utica. We’ve had really, really good growth from the second to the third quarter in our volumes, and with the Kensington facility starting up in December, there’s an additional $200 million that will be coming available.

So I don’t think that the surface related, whether it be processing, compression, or infrastructure issues right there are going to materially impact our operations and rig count in the Utica, just because these are short term in nature and we’ll be working through those and continuing to optimize on our own efficiencies and what we control.

David Heikkinen - Heikkinen Energy Advisors

So it’s just fourth quarter that it impacts?

Doug Lawler

Yes.

David Heikkinen - Heikkinen Energy Advisors

And then Nick, your comments on gathering and transported marketing have been a focus in the market on what’s happening in the Northeast, kind of on average are your realizations on oil, gas, and NGLs tend to be a little lower than peers. Can you give us a little more detail as far as how much of that is fixed and how much of that is variable, just given the temporary maintenance?

Nick Dell’Osso

Well, the moves this quarter are primarily due to the basis differentials in the Northeast, and to a lesser extent some other basins. But we’ve had our guidance out there for what our differentials look like based on our gathering and transport contracts that are in place for the year, and then I would say they were impacted again this quarter by what we saw in the way of basis. So without breaking it out specifically, because obviously those contracts are not all fixed and under [unintelligible] themselves, I would just guide you to look at it that way.

David Heikkinen - Heikkinen Energy Advisors

So it kind of keeps the same levels, maybe bring it down a little bit once you get past this temporary issue?

Nick Dell’Osso

I’d like to think we should return to a little better differential after we get past this temporary issue, that’s right.

Operator

And we’ll take our next question from David Tameron with Wells Fargo.

David Tameron - Wells Fargo

Just a couple of questions. Doug, back to the capex comment about 2014, I know you’ve said before in the past that your other capex is going to be down. When you’re talking about lower capex year on year, are you just talking about E&D? Or are you talking about the total?

Doug Lawler

I’m talking about the total.

David Tameron - Wells Fargo

Care to give any color on E&D?

Doug Lawler

I would love to, but you’re going to have to hang with me there for a little bit, David.

David Tameron - Wells Fargo

All right. No problem. And then let me get back to David’s question. You guys put out some rig projections. In the second quarter you said you were going from ’13 going to end the year at 10 in the Eagle Ford, those types of numbers. Are those still good? Or are those all being reevaluated right now?

Doug Lawler

Well, I think there’s so many opportunities for improvement there, not only with the way that the drilling and completion teams are looking at the operations and already realizing synergies and reduced costs, but there’s also opportunities with our scheduling and our simultaneous operations planning that’s going to also help reduce cycle time and help improve that cash on cash cycle time. And so all of those things are weighing into whether or not we run 10 rigs or 12 rigs.

And as you’re fully aware, the capacity of this organization and the talent that resides here, if we need to run 15 rigs in there, we can do it very quickly. If we decide we need to run 20, we can do that. But it’s going to be at a pace that gives us the optimal returns, and so what we see at present is that we’re at that 10 rig run rate, and there will be an opportunity to potentially increase that next year, but it’s not going to be at the expense of parking capital in the ground that we don’t get a return on, and a return in competitive near term order.

So the pace, the returns, the quality of the investment, and the cycle time are going to really drive that, and what’s great about it is we can run 10, 12, or 20, and have done it before.

David Tameron - Wells Fargo

And then just last question, on the divestment front, you talked about the $600 million in the fourth quarter, but you still have the service piece out there, some other interest in various E&P companies, etc. What’s your outlook for those as we head into ’14 or even ’15 as far as… I know your capex spend is going to be way down in the service side, but can you just talk about outlook for those assets?

Doug Lawler

We’re continuing to evaluate the portfolio, and each of the entities and assets that are underneath Chesapeake Energy we are working and looking closely at to make sure that the returns generated are accretive to higher corporate performance. And there’s noncore assets that have been sold off, there are other assets that we’re looking at potentially selling, and basically it’s going to be return-driven on the total portfolio. And we’re in a position where our liquidity and our cash flow generation, there’s not anything that’s going to be sold on a fire sale basis or that needs to be done so that we can fund our capital program next year.

So it will be more opportunistic in how it fits in our portfolio, and I think that the best way of perhaps answering your question is that there are a number of other things that we’re looking at because we have a high-priority target to continue to improve our balance sheet and we’re going to do that.

Operator

We’ll take our next question from Scott Hanold with RBC.

Scott Hanold - RBC Capital Markets

Could I just clarify one thing? In the Utica, are you basically confirming your 330 million a day target exit rate? Is that right?

Doug Lawler

No, it is subject to the Natrium plant, and when it comes back online. But I think the key there is that we’re ready to go, and with the Kensington plant coming on, we’ve got adequate capacity that we’ll continue to be ramping up there, and it’s just a near term issue. And we’ll hopefully get past that pretty quickly.

Scott Hanold - RBC Capital Markets

The other thing is that you all indicated at the beginning, I think, that you did sort of that review of your asset base, and you see a lot of value creation opportunities. Stepping back and looking at the context of that comment, is that sort of implying that there’s just a lot of high-level development opportunities there, or that there’s certainly a lot more monetization effort that you can undertake as you look into ’14 and beyond?

Doug Lawler

I think the fair answer there is it’s both. We see significant opportunities for capital reduction, capital efficiency, and the process that we’ve implemented, and it’s working very well right now in how we competitively allocate our capital for the best returns. I’m very pleased with the progress we’ve made on that, and monetization, things that we don’t see that will be a part of our investment portfolio in the next several years will be evaluated for potential monetization.

Scott Hanold - RBC Capital Markets

And would you be willing to speak specifically about [unintelligible], or maybe in general, like things like ownership of oilfield services, Frac Tec, Chaparral? I mean when you look at those relative to CHK’s other upstream opportunities, would you consider those a little bit more noncore?

Doug Lawler

Well, we’ve talked about some of those assets in the past as being items that we would be willing to sell. And frankly there’s no difference in viewpoint there. The reality is we have no need to rush out and just take whatever price is available.

So for example on Chaparral or Frac Tec, those are our assets that given where valuations are in the industry today, and the structure of our ownership, we could either sell or hold for better valuation at some point. They don’t require us to continue to put capital into those entities, and they’re passive investments. And so we’re not in a rush to sell at a bottom price, and yet there’s still things that we would be willing to sell. So as far as their being noncore, I’m happy to say that’s still the case.

Doug touched on oilfield services previously, our own internal services, that is, and that’s a business that we’ve owned for a long time, we’ve had a lot of success with, and it’s part of what we’re reviewing to determine the best way to own and operate or get value from that business going forward.

Scott Hanold - RBC Capital Markets

And then one more quick one if I might, more of an operational question in the Eagle Ford. Are you all evaluating other formations or zones outside of the Eagle Ford? Are you looking at both the upper and lower Eagle Ford, the Buda or Pearsall? Are those things you’re testing at this point?

Doug Lawler

Yes, as you know, we’ve got a significant lease hold position there, and we see other opportunities as well. So I think that we’ll continue, as we look to improve our Eagle Ford program and performance, making progress on the things that have already been accomplished so far this year, that looking at those other opportunities for additional investment, we’ll be evaluating and testing through time.

And so there’s a number of initiatives that are in place on our lease hold, including spacing and other optimization efforts that we believe are going to pay off very nicely for us with that large lease hold position.

Operator

We’ll take our next question from Arun Jayaram with Credit Suisse.

Arun Jayaram - Credit Suisse

I just wanted to just see if you could give us a little bit of a baseline as we look towards, you mentioned in the press release, organic growth in 2014. Just wanted to see if you could give us a baseline on what we should think about. You had some asset sales this year, just to base that organic growth on. And my follow up is would you expect to grow your liquids in ’14 relative to that baseline?

Doug Lawler

Yes, we continue to expect, with our focus on the Eagle Ford and the other liquids plays, that we’ll continue to grow our liquids.

Arun Jayaram - Credit Suisse

And just trying to understand what the baseline for that growth would be, given the asset sales that you’ve done in 2013.

Doug Lawler

The organic growth rate in the third quarter was 8%, and so when you look at the divestitures and things that we can be potentially looking at next year, that’s why we have said that we have confidence that we’ll be able to continue to show positive growth with the reduced capital in 2014.

Arun Jayaram - Credit Suisse

Just to clarify, I’m just trying to understand, when you’re talking about organic growth, and as we look to our models, do we just assume your actual reported results in ’14, are you parsing out the impact of asset sales?

Doug Lawler

Yes, same-store sales is what we’re describing as organic growth, but if you look at it in an aggregate basis as well, we still are evaluating it with plans that we will continue to see growth next year. So without being able to provide you the exact detail just yet, we have to continue to defer to when that guidance will be provided and that detail is coming shortly.

Arun Jayaram - Credit Suisse

Fair enough. And just a follow up, as you think about potentially doing something with your oil service assets per se, obviously that’s, perhaps, helped you in terms of thinking about efficiencies, but as you know, Doug, the oil service multiples are quite a bit lower than Chesapeake’s current multiple. So just wondering if you can talk about maybe some of the positives of separating oilfield services from, on the flipside, some of the negatives.

Doug Lawler

Well, as Nick highlighted, the oilfield services have provided a very good competitive advantage for Chesapeake, and we’ve seen tremendous synergies by having those assets in the company. And part of our ongoing evaluation there includes, with our new strategy, how can we best optimize with those assets as a part of the company.

And so it’s under review, and we’re going to continue to evaluate it, because the driver there is that with all of our assets, we’re going to make sure that we get the best returns on all the capital that we spend, and our direction in trying to be a better performer and a top quartile performer. So it’s under review, and at this point in time, that’s really all the color I can provide on it. And we’ll share more with you when we can.

Operator

We’ll take our next question from Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust

Just wondering, on as far as lease expenditures, your thoughts on next year versus this year and how you see that. Clearly, you’ve got the capital reduction plan in place, but just wondering, still on leases, what your thoughts are.

Doug Lawler

The company still has a very significant lease hold, and as we are going through this process of evaluating where the capital will be allocated next year, some of that lease hold will continue to be developed. Some of it will be tested for whatever technology or synergies that we can push to those areas to capture value in the future, and some of the lease hold won’t make it in our cut.

And so we’ve got an ongoing process that we’ll be continuing to evaluate, and that evaluation will include current operations and what we can do with it to get the best returns. It will also include how technology and innovation can be applied, and in some cases, if it’s very long-dated, or we don’t see [unintelligible] to it, we’ll actually sell it or relinquish it. So the lease hold position, the key there is we’re not going to be a land-driven company.

Neal Dingmann - SunTrust

And then just one other question, turning it over to the Utica. You’ve got a good slide on 13 that basically lays out the midstream development there. Your thoughts? Is that now, when you look at it going forward, keeping up to your activity there? Or are you still resting some of these wells, maybe perhaps a little bit longer than you would waiting on some midstream?

Doug Lawler

It’s improving, and I think what you’ll see is continued improvements with the additional facilities and processing that’s being built out and will be in place the latter part of this year. So I think that that story and matching the cycle times and the optimum investment rate there that rig count and all is under close review, and I believe it will be very close to optimized in 2014.

And we’re not quite there, but with all the infrastructure that’s being put in place, and it will be in service here in the latter part of the fourth quarter, first part of next year, we don’t see that materially impacting the pace that we’ve got scheduled at this point in time.

Operator

We’ll take our next question from Peter Kissel with Howard Weil.

Peter Kissel - Howard Weil

Nick, one more question on the balance sheet, please. It seems like you’re pretty comfortable with the current leverage levels, and of course you’ve got the $600 million coming in the door over the next quarter or so. So it seems like your plan is to basically just drill your way to a less levered balance sheet. Am I reading that correctly? Or is there some sort of more drastic delevering event to look for in ’14?

Nick Dell’Osso

Well, when you say we’re comfortable with our current level of leverage, I guess I’d answer that in two ways. One, I don’t feel any current pressure in the market relative to our current level of leverage, and obviously credit markets are favorable. The cost of debt is favorable. However, for the long run, we believe our balance sheet has too much debt on it, and we have a strategic goal to reduce that.

And so as we look at our portfolio, and as we identify the assets that we believe are not optimal for us to own, and like we said, we think there are several that, over the course of the next many months and maybe years, we’ll be where we would like to sell them. We expect that a number of those proceeds will go towards reducing the leverage on our balance sheet.

And when I say the leverage on our balance sheet, I commented that we’re looking at overall debt, we’re looking at cash commitments in the future, so in my prepared comments I talked about having reduced some sale leasebacks on some rigs, which are not debt, or operating leases, but yet they’re a structure that’s in place that gets in the way of exactly how we own our assets that have a cash cost to us that’s carried out into the future, and it’s a simpler way for us to look at our company without those leases in place at the moment. And we believe we’ve bought them back at relatively attractive prices, from an NPB perspective it makes sense for us to do so.

And so that’s how we’re going to continue to think about this. We want our balance sheet to be smaller on the leverage side, and we want our overall capital structure to be simpler. And we can do that with the proceeds from asset sales, we can do it with the proceeds that are thrown off from the bus over time, and we’ll continue to do so. But there’s no real sense of urgency in that. We’re not rushing out to create something to make it happen immediately.

Operator

And then one other question. There’s been a lot of talk on efficiencies, but I was wondering if you wouldn’t mind just drilling down a little bit deeper and talking about some of the completion optimization initiatives. Not so much on the pad drilling, but more on the actual well designs. Any sort of reduced frack spacing or anything like that in particular that you’re using across the portfolio that’s really driving better performance, better IRRs and whatnot?

Doug Lawler

It’s a great question. I think the best way to look at that is that the efficiencies that the industry has captured over the past several years we’re just at the beginning stages of, whether it be the amount of sand pumped, the spacing, the cluster spacing, the fluids, we have so many opportunities to continue to improve and optimize our program.

And each of those things are under evaluation and review, and I think we’ll continue to see in all of the areas, as we narrow down and begin some of these optimization plans, that frankly we have not been able to do up to this point in time, because we’ve been more focused on how to hold the leases.

So this is a huge opportunity for us, huge in respect to cost, huge in respect to estimated ultimate recovery, and really it captures almost every single aspect of completion and design that you can think of that is being evaluated and reviewed here.

But I’ll also note that there isn’t anything out there in the industry that’s taking place that Chesapeake has not tried or participated in, so even though we might be on a single well pad and away from the best acreage, testing new ideas and continuing to look for ways to improve have been part of our program, it’s just the focus now, as we concentrate in these high quality areas, is going to give us a better return.

Operator

We’ll take our next question from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities

I was hoping you could give us a bit of a look under the hood in the current capital allocation process that you’re going through right now. I think it would be helpful just to hear you compare and contrast it to how it’s being approached today versus maybe how it’s been done at Chesapeake in years past. And then just I’d like to gauge if this is a process that you think will ultimately yield some potentially meaningful swings in how you allocate capital or spread capital around across your core basins in 2014.

Doug Lawler

It’s a great question. The capital allocation process in the past has been primarily directed at how we continue to maintain and hold the lease hold. And while there has been some benefits to that, it has not been the most efficient. And the focus now, with the competitive capital allocation process, is to ensure that all of our dollars are directed at where the best returns are achievable. And that includes a rigorous post-appraisal process. It includes that we will lay rigs down in certain areas if the investment in the wells are not performing as we expected.

And so it’s a very, very strong difference from capital allocation in the past, and I’ll also note that the capital allocation and competitive funding is not going to be based on additional debt instruments that can be secure, whether it be conventional or creative ideas, to execute our program. And so really it’s going to the fundamentals necessary to drive value and focusing on the high quality assets that we have, and we’re excited about it. We think there’s just a tremendous amount of opportunity.

Michael Kelly - Global Hunter Securities

One on the Utica here. The bulk of your activity to date has been focused in Carroll County, but you do have a decent amount of acreage further to the southwest portion of the play, where we’ve seen some really strong projections in terms of IRRs from some of your competitors. Just hoping you could maybe give us a sense of what you expect the difference in returns to be in Carroll County versus maybe what you have in the southwest. I think that would be helpful.

Doug Lawler

We won’t provide that information at this time. As we look forward to providing guidance in 2014, we’ll have some additional asset review that can give you a little more color on that.

Operator

We’ll take our next question from Matt Portillo with TPH.

Matt Portillo - Tudor, Pickering, and Holt

Just a few quick questions for me. I just wanted to confirm, in the prepared remarks, did you mention that LOE would be potentially up on work overs in 2014? And then a second follow up question, just in regards to your longer term LOE initiative, I was curious, from the $0.75/$0.76 per Mcf that you currently have today, what do you view as kind of leading edge LOE or kind of top tier LOE targets from your peers, with this similar type of production mix?

Doug Lawler

The point we were trying to make is that the work over expenses and the opportunities there we also see a significant amount of opportunity there with our base volumes. And the point there is that there is a lot of value in it. And so if we were to see a higher LOE, it’s going to be because we’re capturing greater value with a work over program that’s going to yield good results for us.

And the point there is that as we continue to evaluate our production costs, that’s an important element that we want to capture the greatest amount of value from. What we’re saying, though, is there’s also, in addition to that, significant opportunities. We’ve lowered those costs, and we see opportunities going forward to further reduce those costs.

And so your question, we’re not trying to signal it’s going to be higher. What we’re signaling is we’re going to capture the greatest value we can. And so then to your second question, the plan going forward, what I consider to be top-quartile type of LOE performance, is going to be in the $2 to $3 per BOE, or kind of in that $0.60 range.

So that just gives you a little directional guidance where we are targeting to continue to drive our cost down, and I’m very excited about the team that we’ve got in place that’s looking at all of the areas and whether it’s standardization, knowledge sharing, best practices, with respect to all the different operations in the field that will result in driving those costs down.

Matt Portillo - Tudor, Pickering, and Holt

And then there’s been a big buildup of inventory over time, and I know you guys have done a good job of kind of working that down. I think just kind of skimming through the release, you have about 500 wells left in your backlog. I was hoping that we could maybe get a little more color in terms of where you think that ultimately should move to. What’s an appropriate level of [selling] capital into the ground? I know you guys are trying to reduce that as a bigger strategic initiative.

Doug Lawler

It’s a very good question. And inventory depends on several things. It will depend on the rig count in the area, on infrastructure in the area, and our plan is to optimize that. I’ll just go back to that comment about making sure that we’re not parking capital in the ground that we’re not getting a return on as quickly as possible. So the inventory levels, particularly as we move to more multi-well pads, there will be a base level of inventory that you would expect, as you’ve seen before, with other operators that have been climbing that efficiency curve.

So we’ll continue to see an inventory and what is the exact amount? It’s very dependent on the rig count, it’s dependent on takeaway capacity, but what our commitment is that we’re not going to just park capital in the ground for 9 months, 12 months, 15 months, or greater, without being able to get a return on it. So rather than look at what the optimum level of inventory is, I’d focus that what we’re going to do is get the greatest returns from the investments, and not strand that capital in the ground.

Matt Portillo - Tudor, Pickering, and Holt

And then just my last question, quickly, on the mid-con, you guys you have kind of lumped all of your rigs together. I was hoping that we could get maybe a little bit more clarity in terms of where you may have been decelerating over the last few quarters. And in particular, I just wanted to get an update maybe on your Powder River Basin drilling program.

Doug Lawler

Mid-con is an area that we still are very interested in, and that we like. We’ve reduced some of our activity there as we’ve been working our geologic models. The maturity of the geologic program and the predictability there needs to improve, and so pulling back a little bit to make sure that we’re operationally doing the things we need to do, the technical and geologic work is focused properly. And I think you’ll continue to see the number of rigs in mid-con will be in a range there as we increase and decrease based on our confidence in that program to continue to deliver. So we’ve had several adjustments there.

And then the Powder River, we still are very encouraged about it. And you’ll also see some fluctuation in the rig activity. The issue there involves infrastructure to a certain extent, and back to that comment about not parking capital in the ground for extended periods of time, and also the post-appraisal and work that needs to be done to improve our cost and make sure that we have a good, predictable play there.

But in both areas, we like the opportunities that we have, and believe that they will be very competitive in our portfolio.

Operator

We’ll take our next question from James Sullivan with Alembic Global Advisors.

James Sullivan - Alembic Global Advisors

Just a quick question I had. I wanted to see if I could get a little bit of quantification around your plans on switching over from single well one offs to pad drilling. I apologize if I missed this, but at this time you guys are still doing mostly single wells one offs at this point, in your main place, right?

Doug Lawler

It’s improving as we speak. We’re recognizing the multi-well pad efficiencies and cost reductions. I think it’s important to note that multi-well pads in and of itself does not provide the capital decrease. It’s the synergies and the testing and the optimization that takes place that provides those opportunities. So you obviously benefit from multi-well pads because you don’t have the additional pad location, road construction, all those kind of things that are high level hits, but in and of itself, it’s the synergies in our operations and the greater purchasing power of Chesapeake that we’re looking to capture.

James Sullivan - Alembic Global Advisors

Do you guys give a kind of target percent range in the various plays, for what you’re hoping to be at in 2014? Let’s say if you were running in a generic play 10 rigs, are you guys thinking you might have five of them by this time next year running on pads? Or are you looking to get 100% in most of the major plays?

Doug Lawler

We’re targeting to get to 100%, but as you’d expect, though, as you continue to develop a play you’ll still have some outside of a multi-well pad type of grid. And what we’ve been providing guidance on is that in the past couple of years, we’ve been in the 75% range on single well pads, and going forward in 2014 we expect to flip that to be more 75% on the multi-well pads. So it’s a big shift for us, and we’ve targeted in our presentation some significant capital reductions that we anticipate can be up to 30%.

James Sullivan - Alembic Global Advisors

And then just last one on this topic, as you guys think about doing this, I know you guys are guiding to a sequential decrease in output next quarter. But I assume you’re sort of phasing in this program through your growth areas in the Eagle Ford and elsewhere, Utica. So I assume that the idea is that you don’t go through the big kind of dry spell and then [pops] all in one quarter, or all in one section of time. The idea would be that you would maybe run through the plays. Is that the sort of concept?

Doug Lawler

Yes, I think that’s fair.

James Sullivan - Alembic Global Advisors

And then just last thing, do you guys have any updates on the program in the Niobrara?

Doug Lawler

No, not really, other than what we’ve highlighted there just previously, that we are encouraged by the area, we see a lot of opportunity in it, and we’ll be matching our capital spend with infrastructure and the best returns that we can get in the portfolio.

Operator

We’ll take our final question from Joe Allman with JPMorgan.

Joe Allman - JPMorgan

Doug, going back to Arun’s question, you’re expecting organic production growth in 2014. So are you expecting absolute production growth in 2014 over 2013? Or is it possible that you’d actually have production down in 2014 versus ’13 and still have organic growth?

Doug Lawler

Well, Joe, I’m just going to push you to when we give the guidance, okay?

Joe Allman - JPMorgan

Okay. That’s helpful. Because in the third quarter of ’13, I think production was down 2% over third quarter of ’12, but you indicated you had organic growth of 8%. So I think those numbers are right.

Doug Lawler

That’s right.

Joe Allman - JPMorgan

Okay. And then the midpoint of your new guidance for oil for 2013, the midpoint implies that your fourth quarter oil will drop by about 9,000 barrels a day. So why would we see that drop?

Doug Lawler

Well, as we noted there, we had a couple of things. There are a few things that are entered into it. Partially, the acceleration of activity in Eagle Ford in the third quarter. We’re going to be back at a more normal run rate in the fourth quarter. We benefited from an additional month when we sold some of the assets. We got a little bit of an uplift in the third quarter, because of an additional month that we had those before selling them. And then in October, because some of the weather issues that we had with the heavy rains down there in south Texas, that impacted our production a little bit. So that’s the reason why we see that difference.

Joe Allman - JPMorgan

And then in terms of asset sales, over 2014 you mentioned we might see some asset sales close in the first half of the year. Do you have a target for how much you want to sell, a dollar value or a range? And also, do you have some debt and metric targets that you’re looking at? And on the same topic, in the release you indicated that you want to reduce complexity. Could you talk specifically? What complexity do you want to reduce?

Doug Lawler

I touched on that a couple of questions ago as well. When we talk about complexity, we’re talking about things that leave us with future cash obligations or operating restrictions in ways that can affect how we run our bus, and we want to remove as many of those so we have the most freedom in how we run our business day to day if possible.

In terms of a debt target, I’ve said before that I don’t want to have an absolute debt target. I’ve said recently I don’t want to have an absolute debt target. A couple of years ago, we put out a specific number, which was related to what the company looked like at the time, and the size of our assets at the time.

And so we’ll continue to think about this in terms of ratios and in terms of targets around those ratios, and what I’ll just continue to say there is we intend to be an investment grade company over time. There’s no one ratio that’s going to lead us to that as a measure across the entire balance sheet, and we’ll continue to target metrics that drive us toward investment grade performance.

Joe Allman - JPMorgan

So in terms of the dollar value of asset sales, should we expect at least a couple of billion dollars of asset sales?

Doug Lawler

That’s just going to be totally driven by our ongoing portfolio analysis and value determinations. We could decide to sell less or more than that, and it will be determined by how we view the assets that we have in the portfolio contributing to the longer term goals of production growth rate and shareholder returns.

Joe Allman - JPMorgan

And then just lastly, I just want to clarify your cash flow expectations versus capex in 2014. Do you expect your operating cash flow to match or surpass your total capex, including E&D and lease hold and other capex?

Doug Lawler

We haven’t provided that guidance yet, but just directionally, what we’ve been trying to indicate is that we want to implement and execute with financial discipline that is in that direction.

Joe Allman - JPMorgan

So capex may still be above, but you’re trying to at least get closer than you’ve been in the past.

Doug Lawler

Well, we haven’t provided any of that guidance yet, so you’ll get more on that shortly.

Joe Allman - JPMorgan

What’s the timetable for the new guidance for 2014?

Doug Lawler

What we’ve said here is that we’ll provide that guidance early in the year. So you can look forward to that time.

With that being the last call, I just want to thank everyone for their time. I do believe we had a very strong quarter. I think it’s a foundational quarter to Chesapeake, and I just want to reiterate that the number of initiatives that are in place in this company are significant. I believe we have a significant opportunity to continue to provide differential performance to the investment community, and I’m excited about the opportunities and the talent that resides in the organization to execute that program. So 2014 is going to be an exciting year for us, and we’ll look forward to sharing more with you about that here in the near future.

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