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Chesapeake Energy (NYSE:CHK)

Q4 2013 Earnings Call

February 26, 2014 9:00 am ET

Executives

Gary Clark

Robert Douglas Lawler - Chief Executive Officer, President and Director

Domenic J. Dell'Osso - Chief Financial Officer and Executive Vice President

M. Christopher Doyle - Senior Vice President of Operations

M. Jason Pigott - Senior Vice President of Operations

Analysts

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Michael Kelly - Global Hunter Securities, LLC, Research Division

Scott Hanold - RBC Capital Markets, LLC, Research Division

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Dan McSpirit - BMO Capital Markets Canada

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Operator

Good day, and welcome to the Chesapeake Energy Corporation's Fourth Quarter 2013 Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Mr. Gary Clark. Please go ahead, sir.

Gary Clark

Thank you, David, and good morning, everybody, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2013 full year and fourth quarter.

Hopefully, you've had a chance to review our press release and the investor -- and the updated investor presentation that we posted to our website this morning. During this morning's call, we will be making forward-looking statements which includes 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 will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and the company's SEC filings.

Please recognize that except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

I would next like to introduce the members of management who are on the call with me today: Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Chris Doyle, our Senior Vice President of Operations, Northern Division; Jason Pigott, our Senior Vice President of Operations, Southern Division; and John Reinhart, our Senior Vice President of Operations and Technical Services.

As a reminder, we provided our 2014 outlook and capital program on February 6, and that guidance remains unchanged at this time. Please note that for your convenience, we have attached Schedule A detailing that outlook at the back of today's earnings release. We will next turn to prepared commentary from Doug and Nick, and then we will move to Q&A. Doug?

Robert Douglas Lawler

Thank you, Gary, and good morning. Like Gary said, I hope you had an opportunity to review our 2013 full year and fourth quarter results, which were issued earlier this morning. Just first off, 2013 was a remarkable year of transformation for Chesapeake and one in which a tremendous amount hard work and organizational change took place. I'm extremely proud of the Chesapeake team and the rapid pace that we tackled our challenges and opportunities. Our new strategies of financial discipline and profitable and efficient growth from captured resources have resulted in foundational improvements across the business.

In 2013, we've dramatically improved our capital efficiency, cash cost and operating margins. We've made progress in strengthening our balance sheet and reducing complexity in the company financial statements. And with the release of our 2014 guidance a few weeks ago, we have set the course for another year of continued improvement.

While we still have lots of work to do to achieve our goal of becoming a top-performing E&P company, we completed the necessary steps in 2013 to align our strategy with our world-class assets, motivated and talented employees, and competitive business processes. I'm confident that our 2014 investment program will yield improved returns and increase our high-quality core acreage through further capital efficiencies, downspacing and improved recovery on a per well basis. The 2013 full year and fourth quarter results that we report this morning reflect both our challenges and our opportunities.

Operationally, we had an exceptional year in 2013 with the total production growth of 11% adjusted for asset sales, adjusted oil production growth of 71%, adjusted EBITDA growth of 34% and adjusted earnings per share growth of 146%. I'm particularly proud that our team achieved this growth while running a disciplined capital budget that was 49% less than in 2012.

Despite some severe weather challenges, we finished 2013 on a strong note, with fourth quarter production coming in at approximately 665,000 barrels of oil equivalent per day, which is above the implied midpoint of our 2013 guidance range. This is despite the fact that our production was negatively impacted in the quarter by more than 6,000 barrels of oil equivalent per day associated with heavy rains, flooding and freeze-offs during the fourth quarter in the Mid-Continent and South Texas areas, as well as an additional loss of production at Utica due to the loss of the Natrium gas processing facility for the entire quarter.

While we expect first quarter production will also be slightly impacted by severe winter weather, we look forward to demonstrating the strong production growth capacity of our assets as we move into spring.

On a reported basis, our 2013 full year earnings were $0.73 per fully diluted share, which reflects the impact of $422 million of after-tax charges typically excluded by securities analysts in their earnings estimates. In the earnings release, we have detailed the charges that affected both our earnings per share and operating cash flow. Several of these charges are related to the restructuring of the organization designed to optimize our competitive capabilities and build a solid financial foundation that will enable the company to be successful through the commodity price cycle. Other charges that we recorded are associated with reducing overall leverage, simplifying the balance sheet and capital structure, and preparing the organization for tactical and strategic asset dispositions that we intend to complete, subject to market conditions and value-capture opportunities.

As we enter 2014, we believe that most of the charges related to our organizational restructuring are in the rearview mirror, and we look forward to reporting fewer adjustments to earnings going forward. Nick will discuss the 2013 charges in more detail during his prepared remarks in a few moments.

I'd like to turn to asset sales for a moment and discuss what we are looking to achieve with our disposition program this year. As we noted in the release, year-to-date, the sale of our interest in Chaparral Energy, coupled with expected final receipts from previously closed asset sales and other anticipated non-E&P asset sales, should approximate $1 billion. I'm pleased to note that if completed, these asset sales are expected to have minimal impact on our current 2014 operating cash flow guidance. Beyond these sales, we have planned other tactical and strategic asset dispositions designed to further strengthen our program returns and reduce balance sheet leverage and complexity. The announcement on Monday that we are pursuing a spin-off or sale of our oilfield services division is one example of this type of transaction, and we will share further information as these opportunities mature through the year. Notably, you will see a difference in our 2014 asset dispositions. We will divest assets that are not core to the future of the company so long as we receive appropriate value for them. We no longer need to divest assets to survive or to fund our drilling capital program.

As noted in our 2014 guidance, our investment program is focused on higher rate of return projects, and we are already seeing the results. Drilling and completion cost reductions, coupled with the cycle time improvements, are driving improved returns in our Eagle Ford and Mid-Continent oil plays. We're also seeing the early benefits of cost reductions and efficiency gains in our high-quality gas portfolio. As one example, we've recognized significant cost savings from pad drilling in the Haynesville. Our limited investment program in the Haynesville is expected to yield a 100% rate of return when the minimum volume commitments are considered. Further cost efficiencies of 20% to 25% are expected, resulting in very competitive returns. The current rig activity there will offset our base decline and maintain a fairly uniform production profile for the year. From a strategic perspective, our investment at Haynesville also provides the company with future natural gas marketing optionality, particularly as LNG infrastructure is completed along the Gulf Coast.

This concludes my prepared remarks, and I'll now turn the call over to Nick Dell'Osso, our Chief Financial Officer, and he'll discuss our natural gas differentials and hedging.

Domenic J. Dell'Osso

Thanks, Doug, and good morning. As Gary noted at the outset, we have posted an updated investor presentation on our website this morning to accompany today's earnings release.

I'd like to begin by pointing out some of the significant progress we've made toward improving our balance sheet, which is highlighted on Slide 5 of the presentation on our website.

During 2013, we worked on several areas of our balance sheet capital structure, with the goal of eliminating higher-cost obligations, as well as those obligations that add to the financial complexity of the company or hinder our ability to achieve strategic asset dispositions. Along those lines, you can see the total improvement in our cash, net working capital deficit, net long-term debt and other long-term liability positions improved by $922 million in aggregate. Notably, our unrestricted cash balance rose to $837 million, which together with our undrawn $4 million corporate banking facility and $100 million of availability on our COS credit facility, gave us $4.9 billion of liquidity. Additionally, we eliminated more than $200 million of off-balance-sheet commitments through the repurchase of certain drilling rigs and compressors subject to sale-leaseback transactions, which sparked a strategic initiative to reduce leverage and will facilitate the recently announced sale or spin-off of our oilfield services business. We continued this effort in January and February, and have completed the repurchase of another $135 million of rigs and compressors.

As a reminder, in the second quarter of 2013, we also repurchased $143 million of preferred shares at our CHK Utica subsidiary at an attractive discount to contractual purchase price. The impact of these efforts, as well as other restructuring activities on our fourth quarter and full year results are fully detailed in our press release from this morning. The takeaway is that there were a lot of moving pieces in the fourth quarter and full year 2013, but we believe that we have made substantial progress and have a good plan for reducing financial complexity.

I'd like to briefly discuss our fourth quarter CapEx and unit costs before turning to a discussion of our gas differentials and hedging. Total CapEx for the quarter was approximately $1.65 billion. That consisted of $1.2 billion for drilling and completion activities, $60 million for leaseholds and $390 million for other CapEx. Included in the other CapEx category was $235 million of repurchase of rig compressors that I discussed above.

Production costs in 2013 fourth quarter were $4.62 per boe, up slightly from the third quarter, primarily due to slightly lower production volumes. G&A costs in the fourth quarter were $1.79 per boe, up from $1.71 in the third quarter, due primarily to lower production volumes and the timing of other fees.

Natural gas differentials for the fourth quarter were $1.76 per Mcf and were $1.43 per Mcf for the full year 2013, which was in-line with guidance range of $1.30 to $1.50 per Mcf that we provided on our third quarter release on November 6. Previously, we indicated that there would be an increase in our expected fourth quarter differentials stemming from our minimum volume commitment payments in the Barnett region. I would like to point out that our MVC payments are structured as a look-back such that they are accrued at the end of the year and, hence, only affect the fourth quarter. Coupled with relatively wide basis differentials in the Northeast, our total fourth quarter natural gas differential was $0.30 higher per Mcf than in the third quarter.

Looking ahead to the first quarter of 2014, we expect our gas price differentials will contract significantly due to very strong Northeast pricing, particularly off our current volumes, that we're able to access Manhattan pricing during the extreme cold spells of January and February.

Turning now to hedges. Slide 6 in our presentation sets forth our hedging position as of January 31, 2014. During the month of February, we added some incremental oil and gas hedges for the second, third and fourth quarters of '14 and entered into more material volume hedges covering the first quarter of '15. We also entered into basis hedges covering a significant percentage of our Northeast gas volumes, primarily for the second and third quarters of 2014.

This concludes my remarks. Thank you for your time this morning, and we will now open the call up for questions.

Question-and-Answer Session

Operator

[Operator Instructions] And we'll now take our first question from Neal Dingmann with SunTrust.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Say, Doug, just wondering, obviously, you guys continue to do a lot of drilling and completion efficiencies. Just wondering what you could comment as far as, particular in the Eagle Ford and Utica, how you see those sort of peak rates improving versus the 800 per day in the Eagle Ford and the 7.7 in the Utica? I'm just trying to get a sense of what type of expansion we could see there.

Robert Douglas Lawler

Sure, it's a good question, Neal. I'm very excited about what we have in Eagle Ford, and I think that as we are shifting to almost exclusively multi-well pads, that you're going to see a significant improvement in our opportunity set in Eagle Ford as we drill out our 2014 program. And I say that because of 2 things: one, we're recognizing -- already recognizing and expect to continue to recognize significant reductions in our capital cost, either through synergies of the multi-well pads or just the focus of being -- of our operations there and our supply chain efficiencies; but also, that a lot of the testing to optimize EURs and optimize the IPs, as well as downspacing -- so the number of levers that we have available to us at this point, Neal, are significant. And as I've highlighted before in the past, I personally believe that we have not had the opportunity to focus on all those different levers that lead to further cost reductions and greater EURs. So as a result, I expect during the year that we'll see expansion of what we would call core inventory and higher-quality projects, and would accordingly expect to see increases with EUR and better efficiency.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And a follow-up, Doug, just wondering, in the Utica, still obvious you're having some infrastructure issues that seem to be improving here quite quickly, and you obviously have the tight chokes. How much -- because of those 2 issues, I mean, are we going to see a nice ramp-up soon because of that? Or is that more second half this year?

Robert Douglas Lawler

It's going to be more the second half of this year. Chris may want to add a little further color.

M. Christopher Doyle

Yes, Neal, it's Chris Doyle. So we finished the year strong, as I think I discussed with you. The first quarter, so far, has been marked with some weather issues and bringing Natrium back on, getting into ethane recoveries caused a little bit of hiccups. Volumes are back up. We just set a record for the business unit earlier this week. So I like where we are. I love the trajectory. As we indicated in the slides and I have mentioned before, it's an asset we're looking to expand capacity or double capacity by the end of this year. One thing I might add on the -- on your original question on efficiency and one thing I discussed briefly was really the spot that Chesapeake's at in terms of Utica drilling more wells than anybody else, having more data than anybody else. We are in the pole position in terms of driving value. On the efficiency side, we indicate an average for 2014 of 13 days from spud to rig release. We just finished up our second sub 8-day well, just a massive efficiency that we're seeing in the system. At the same time, we just drilled a lateral that's over 2 miles long. And so we're testing what the right recipe is, but just extremely excited about the efficiency that we see. And as we continue to drive towards value, that's going to help us build that capacity that, again, we see doubling by the end of the year.

Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division

Okay. And then last one, quick one, if I could. Just, Doug, on the gas delivery requirements, I'm just wondering, based on kind of your rig count now and, I guess, what you and Nick have modeled in, the gas differentials, would that account for kind of what you have forecast for the remainder of the year?

Robert Douglas Lawler

Yes. I think it may be important to note though, as well, that as we anticipate continued efficiencies, then that will change as we go through the year. Because obviously, as we continue to improve on our capital -- drilling and completion capital, that'll afford us opportunities for other options.

Operator

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

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

One thing I've been thinking about is as you separate Chesapeake Oilfield Services, you bought back the rigs and compressors in the quarter, are there any more buybacks or changes in rig commitments that we should expect going into that, that'll be outflows of cash from Chesapeake? And then secondarily, how does the Chesapeake Oilfield Services as a separate business, 87% of revenues in the first 9 months of last year with Chesapeake, how much marketing will be done outside of Chesapeake and how does that impact your thoughts on go-forward expenses and CapEx savings that you've had because of that business being inside the company?

Domenic J. Dell'Osso

That's a good question, David. So the first question around how much outflow might we expect, there are a little bit more in the way of rigs and compresses to buy back. I noted in my commentary that we bought back some additional already in January and February. We've got a little bit more to do, although we've made good progress there. So again, we just think about that as something that facilitates the transaction, so we're sort of prefunding that. From a cost perspective -- or first, from a third-party perspective, the business has done a really fantastic job in handling the inbound interest really that has come for services to third parties. We have not actively or aggressively marketed many of these services. We've probably done a little bit more on rigs and had some very good quick success there, as we noted in our release on Monday. So we're pretty eager that the business is going to be well-received by the industry as a top-notch service provider and someone who is competitive and others want to use quickly. There's been other inbound interest. And as wouldn't be surprising, there's inbound interest from some who say, "We are interested in using your services, but we'd be more interested if you were separate." And so that's part of what drives the decision here. So we're eager for all of that to come together. On the cost side, there's a couple of things to think about there. One, we have a bit of EBITDA that we roll up, which reflects the third-party nature of the cost to drill wells. So for example, our working interest partners and then any third-party business they do, that would go away in the sale. And then we also have an add back from CapEx that we would lose. And so those things combined will impact our business somewhat in the short term. But we believe that as we continue to drive efficiencies into our structure and as we continue to lower our well costs through different completion designs, through increased -- or decreased spud-to-TD timing, all of those things above, we feel pretty good about what this will look like pro forma for Chesapeake. We haven't given any of that guidance yet and I don't want to give it this morning until we're more certain [ph] about what it'll look like.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Okay. The net proceed -- or the proceeds of $650 million, is that net of the prefunding of buyback of compressors and the like? Or is that...

Domenic J. Dell'Osso

They're not really apples to apples, David. Those are kind of 2 separate concepts. But to the extent that anything in that required a buyback, then, yes, they are.

David Martin Heikkinen - Heikkinen Energy Advisors, LLC

Okay. And then just specifics on 1Q gas differentials, Nick, you had some thoughts of a dramatic improvement. Can you just tell us where you think you are to date?

Domenic J. Dell'Osso

Yes. So again, we really only have 1 month in the books for the first quarter, but we saw a very significant improvement, as everyone is well aware, in the first quarter in Northeast cash pricing. And we have very good access to some FTE in the Northeast. We have pretty significant capacity on the new Spectra line into New York that obviously yielded a great net back in January and also again in February. So we feel much better about where we are on that front in January and February.

Robert Douglas Lawler

I might just add on top of Nick's comments, that as it was noted in the release on Monday, my personal confidence in coming into the company and being here now about 8 months that -- and Jerry Winchester and the team that make up our oilfield service, not only the leadership, but the execution of that team in our projects, I've been extremely pleased with, and I have great confidence in the them. And as they have been doing a great job for Chesapeake, this is what I believe to be a natural step, particularly given our strategy, for them to expand out now and as we look at these separation alternatives, and really for that organization to continue to grow. And so my confidence in our continued work with them, I see as being very close, and they'll be a big part of our program as we go forward on the service side.

Operator

We'll take our next question from Amir Arif with Stifel.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Just a question first on the Utica, can you just remind us how much carry is left out there? When do you expect that to run out? And after the carry, would that change the capital allocation decision in terms of where you'd like to be spending your money by region?

Robert Douglas Lawler

I think just a quick note, Chris can provide some additional color on that, but we anticipate that carry to go through the year. And I think it's important to note that the focus in concentrated investments that we've had, up to this point in time in the Utica, have been directed at improving the profitability, improving the capital efficiency. And as we go forward, the -- what is building now is a very competitive, high-quality asset in our portfolio. And so the funding levels as we go forward will be driven by how we can capture the greatest value, and Utica will continue to be a significant part of our investment portfolio on a go -- on an ongoing basis.

M. Christopher Doyle

Amir, this Chris Doyle. Just a little bit of additional color. So we ended the year with just under $600 million of carry remaining. We project that given some of the efficiencies, some of the churn that we're seeing, all good stuff, that we could see that in the fourth quarter come off. It's not, as Doug said, going to impact our allocation. We see a world-class asset here and it will -- what will drive the capital allocation is our ability to continue to fill that capacity going forward.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay. And just a quick question on the proved reserves, do you have a breakdown of how much of the PUDs are gas versus oil, or will that just be out in the 10-K?

M. Christopher Doyle

We'll have it all detailed out for you in the 10-K. The -- it's going to very closely approximate the current breakout of what total proved is comprised of, which is basically 73% gas, 27% liquids.

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

Okay. Then just one quick clarification, the $1 billion in proceeds that you're expecting, that does not include the oilfield services, is that correct?

Domenic J. Dell'Osso

I'm sorry, Amir, can you repeat that?

Amir Arif - Stifel, Nicolaus & Company, Incorporated, Research Division

The $1 billion you mentioned in potential proceeds in 2014 from asset sales, that does not include the oilfield services? I just wanted to clarify that.

Domenic J. Dell'Osso

That's correct. Those are all near-term, very kind of actively-and-close-to-completion things.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

I was hoping to get a little bit more color on the gas realization front, and in particular, just interested in how these Barnett contracts work, and how much of the $0.30 decrease in realizations sequentially was due to that versus just low prices in the Northeast?

Domenic J. Dell'Osso

Sure. So the Q4 differentials, just to go back and remind you kind of where we were in our outlook at the end of Q3, we put out a range of $1.30 to $1.50. Included in our assumption for that was the MVC as it came to fruition. So really, the difference that drove where we ended up in the fourth quarter was basis differentials for the most part and it was across, primarily, the Northeast, but there were also impacts in South Texas and in the Haynesville. So we saw basis differentials be an issue really across the company there. The fourth quarter, I guess, sequential, you can do the math on, but it was about a $35 million payment.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Got it, okay. That's helpful. Appreciate that. And then, Doug, just as it pertains to your mandate to really reduce the complexity at Chesapeake, I was just hoping you could talk about what maybe your major priorities are here? We've seen you guys buy back some of the preferred shares in the Utica L.L.C., maybe you could talk about that, potentially the VPP front. You now have the announcement on the oilfield service side, so maybe what the major priorities are here?

Robert Douglas Lawler

You bet, Mike. I appreciate you asking. The 2 real significant priorities that are in line with our strategy is to continue to drive greater efficiency into our investment program. And that is not just on a reducing capital intensity side, but also working the denominator and improving our EURs. And then also, on the exploitation side continuing to build and expand our core areas. I have very, very strong confidence in the initial results we're seeing with some of our pad drilling points to what I believe will be very, very good, solid core expansion, which will result in greater value to our shareholders. And then also in that same -- with that priority, comes the cash cost management in reducing our cash costs, we've seen significant improvement in 2013 versus 2012. And then as you focus on what guidance we've provided, Mike, for 2014, we're seeing continued improvements in our G&A costs, as well as our production costs. And I'm very excited about that and look for those margins to continue to improve. And with our capital efficiencies and those cash cost improvements, it's just going to provide us a lot more optionality. The second thing, and equally as important to me as a priority, is this focus on how we continue to restore and build greater strength of our balance sheet. And the asset sales that we're looking at and the things that we're considering for 2014 are a direct reflection of a competitive capital allocation process, where do we see our funding going to provide top quartile strategic growth metrics for Chesapeake. As you all are aware, some of our efficiencies and performance metrics have not been as high as we believe, internally, they are capable of being. And we have the assets, we have the confidence in these assets, we have the talent in this organization in our employee base, to drive top quartile results. And so, we believe very strongly that the asset base we have, some assets are going to get funding and some won't. And so either based on maturity or how they compete for capital going forward, that's where we're going to be focused in our disposition program.

Operator

We'll go to our next question, Scott Hanold with RBC Capital Markets.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Could I clarify something that you mentioned, to make sure I understood it correctly? Did you say that post 2014, you don't see any need to sell additional assets, is that correct?

Robert Douglas Lawler

Well, the -- no, that's not what I intended to represent. It's going to all be based on value and how we can optimize value for our shareholders. The key is, as we look at our portfolio and what's contributing to the strategic growth metrics of the company and how we get to be a top performer is what those priorities and strategies directed. We continue -- I believe we'll continue to see opportunities to improve. And in some cases, it may be add to our asset base to provide greater value for our shareholders. So we've got a very heavy, focused 2014 program that -- with some of the liabilities and the complexity that is provided on our balance sheet that we're looking to improve and will improve in 2014, and some of that could extend into 2015.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay, okay. And so when you step back and look, is there like a target debt metric that we should think about? Or where do we want that to go for you guys to feel comfortable? And if you did find an opportunity to add an asset, like you just mentioned, how would that -- what would that funding look like? Is equity off the table or is that still an option available to you all?

Domenic J. Dell'Osso

Yes, Scott. We've continued to say and will continue to say that equity is not something we expect to pursue. I've also said several times, and I'll stand by, that I don't want to give anybody a hard and fast 1-debt metric. There's a lot of metrics we look at across our portfolio of our balance sheet. And what I will continue to say, though, is that we want to be a firmly investment-grade credit. And so we have some distance to travel to get there, but we feel like we have a plan in place to accomplish it. The 2 things are so closely aligned where Doug talks about wanting to have a more competitive set of assets, assets that are focused on where we can generate the highest rates of return and the assets that demand the capital from within a competitive capital allocation process, as well as then a desire to improve our balance sheet. Given the breadth of our portfolio, as you think about an appropriately-sized capital program, there's a number of assets that won't compete for capital. There's a number of assets where we can't be as efficient in operating it as somebody else can because they're more cored up in the area, because it's more of their primary area or it's just something that would be more attractive in their portfolio relative to ours. As a result of that, there's going to continue to be assets that, strategically, we think we ought to sell. Those 2 things are perfectly connected to each other and they all yield something that allows us to greatly improve our balance sheet. So we feel really good about where we're headed with all of these things.

Scott Hanold - RBC Capital Markets, LLC, Research Division

When you look at the E&P assets, is there any like, [indiscernible] are there any assets there that are just too good that you don't want to give up? Or when you're looking to move Chesapeake down this road to get to more capital efficiency and investment-grade, are you just going to do what makes sense and do what needs to be done?

Robert Douglas Lawler

Well, it's going to all be directed at how we accomplish the greatest value for the company and for our shareholders. And I'll tell you, though, when you look at the improving efficiencies, what I see out of the operating teams is it's going to be ever increasingly difficult to make those decisions because they're continuing to drive greater and greater value. And -- but we know we need to continue to make strides in that direction. And obviously, the liquid plays have a major role in our portfolio, but we also like the significant strength that exists in our gas portfolio on a go-forward basis. So it really is just going to be based on what assets are going to continue to compete for funding and how can we optimize the strategic metrics to drive us to that top quartile.

Scott Hanold - RBC Capital Markets, LLC, Research Division

Okay. And -- okay. No, that's fair enough. And one last one quickly, if I could. You mentioned weather impacts a couple of times and kind of talked around various areas that might have had some impacts. Could you be a little bit more specific? It sounds like maybe some in the Utica. And when you say the Mid-Con, is that the Mississippi and that, that had some impact in? On a relative basis, where was it the heaviest?

Robert Douglas Lawler

Sure, we can provide that for you.

M. Jason Pigott

This is Jason. Really, the 2 impacts in there, on a net basis, fairly equally impacted were the Mid-Con. Again, it was impacted by a lot of freezing weather. Again, it's one of our oil-producing areas. The challenge there is you get some snow and ice on the roads, it makes it difficult to pick up those oil loads sometimes. The other was South Texas, which happened a little bit earlier in that quarter. We had a significant rain event there that caused some flooding, washed out some roads. We had one of our stimulation crews kind of trapped on a location there that prevented some of the wells coming on as well. So those are the 2 major events, kind of equally impacted us in each area.

M. Christopher Doyle

Scott, in the Uticas, I mentioned before, we had some weather in January and February, not surprisingly given the area. The other impact was just the start up -- back start-up of Natrium and getting into ethane recovery flowing into Kensington. We continue to work those issues out. Volumes are back up. These are not lost volumes, these are deferred volumes. And so we really look forward to continuing to see the growth out of that play.

Operator

We'll go to our next question, Matt Portillo with TPH.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Just a few quick questions for me, I was wondering if you could give us an update on where your Utica well costs stand at the moment? And then you've previously talked about kind of a 5- to 10 Bcf-type curve. I was wondering if you could provide any more color on how the wells have been performing versus that previous metric.

M. Christopher Doyle

Yes, Matt, this is Chris Doyle. I think we'll have a chance in May to get into the details, but let me just give you a high-level color. What we see in well costs, again, is we're doing things out there that nobody else can do. We're seeing well costs in the 7s, low-7s going forward. And most recently, as I mentioned, some sub 8-day wells. Just tremendous value, tremendous efficiency in the system. Where we are today, though, is not only attacking the cost side, but attacking that EUR side, and looking for completion efficiencies, tighter cluster spacing, all those things that will drive our EURs. We're firmly in that guidance range of the type curve that we provided before and honestly looking to push outside the top of that as we continue to potentially increase well costs, but drive for a better solution and more value in that asset. And I said I think we'll have a chance and look forward to the chance to share more details with not only Utica, but across the play as we're doing many of the same things across our portfolio in May.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Great. And then just a quick follow-up question to a previous question on the OFS business. I was wondering if you could guys provide kind of a range on where the EBITDA margin stands at the moment?

Domenic J. Dell'Osso

We're going to stay away from specifics like that for oilfield services, and be able to talk to you more about it as we get closer.

Matthew Portillo - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay, great. And then my last question, just on the Haynesville. Looking through the presentation, you guys, I think, are highlighting 80-acre spacing. We've seen some of the recent -- your industry peers moving out wider on that in regards to potential interference on the wells. I wanted to just see how you guys are thinking about the well performance to date and how you guys are thinking about spacing on a go-forward basis?

M. Jason Pigott

This is Jason, again. We're actually developing most of our pads in the Haynesville on 160-acre spacing right now. Again, it's one of the things that we have an advantage of coming in later with the pad drilling to be able to look at our peers, see what some of -- they have done. Again, we have seen, in some instances like you suggest, that they have over-downspaced there, so it's something that we're looking at. We've got a team that's really focused on looking at it now and looking at rock quality, doing some numerical simulations, looking at their stimulation designs there. So we've got a rigorous program kind of in place to find out what the right spacing is there. We gave ourselves some opportunity to come in and infill if we feel like it's necessary on that area. Again, one of the things we really highlight is our cost control there as well. We've seen a significant improvement the last 3 or 4 wells as we've got a supply chain management system put in place. We've also created new completions teams that are 100% focused on the completions from our wells, versus a base team that's focused on minimizing our base declines. So they have really had a major impact this last quarter. I think, again, we're estimating we could be down as low as 7.8 is kind of what's in here, but we're starting to hit that already. And I see us being able to beat in the future as this system continues to get optimized.

Operator

And we'll take our next question from Jason Wangler with Wunderlich Securities.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

Curious, out in the Eagle Ford there's been some talk the last couple of days or week or so about the -- kind of the western Eagle Ford, and I know you guys have some acreage out that way. Can you comment maybe on what you're seeing out in that area and how you're looking at that going forward?

M. Jason Pigott

Yes. We are -- again, we're excited about our acreage in the Western Eagle Ford. Again, one of our competitors had kind of had some negative results. But we watch our competition pretty well. We've got some -- we've got higher permeability of rock in some of our Western Eagle Ford acreage. We're also, again, on less dense spacing there. We're kind of drilling more at the 660-foot versus some of the peers who are more like 450-foot spacing. So this is another chance where, again, transitioning to the pad drilling a little bit slower has allowed us to watch what some of the competition is doing. So we're getting really good wells out there and excited about that program. And don't really -- we're not really pulling back from it right now.

Jason A. Wangler - Wunderlich Securities Inc., Research Division

That's helpful. And just curious on the Utica, obviously, with the big ramp in NGLs for the year as a company, what are you seeing? Is the Utica going to be one of those pretty big drivers? Do you have an idea of what the mix is going to be as you get it to less of a constrained situation throughout the year?

M. Christopher Doyle

Yes, Jason, this is Chris Doyle. Utica will be one of the drivers. We've got the ATEX commitment that I'm sure you're familiar with. As we fill that, both from Utica volumes and Marcellus South volumes, that's going to facilitate that ramp in NGLs. I'll tell you, though, it's not a static equation here. We look at NGL pricing and we'll continue to make the best value decision for the company. But, yes, those 2 assets, Utica and Marcellus, will be what's driving the NGL ramp for the company in '14.

Operator

We'll take our next question from Dan McSpirit with BMO Capital Markets.

Dan McSpirit - BMO Capital Markets Canada

What is the economic limit or breakeven natural gas price for the Haynesville Shale operations? And can you also qualify, or quantify rather, the midstream commitments in terms of volumes in term for that operation?

Robert Douglas Lawler

I'll make an initial comment, and then Jason can provide a little bit more color on it, Dan. The -- while the breakeven prices is often the attractive metric that we go to, when you can crush $1 million or $2 million out of your well cost, that driver is huge in our economics. And the focus on the efficiencies and testing some of the new strategies there to optimize our EURs, and capitalizing on the supply chain, as Jason noted earlier, it's going to drive that breakeven price down considerably. And I think it's also important to note that, as an industry, what took place in the Haynesville was not necessarily a positive thing in the past 3 of 5 years, and the amount of capital that was invested and what, as a result, we saw in the gas market. But our focus in the Haynesville is almost surgical and precise, and we know exactly what we need to do to drive the cost down. We're recognizing it, as we speak. And the competitiveness in terms of not only in our portfolio and what it can do for us, is -- also has longer-term implications as you have a very, very strong high-quality asset capable of providing gas not only to the domestic market, but more importantly, to a global market as the LNG infrastructure gets built out along the Gulf Coast. So we think that the opportunity there, rather than looking at what the breakeven price is, I prefer to focus on the fact that the work that's being done to drive the cost is immediate value to the company. And Jason, would you provide any more color there?

M. Jason Pigott

Yes, I don't have too much to add there. Again, I just remember when we first came in, we did an analysis where $1 million was equivalent of $1 per Mcf in gas price. So again, as we continue to drive costs down, the breakeven point goes down further. Again, we're really excited about the program out there, the optimization that we're making, so hesitate to put a breakeven price on there. One of the other things we're doing is they've allowed some new rules to drill cross-unit laterals, which allows us to complete more feet per well. So that's another thing that we're continuing to look out there and try to optimize on as being able to maximize our lateral length in the play, which is another factor that, again, improves overall well economics.

Dan McSpirit - BMO Capital Markets Canada

Okay, great. And then just turning to volume commitments, minimum volume commitments, as part of the last question, can you quantify for us what amount of production is obligated and in what operating areas, remembering you mentioned the Barnett Shale in your prepared remarks?

Domenic J. Dell'Osso

I'm sorry, can you repeat that?

Dan McSpirit - BMO Capital Markets Canada

Yes, just on the minimum volume commitments, company-wide, can you quantify the amount of production that is obligated and in what operating areas, just remembering that you had mentioned the Barnett Shale as one example in your prepared remarks?

Domenic J. Dell'Osso

Yes, that's actually something we're looking towards providing probably a little bit more detail on in our Analyst Day. We did give you in our outlook a breakout of what we were forecasting as minimum volume commitments for both the Barnett and the Haynesville separately. So we're looking to doing some additional breakout of that and other FTE at our Analyst Day. But overall, again, I'll repeat what we've been saying here, those are the 2 minimum volume commitments that we're focused on, and then the rest of it, we're actively managing. And we need to get our gas to market, so we feel good about that overall portfolio of positions.

Operator

[Operator Instructions] We'll take our next question from Mike Kelly with Global Hunter Securities.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Guys, just a follow up on the Eagle Ford. Jason asked about your Western acreage there, and I'll be specific about it. We've got 2 updates earlier this week and last week on reserve revisions. And to be very specific, SM's Area-1 acreage took a pretty big hit. Just wanted to hear your take on how your acreage is around theirs there? And if there's the risk that there's a potential negative revision in your future as well?

M. Jason Pigott

No. Again, we've just done our on fourth quarter reserves and I looked at Eagle Ford overall, and we had positive performance improvements for that acreage. Again, we tend to book a little bit conservatively. But again, I think the things that if you -- again, all of the Eagle Ford is not uniform as far as rock quality. And so again, we've mapped higher permeability streaks underneath our acreage. And again, if you looked immediately across the lease line, again, our estimate is that St. Mary's averaged about 450-foot spacing versus our 660. So again, we've got -- if you have interference and things like that, that can negatively impact performance as well as the rock quality. So again, we pooled our wells versus theirs, and our wells significantly outperform theirs based on the data that I've got.

Operator

[Operator Instructions] We'll take our next question from Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So just a quick question on oilfield services. Would you prefer a sale versus a spin, because the sale is going to get you, actually, some cash? And if you were to go down the route of a spin, like what does that do for you strategically and structurally and in terms of simplifying just the company as a whole?

Robert Douglas Lawler

It's a really good question, Joe, one that at this point, we probably are not going to be able to give you a whole lot more color on today. I'll tell you that the driver there is to capture the greatest amount of value that we can. And we think that both options, a spin or a sale, have pros and cons associated with them. But it really is going to be on a value basis. And as we proceed here with our consideration of strategic alternatives in the next few weeks and months, it will -- we'll be able to provide more color. Nick, do you want to add to that?

Domenic J. Dell'Osso

I think that's right. I mean, there's value components to each of those paths and we'll continue to look at what will provide the best value. As you think about what it will do for us structurally and what are the benefits, look, we are focusing all of our teams across the company on delivering the best value in our E&P operations and driving costs out of our system. And as a result of that, when you're managing 2 separate businesses, there's going to be some excess cost in the system, we think, sort of generally as you manage 2 very separate processes. And we think that the focus that comes to our overall business and to our teams of being a pure E&P company is a big improvement to us, and we think that there are further efficiencies that we can drive through our back-office processes, et cetera, to deliver more value. The other thing I would add there, Joe, is that there are balance sheet improvements that come through this, whether it's a spin or a sale, and we don't really have -- need the cash right away. And so a spin can be a really good answer here.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's helpful. And then I think Mike Kelly was -- when the first time he got on, I think, he was asking, if I'm not mistaken, just about the complexity and you're -- the specific steps you're going to take to reduce complexity. So could -- rather than just talk about sort of your key strategic objectives, could you specifically talk about like what are the things that you think you need to do over the next year or 2 or 3 to reduce the complexity of the company?

Robert Douglas Lawler

Well, that's a great question, Joe. And I think that, as you are very keenly aware and the other analysts are aware, the balance sheet -- when we talk about complexity and all of the different financial arrangements, the commitments, the obligations, the different instruments that we've used for essentially to fund for debt or to fund our program, we just need to clean those things up. We are an -- we are going to be an efficient, well-run E&P company. And the strategic metrics that we're trying to accomplish are -- we're not trying to be in the middle of the pack. We believe we have the assets. We believe we have the people and the capability to be a top-performing E&P company. And what I really love is the alignment of the strategy and the things that we're seeing so far. As we're working through some of these challenges, we still see significant opportunity. But these -- a lot of these residual legacy balance sheet issues, what I'm very pleased about is that we have the capability to -- with reduced capital, to continue to demonstrate growth, and we expect that to continue to improve. And we also have the ability, with the balance sheet and with the assets that we have, to improve and fix our balance sheet. And so without giving too many specifics on it, I think that just in general, you are very aware, as everyone else is, that we just have a lot of noise on the balance sheet that needs to be improved so our story becomes simpler, better to understand. And the clarity that we provide to you and the investment community is how we can add more value for our shareholders. And so everything that we've been working on in the past part of the year in 2013, and everything we're focused on now, is driven in that direction.

Well, I think we're at the top of the hour, operator. And I just want to thank everyone for tuning in and for the questions. If anyone has any follow-up questions, I would just ask you to, please, reach out to Gary. We look forward to continuing to share the progress of the company in the next coming quarters and in 2014. And we're also very excited to share more asset detail in how we're continuing to drive additional value, as well as update on the status and progress with our balance sheet efforts to improve at our Analyst Day on May 16 here in Oklahoma City.

So with that, that concludes our call. Thank you, all, very much.

Operator

Thank you. That does conclude today's conference. We thank you for your participation.

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