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Chesapeake Energy Corporation (NYSE:CHK)

Q1 2013 Earnings Conference Call

May 1, 2013 9:00 am ET

Executives

Steven C. Dixon – Acting Chief Executive Officer and Chief Operating Officer

Jeffrey A. Fisher – Executive Vice President – Production

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

Jeffrey L. Mobley – SVP, IR and Research

Analysts

David Kistler – Simmons & Company

Arun Jayaram – Credit Suisse

Brian Singer – Goldman Sachs

David Tameron – Wells Fargo

Doug Leggate – Bank of America Merrill Lynch

Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc

Neal Dingmann – SunTrust Robinson Humphrey

Jeff Robertson – Barclays

Charles A. Meade – Johnson Rice & Company L.L.C

Biju Perincheril – Jefferies & Company

Robert Morris – Citigroup

Operator

Good day everyone, welcome to the Chesapeake Energy Corporation Q1 2013 Earnings Conference. Today's call is being recorded.

At this time for opening remarks, I'd like to turn things over to Mr. Jeff Mobley. Please go ahead, sir.

Jeffrey L. Mobley

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

During the course of this call, our commentary will include forward-looking statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements. Please note that there are a number of factors that could cause our actual results to differ materially from such forward-looking statements. Additional information concerning these factors is available on our earnings release and the Company’s SEC filings. We also refer to certain non-GAAP financial measures and we encourage you to read the full disclosure and GAAP reconciliations located on our website in this morning’s press release.

I would next like to introduce the members of management here on the call with me today; Steve Dixon, our acting Chief Executive Officer; Nick Dell’Osso, our Chief Financial Officer; and Jeff Fisher, our Executive Vice President of Production and Gary Clark, our Vice President of Investor Relations and Research. We’ll begin with prepared commentary from Steve, Nick and Jeff and then we will move to Q&A. Steve?

Steven C. Dixon

Thanks Jeff. Good morning everyone and thanks for attending this conference call. I’m pleased to report that Chesapeake is off to a strong start in 2013. We’re beginning to see the benefits of our operational strategy shift from identifying and capturing new assets to developing our extensive existing assets as we enter a new era of shareholder value realization. Our operational focus on the core of the core is enabling our drilling program to increasingly target the best reservoir rock in each of our key plays. We’re capitalizing on pad drilling efficiencies wherever possible and leveraging our substantial investments in roads, well pads, gathering lines, and compression and processing facilities. As a result, we are generating more efficient production growth, stronger cash flow and better returns on capital.

We continue to make substantial progress, delivering on four key initiatives, developing our existing asset, heightening our operational excellence, increasing capital efficiency and focusing on financial discipline. Nick Dell’Osso and Jeff Fisher will provide additional details on these important initiatives. But first I would like to highlight several significant accomplishments. Our adjusted net income per share of $0.30 rose 67% from the year ago first quarter. Our total first quarter net production grew 9% year-over-year and 1% sequentially to 4 bcfe per day. Our liquids production mix increased to 24% of our total production of this 19% a year ago.

Our combined production and G&A cost decreased 26% year-over-year to $1.11 per mcfe. Our first quarter upstream CapEx was at or below budget. We have signed or closed on $2 billion of asset sales towards our $4 billion to $7 billion target, we have a number of other E&P and midstream divestitures in advanced stages of negotiation, which will share [we want] definitive agreements at least in the next few weeks or months.

In quarter end our liquidity was more than $3.2 billion through cash are available revolver capacity. Our safety program recently achieved an industry standard of excellence with our E&P segments surpassing more than 1.5 million man hours without a recordable injury. And we’ve implemented substantial corporate governance and executive compensation measures to further strengthen the company by enhancing oversight and accountability.

We’ve received variable court determinations dismissing multiple shareholder losses including the dismissal of class action concerning at July 2008 note offering. And the dismissal of reported class action concerning issues that was subject to considerable press coverage in late spring in summer of 2012. Lastly, but importantly natural gas markets have improved materially in the last few months and signs of long-term demand growth are beginning to materialize across multiple market segments, we believe this does two important things for Chesapeake, it improved the profitability and a mixed gassy assets in our portfolio more valuable and more attractive to buyers in the E&P market.

In summary, we are solidly on track in gaining strength as we look ahead to the second quarter and the back half of this year. I’d next like to discuss the progress of our leadership transition and Chesapeake strategic plans for 2013 and beyond.

As disclosed on April 1, Chesapeake established a new three-person office of the Chairman. That office consists of myself, Archie Dunham, our Independent Non-Executive Chairman, and Nick Dell'Osso, our CFO.

The leadership transition process has been smooth and effective. As acting CEO, I greatly appreciate Archie’s and Nick’s support as well as the support and assistance of our senior management team and our 12,000 employees.

Our management team and the Board of Directors are excited about the Company’s business strategy and objectives that we’ve outlined. The path forward for Chesapeake and its shareholders will be very different from our past. This is a very important development for our company. Recognize though, that this strategy transition is a natural evolution design to capitalize on the durable competitive advantages created by Chesapeake during the unconventional resource revolution of the past decade. We believe the results of this strategy shift have begun to be reflected in our operational results over the past three quarters, and we expect them to continue to bear fruit for many years to come.

Our asset teams are focused on operational excellence, which for us means a sharp focus on safety, regulatory compliance, environmental stewardship, process improvement, cycle time reduction, and leveraging economies of scale. I’m confident that our execution of this strategy quarter-after-quarter will deliver material improvements to shareholder returns.

Turning briefly to our financial strategy, we are optimizing our portfolio and allocating approximately 85% of our drilling completion capital to liquids plays in 2013. We are largely deferring drilling on dry gas plays until natural gas prices recover enough to generate competitive returns with our liquids plays. We’re diligently working to reduce and eventually eliminate our funding gap, which we now estimate will be approximately $3.5 billion in 2013. Achieving a low end of our asset sales target of $4 billion will enable us to fully fund our 2013 investments and maintain long-term debt at or below year-end 2012 levels.

Asset sales above $4 billion will enable us to achieve approximately all of our long-term debt reduction objectives. We are committed to maintaining financial discipline, while reducing the financial risk and complexity.

In conclusion, I would like to remind you that we own extraordinary assets in the top resource plays in America. We own integrated oilfield service assets that help us sustain the most active drilling program in the nation and help drive safety and efficiencies throughout our operations while also insulating against future oilfield service cost inflation.

And lastly and most importantly, we have an exceptionally talented and dedicated workforce that has collectively drilled more horizontal wells that any company in the industry. In my 22 years with Chesapeake, I have never been more excited and energized about our future. The era of shareholder value realization at Chesapeake is now underway. I look forward to leading this new era. Thank you again for joining us on this call.

I will now turn it over to Nick for his comments on the quarter.

Domenic J. Dell'Osso Jr.

Good morning and thanks, Steve. As Steve mentioned, our strong first quarter results demonstrated the successful execution of our ongoing strategic initiatives. Adjusted earnings per share in the first quarter were $0.30, which was up from $0.26 in the fourth quarter and $0.18 per share in the 2012 first quarter. Adjusted EBITDA also saw an uptick in the quarter to $1.13 billion, up from $1.09 billion in the fourth quarter and $838 million in the 2012 first quarter.

I am pleased to report that our first quarter oil production of $103,100 barrels per day was once again ahead of plan and was up 6% sequentially and 56% year-over-year. This growth was primarily driven by strong contributions from the Eagle Ford and Greater Anadarko Basin plays, which Jeff Fisher will discuss in more detail. NGL production came in at approximately 54,300 barrels per day, up 8% sequentially and 14% year-over-year.

As a result of better than expected performance in our Eagle Ford and Greater Anadarko Basin plays, we are increasing our overall 2013 oil production guidance by 1 million barrels to a new range of 37 million to 39 million barrels. Conversely as we noted on our last conference call, our line of sight is lower for NGL production this year, and we are reducing our 2013 NGL production guidance by 1 million barrels to between 23 million and 25 million barrels. This is primarily due to natural gas processing infrastructure delays in Utica and Niobrara, as well as liquids rig allocation changes to more oily plays in the Anadarko Basin. We are also raising our 2013 natural gas production guidance to a range of 1.06 to 1.09 Tcf, which is an increase of 2% versus the prior range. This is primarily due to stronger than expected natural gas production from our Marcellus play. These guidance changes are detailed on page 16 of our press release under Schedule A.

Turning now to capital expenditures. We operated an average of 83 rigs in the quarter and invested approximately $1.5 billion in drilling and completions, which is a run rate consistent with the $6 billion midpoint of our 2013 guidance. Net lease hold expenditures on unproved properties were $45 million, putting this on track to be in line or below $400 million budget for the year.

Our CapEx was approximately -- other CapEx was approximately $345 million, which includes $62 million for CapEx spends on the two remaining midstream systems that we are divesting. We anticipate recovery of this CapEx as these assets are sold. The other CapEx also include $69 million for final delivery of two pressure pumping spreads and 3 rigs that were ordered in early 2012. There are three additional rigs to be received during this quarter after which we have no additional plans for material growth of our oilfield services assets.

Consequently, other CapEx for 2013 is heavily front-end loaded and will decline substantially in the second, third, and fourth quarters. I’ll further note that as a result of an expected decline in leasehold, midstream, oilfield services and other CapEx versus last year and further decreases going forward, 80% of our total CapEx will be spent on drilling and completion activities in 2013 versus an average of just 50% over the last three years.

We believe this capital allocation trend will be more pronounced in 2014 when we plan to dedicate nearly 90% of our total CapEx to drilling and completion activities. We are now clearing seeing the benefits of our past investments in leasehold, oilfield services, and other assets which no longer require significant capital investment.

Production cost during the quarter averaged $0.86 per Mcfe which is down 18% from $1.05 per Mcfe in the year-ago quarter. We continue to make good progress on lowering G&A expenses as well, which averaged $0.25 per Mcfe during the first quarter, down 29% from $0.35 per Mcfe in the year-ago quarter. Per unit production costs and G&A were both up slightly versus fourth quarter of 2012, which as we noted on our last call contained several one-time items.

I’m pleased to announce the reduction in our 2013 per unit production cost and G&A guidance ranges for the second quarter in a row. We now project that production cost will range from $0.85 to $0.90 per Mcfe for the year, down $0.05 per Mcfe versus prior guidance. We projected G&A expenses will range from $0.30 to $0.35 per Mcfe, down $0.04 per Mcfe per prior guidance. These decreases in expense guidance amount to an approximate $100 million expected improvement to our 2013 operating cash flow.

I’d now like to address progress with regard to asset sales. We signed or closed $2 billion of asset sales year-to-date segmented as follows; in the first quarter, we’ve received $366 million of cash proceeds on sales including $45 million of hold backs received from last year’s Permian sale. In Q2, thus far we have received cash proceeds of $262 million on sales, including $40 million of hold backs from last year’s Permian sale. And lastly, we have signed purchase and sale agreements on $1.4 billion of asset sales that are not yet closed. The largest portion of this is our Mississippi Lime transaction with Sinopec, which we anticipate closing before the end of the second quarter and also includes the sale of midstream assets in the Mississippi Lime play to SemGroup which was announced by the buyer this morning. In addition, we anticipate signing agreements to sell our Northern Eagle Ford and remaining midstream assets during the second quarter.

Turning to the balance sheet; on March 31, we had a total debt balance of $13.4 billion, including $832 million drawn on our corporate revolver. On April 1, we’ve completed a $2.3 billion senior note offering at the lowest interest rate in the company history. As a reminder, the use of proceeds for this offering is solely for refinancing and will not be used for general corporate purposes. Accordingly on April 15, we used a portion of the proceeds to complete tender offers for approximately $594 million of debt, which represents portions of our outstanding 2013 and 2018 nets. As an insight, I would like point out that our credit default swaps reported yesterday at 310 basis points which we believe is the lowest level since August of 2011. We also paid off the balance of our corporate revolver subsequent to March 31.

Next, I would like to address our hedge position for 2013 and 2014. In 2013, we have put in place downside protection on approximately 78% of our projected natural gas production at an average price of $3.72 per Mcf. On the oil side, we have downside protection on roughly 88% of our expected volumes at an average price of $95.43 per barrel. For 2014, we used recent strength in natural gas prices to hedge approximately 13% of our projected gas production at $4.33 per Mcf. We have also put in place 2014 oil hedges that project our downside on approximately 40% of our projected production at an average price of $93.63 per barrel, which is well above the current NYMEX strip.

With that I’d like to turn the call over to Jeff Fisher to discuss operations in more detail.

Jeffrey A. Fisher

Thank you, Nick. We are continuing to see tangible efficiency gains across our key plays from increased pad drilling, reduced cycle times and targeting the best reservoirs in the core of the core of our acreage. Before I get to the discussion of our specific play performance, let me describe a number of operational initiatives that highlight our commitment to project execution, capital efficiency and safety. To augment our more focused development programs, we are leveraging automation systems and enhanced work processes to improve operational efficiencies and drive down the cost. As an example, we have developed a high tech drilling operation center in Oklahoma City, where technicians, monitor and manage drilling performance in the steering of horizontal wells, real time 24/7.

In addition to better managing our staff resources, we are realizing better drilling performance, improved logistics and lower cost. This center has been expanded to incorporate real time monitoring of pressure pumping and production operations where we expect to see similar benefits. Our teams have also been applying lean manufacturing concepts to improve project execution in the field. As an example, these practices have led to a revamp of our rig move processes in which we have been able to reduce cycle times by up to 45%.

We’re expanding these practices to enhance many other aspects of our operations and we look forward to continuing improvement. And importantly, these programs also improved safety performance and as Steve noted, we are very pleased with our progress on that front. In addition to improving capital efficiency going forward, these initiatives are also contributing to the lower production cost performance that Nick discussed.

I would now like to discuss our operations in four key plays: the Eagle Ford, the Utica, the Greater Anadarko Basin and the Marcellus. As Nick noted in his remarks, we’re increasing our overall 2013 oil production guidance by 1 million barrels. This is largely attributable to outstanding results in the Eagle Ford, where we are drilling longer laterals, achieving better than expected well performance, and benefitting from increased gathering system and processing capacity.

During the first quarter, we drilled 91 new wells while bringing online a 111 wells at average peak rates of 950 boe per day. As infrastructure continues to develop, we remain on plan to reduce excess well inventory by drilling a total of 300 wells, while bringing online approximately 400 wells to sales by year-end. First quarter liquids production in the Eagle Ford averaged 61,600 barrels per day. This was an increase of 44,100 barrels per day, or 251% year-over-year, and an increase of 10,800 barrels per day or 21% sequentially from the fourth quarter.

To remind everybody, we are targeting a year-end 2013 exit rate of approximately 71,000 barrels of liquids per day, and a total production exit rate of 92,000 boe per day net from the Eagle Ford. On average, Eagle Ford’s spud-to-spud cycle time during the first quarter was 18 days, down 28% year-over-year. We executed 30% more frac stages versus the prior quarter and we continue to make progress at our completion practices. Longer term, we’re targeting an average spud-to-spud cycle time of approximately 30 days in full pad development mode and an average completed well cost of $6.5 million for a 6300 foot lateral.

In the second half of 2013, we anticipate that 50% of our Eagle Ford wells will be drilled on multi well pads versus only 15% during the first half of 2012. Looking ahead 2014, we believe more than 75% of our wells in this play will be drilled on multi-well pads. Based on an assessment of more than 600 wells drilled and brought online to date in our core Eagle Ford, we conservatively estimate that our average type well across the core will yield a EUR of 570,000 boe.

Assuming an average well cost of $6.5 million, we expect to generate pre-tax rates return ranging from 30% to 80%. Pro forma for the sale of our Northern Eagle Ford assets, we conservatively estimate a drilling inventory of more than 3500 high quality development locations, representing an inventory of more than 10 years based on current activity levels.

In the Utica play, we have drilled 249 wells of which 66 are completed and flowing to sales as of first quarter. Production is relatively flat versus our operations update call one-month ago as the new processing infrastructure that we spoke of has not yet come online. We now expect the next step change in our Utica production will occur closer to mid year that are maintaining our year end exist rate target of 330 million cubic feet equivalent per day net.

In that April 1 update call, we discussed the impressive results we have seen in our Scott unit in Carroll County. Today, I would like to highlight our co-unit also in Carroll County which is delivering strong production rates and has yielded some excellent pad drilling capital efficiency gains. We drilled six miles from a common pad with an average 24-hour restricted flow rate of 1,170 boe per day, consisting of 75 barrels of oil, 280 barrels of NGL have reduced ethane recovery and 4.9 million cubic feet of natural gas per day with flowing tubing pressures exceeding 2400 PSI. The cost of the first well on this pad including related infrastructure was nearly $8.5 million, the next five wells on the pad were drilled and completed at an average cost of only $5.9 million for a 30% decrease.

Turing now to the Greater Anadarko Basin, where we are principally targeting five places: The Mississippi Lime, Cleveland, Tonkawa, Granite Wash and Hogshooter which has been expanded recently to include some additional Missourian H targets. At March 31, we had 28 rigs running in this basin and had combined first quarter net production of 114,000 boe per day, which is up 9,500 boe per day from the fourth quarter or 9% sequentially. This was in spite of some fairly substantial winter weather related downtime during the quarter that impacted our production by nearly 5,000 boe per day.

Now, let me give you a few specific play highlights from the Greater Anadarko. In the Mississippi Lime, we have substantially completed our water disposing infrastructure projects across the majority of our core development areas.

We believe this will results in improved efficiencies for turning wells to sales and will reduce construction and water disposal cost going forward. Our measured pace in science-based approach to this play is also generating improved well performance and returns on capital.

We turned 32 Miss Line wells to sales in the first quarter at average peak rates of 540 boe per day, with five of those wells in excess of 1,000 boe per day. We are actively shooting 3D across our core development areas to assist with the geomodeling and mapping techniques we are employing to further refine prospect identification.

In short, we believe that we have the development strategy that will result in the most efficient and cost effective way to develop this play and we are eager to move forward with our soon-to-be-partner Sinopec.

Our Hogshooter Play also continues to generate outstanding results. We turned 14 wells to sales in the first quarter at average peak rates of 2,380 boe per day. Our best well, the Roark Trust 1H, tested at a peak flow rate of more than 4,570 boe per day, outstanding results.

Our teams have identified more than 50 remaining Hogshooter locations and have been successful in further extending the play to the east of our original development area. Indeed, we believe the Greater Anadarko holds the treasure chest of opportunity and we have the teens and the acreage to maximize the value for our shareholders.

And finally, I’d like to note that in our Marcellus region, where we are the industry’s largest natural gas producer, we recently achieved a gross operated natural gas production milestone of more than 2 bcf equivalent per day. As gas prices have recovered nicely from year ago levels, we are benefiting greatly from strong growth and returns in both the Northern dry and the Southern wet gas portions of the play.

Natural gas production in the first quarter was up an impressive 58% year-over-year and 9% sequentially versus the fourth quarter. You will note from our press release that we are bringing online outstanding wells in our Marcellus position that our recent results in the Southern portion of our Marcellus north dry gas play really stand out. Extending from our position in Susquehanna County, west toward into Northern Wyoming and Southern Bradford County lies the most prolific portion of our acreage position that is yielding amazing performance.

We have brought online a number of recent wells in this area that are flowing a restricted rates in excess of 12 million cubic feet per day. Based on results of over 150 producing wells in this area, we are currently estimating per well recoveries of over 10 bcf. We own approximately 100,000 net acres and have over 1,000 remaining development locations to drill in this core of the core.

And let me close by saying that I’m pleased with our liquids production growth, capital efficiency gains, safety performance and per unit cost performance to date and believe that there is much more to come. I very much look forward to the second half of 2013 when we will see a fairly substantial acceleration of pad drilling in a number of our key plays and we expect to realize production growth in the Utica has gas processing capacity is completed.

I’ll now turn the call over to Steve.

Steven C. Dixon

Thank you, Nick and Jeff. We’ll now turn it over to the operator for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) We’ll first to Dave Kistler with Simmons & Company.

David Kistler – Simmons & Co.

Good morning guys.

Jeffrey A. Fisher

Good morning.

Steven C. Dixon

Good morning, Dave.

David Kistler – Simmons & Co.

Real quickly kind of all things being equal, if we think about the timing of the divestitures that you guys have planned and that has occurred year-to-date. How does that impact the uptick we’re seeing in production guidance or should I be thinking about it as those actual timing of divestitures really had no impact to your forward plan, and the uptick in production is specifically related to just asset performance?

Steven C. Dixon

Yeah, Dave, it’s predominantly asset performance. There has been very, very little from sliding on the asset sales.

David Kistler – Simmons & Co.

Okay, I appreciate that. And then previously you guys had talked about that the divestitures would be broken into kind of two different components, a few large ones and then a number of smaller divestitures. As you think about smaller divestitures, are those going to be equally taxing on the staff to get those completed and obviously that increases the number of divestitures. Does that create any concern with respect to meeting the guidance of $4 billion to $7 billion?

Steven C. Dixon

Yeah, no concerns whatsoever. We have identified those packages and they have actually been in process for a number of months now, Dave. So a lot of that hard work has already been done by our staff. So, things are proceeding as planned and I don’t see any changes.

David Kistler – Simmons & Co.

Okay, I appreciate that. And then one last one just kind of relative to the Marcellus sale that was announced earlier. It looks like that was non-op interest, was that previously baked into capital spending rates and was there any concern that that might move aggressively forward in 2013, and why it was targeted as something that you wanted to unload in the Marcellus or is it just purely it’s not core of the core?

Steven C. Dixon

Yeah Dave, it’s mostly we had outlined where we wanted to focus our activities and our capital spend, and it was outside of that, so it was a targeted divestiture for us because of that.

David Kistler – Simmons & Co.

Okay, I appreciate that color. Thank you.

Operator

We’ll hear next from Arun Jayaram with Credit Suisse.

Arun Jayaram – Credit Suisse

Hey, good morning. I just wanted to clarify on the guidance, the updated guidance assumes that you would reach the bottom end of your sales target of $4 billion, Nick is that consistent with what you’d outlined previously in terms of guidance based on the low end of the $4 billion to $7 billion target -- sales target?

Domenic J. Dell'Osso Jr.

Yeah, that’s right Arun. Our production -- our revised production guidance assumes the same set of transactions as previous, and so we are aiming for the low end of the range within that production guidance and still have confidence that we will be well into the range, so should our production guidance need to be adjusted in the future, we’ll do so and when we do so, we’ll also update you all on how we would plan to apply those proceeds to debt reduction.

Arun Jayaram – Credit Suisse

Okay, thanks for clarifying that, just a general question -- you had some impressive growth looking at the Eagle Ford, Anadarko, and Marcellus, all on a period where your rig counts have come in a lot, just wondering if you could maybe comment on what you are doing on the completion side, you’ve talked about completing more wells and you are drilling, I was just wondering, how long does this, call it a tailwind, last for where you have more completion activity relative to wells you are drilling?

Steven C. Dixon

Go ahead Jeff, I’ll let you answer that.

Jeffrey A. Fisher

Sure. So, we are catching up on inventory in several of our plays, specifically in Eagle Ford. And as I commented, I think in that particular play, we should be kind of caught up with what we would call an abnormal inventory or backlog by the end of the year. A lot of it is still related to midstream infrastructure and just timing of bringing wells on, most of that we’re working through with our midstream partners and have line of sight to deliver those mostly by this year and maybe a little bit into the first quarter of next year. But the fact does remain that even with our reduced rig count, we are completing more wells than we’re drilling company-wide right now and that’s really by design to help us to get caught up and improve our capital efficiency.

Arun Jayaram – Credit Suisse

Okay and just a very quick follow-up on the Utica. What midstream project should we be watching in terms of trying to get -- as you try to get to that 330 target by year end, which pipeline project should we be watching?

Steven C. Dixon

Actually more processing, Natrium will be the first one on which should be in May, so this month. Then Momentum is a big one mid year, so those -- processing is really the hold up, and those two are the largest projects. In our slide presentation, we outlined this on page 17.

Arun Jayaram – Credit Suisse

Okay.

Steven C. Dixon

That talks about these various projects.

Arun Jayaram – Credit Suisse

Thank you very much.

Operator

And Bob Morris with Citigroup has our next question.

Robert Morris – Citigroup

Thank you. Steve, your comments with regard to the high end and low end of range in paying down $4 billion $7 billion of debt seemed to imply that paying down debt to $9.5 billion by year end is not as hard of a target as it was before that they may slip out further into 2014. Is that correct and what is driving that, is that just a slower pace of getting the asset sales down or just what underscores that push-out, I guess of the $9.5 billion target?

Steven C. Dixon

Well, we’re focused on the asset sales done at a minimum of 4, if we get to 7, we can actually achieve that, Nick do you have anything else to add to that?

Domenic J. Dell'Osso Jr

Yeah. Bob, I would just say from a goal perspective, the goal hasn’t changed which is an absolute reduction in our debt. We are noticeably, as you have said, being a little bit less specific about the precise timing of that because we want to preserve the optionality to get the right deals done on the right time for the right assets. There are no changes in our strategy. We are refining our assets that we hold in our portfolio to be as efficient as possible that leads to an opportunity to sell assets, and we’ll use those proceeds from asset sales to reduce debt, and we will absolutely get to that lower debt number, but we want to be a little bit cautious about exactly what we said, because we want to make sure and hit the expectations.

Bob Brackett – Bernstein Research

Sure. Now, in that regard, Steve, you’ve made the comment that the stronger gas price environment has made some of your gas assets more attractive to buyers. So, what gas assets might move up in the queue to be sold? In that regard, what are you looking at or what or is there something there that may move up in the queue given the strong gas price environment per your comment?

Steven C. Dixon

Bob, we are not talking about any specific assets, but clearly with movement in the market, it has been a buying signal for buyers out there, and we’re getting a lot of interest from a large set of buyers.

Bob Brackett – Bernstein Research

So, you would now consider more so than before selling, not saying what specifically, but selling some material gas assets at this point then?

Steven C. Dixon

Yes, at the right price we certainly would.

Bob Brackett – Bernstein Research

Okay. Great, thank you.

Operator

We’ll move on to Brian Singer with Goldman Sachs.

Brian Singer – Goldman Sachs

Thank you, good morning. You’ve talked about the 100,000 acres that core of core in the Marcellus, and in the slide that you go through that, you also highlight the larger circle that encompasses the core, can you talk about your acreage position and what you would call the core in Northeast Pennsylvania and how you are thinking about developing those acres versus selling those acres?

Steven C. Dixon

Brain, this is Steve. We don’t plan on selling any of that core acreage. We are just -- as we have our position HPP’d now, we can allocate our capital to our highest returns and certainly having a 1000 locations that is in that core of core area, that’s where most of our drilling activity is going to be in the near future.

Brian Singer – Goldman Sachs

Thanks, and I guess, of the 1.5 million acres that you have in Northern Marcellus -- dry gas Marcellus, what would be in core plus core of core 10,000 and core of core -- what’s the position that you would classify in the core?

Steven C. Dixon

I know that have that with me here Brain, but it would be multiples of that core of core.

Brian Singer – Goldman Sachs

Okay, thanks and then, I’m going back to the Eagle Ford…

Steven C. Dixon

Large inventory

Brian Singer – Goldman Sachs

Thanks, and then going to the Eagle Ford you’ve talked about your 570 boe type curve and I think on one of your slide, you mentioned that the average so far has been a little bit less than that. Has it been the recent results and recent completions that is kind of inspiring to average that up and can you talk about of the inventory highlighted, what percent of our Eagle Ford acreage position that applies to in terms of core of core?

Steven C. Dixon

Brian, I’m throwing that to Jeff.

Jeffrey A. Fisher

Yeah so it is based on improving results, I mean our results are improving in this play continuously. And that’s why we say, we think we’re being conservative in our estimates because we’re still on the uptick. So it is swayed by recent improvements, but it does include most all of the wells that we’ve drilled today. We took out of few wells that were science wells and where we were doing experimentation. So it’s a solid, a very solid reserve number. And it applies to essentially everything that we will end up retaining in the Eagle Ford. As you know, we’d looked at selling kind of a non-core position in our northern Eagle Ford asset there and the type curves and economics that we’re presenting really applied to everything else that we will have remaining, which is quite substantial.

Brian Singer – Goldman Sachs

And can you quantify the acreage you expect to retain there?

Steven C. Dixon

I think 300 that it’s (inaudible).

Brian Singer – Goldman Sachs

Great. Thank you very much.

Operator

We’ll move next to Doug Leggate with Bank of America Merrill Lynch.

Doug Leggate – Bank of America Merrill Lynch

Well, thanks. Good morning everybody. I got a couple questions also. Can I start off with the on the disposals also that $2 billion you’ve got line of sight now but I’m guessing the commentary sense right you’ve got fairly good line of sight and what comes next? So I realized that we’re all focused on the 47 range. But just in terms of trying to qualify, how you see progress towards meeting the bottom end of that range. Can you just give some, some feels to what your line of sight looks like for the balance of this year? And then I’ve got a couple of operating questions.

Steven C. Dixon

Doug, we have a number of additional assets sales that are in various stages, but many where we have basically terms agreed to and we’re just trading the paperwork and exhibits. So it’s given us great confidence to be ahead of our projections on our asset sales for the year.

Doug Leggate – Bank of America Merrill Lynch

When you say ahead, you mean, what is the target for the year, the range is pretty wide, so when you say you are ahead, do you mean you are going to meet the bottom end of the range or can you go little bit more specific?

Steven C. Dixon

We will meet the bottom end of the range certainly.

Doug Leggate – Bank of America Merrill Lynch

Based on what you’ve got line of sight on right now.

Steven C. Dixon

Yes, sir.

Doug Leggate – Bank of America Merrill Lynch

Okay, great. Thank you, my operating questions are really, it’s like you try to maybe and then I’ll leave it there, one on the Utica, you’re still sticking within the 30 million target for the end of the year. But can you help us a little bit, with what the mix is going to look like, as we progress through the year, because obviously, you haven’t really given us detail as to how the that the focus is going to be in terms of targeting of more of the liquid rich areas to the play?

Steven C. Dixon

We’ve given examples of our well results and that mix is where most of our drilling rigs are running in our activity and so it would be similar to those results.

Doug Leggate – Bank of America Merrill Lynch

Okay, so about 40% liquids roughly it looks like?

Steven C. Dixon

Jeff, do you know that number.

Domenic J. Dell'Osso, Jr.

Yes roughly.

Doug Leggate – Bank of America Merrill Lynch

All right, okay. And finally on the Anadarko Basin, the 28 rigs that you are running, could you just give us the breakdown as to where they’ve have focused as obviously the implications of being more rigs in the (inaudible) and other areas could be significant, so I’ll leave it with that? Thank you.

Steven C. Dixon

Thanks, Doug, roughly we have three in the Tonkawa, six in the Cleveland, four in the Colony Wash, three in Texas Pan Hannah Wash and two to four running in the Hogshooter play, and Mississippi at eight as of the 28 that’s approximately where everyone’s running.

Doug Leggate – Bank of America Merrill Lynch

All right, great. Thanks fellas.

Operator

And Matt Portillo with Tudor, Pickering, Holt has our next question.

Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.

Good morning. Just a few quick questions for me. I’m just trying to understand a little better how you guys think about your rig count as you exist this year. So just wanted to see if there is any other moving parts, I know you mentioned the deceleration in the Eagle Ford. But curious if there is any other areas we should think about acceleration of rigs or most the other plays going to be relatively flat and then I have a few quick follow-ups.

Steven C. Dixon

Hey, Matt. We’re really not changing our planned net wells drilled and turned in line, the reduction in rig count in the Eagle Ford throughout this year has just been because of our cycle times and improved efficiencies. So our capital spend and activity level are still the same. We have no big plans to change throughout this year. Our focus is financial discipline and meeting our budget targets.

Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.

Great. And then just within the Eagle Ford, I’m trying to understand a little bit better. As you bring down the rig count there, I think you mentioned 18 days of cycle time and we kind of roughly calculate I think 250 to 275 wells drilled under that cycle time. Is that roughly how we should think about the run rate well count for you guys going forward? Or is there any other color you could provide just on the kind of 14 run rate from a well count perspective?

Steven C. Dixon

Well, for 2013 Matt its right at 300 wells spud and 400 wells turned in line as we burn off some of that inventory. We have not provided guidance yet for 2014, but our cycle times continue to improve and we will be doing more and more pad drilling in the second half of this year and certainly much more in 2014 that will continue to improve our cycle times and capital efficiency.

Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.

Thank you. And then just my last question, as we think about your Marcellus position, obviously in the core of the core at 450 gas, I would assume your returns on 10 bcf wells are extremely strong. I wanted to get a little bit more color on how you guys think about your gas returns at 450 in the Marcellus versus some of your more marginal acreage on the liquids plays? And if you would consider any acceleration as the gas price improves or at what price would you look at accelerating your gas rig count?

Steven C. Dixon

Matt it’s been part of that Northern Marcellus is constrains on gathering and takeaway out of the basin. And so that will improve towards the end of this year and we do hope then we will be able to add rigs back and grow our Marcellus production.

Matthew Portillo – Tudor, Pickering, Holt & Co. Securities, Inc.

Thank you very much.

Operator

And Neal Dingmann with SunTrust Robinson Humphrey have our next question.

Neal Dingmann – SunTrust Robinson Humphrey

Good morning guys. Steve either for you or Jeff, just wondering to focusing on the Utica here for a second. I know you mentioned about, I guess production expected to be about the same despite having a two more wells behind pipe relating to be tied in. Are you assuming that that 14 rig count will still be able to stay rather constant or you will have to ramp that a little bit to the remainder of the year to still hit that number?

Steven C. Dixon

We actually might be able to reduce rigs there because our cycle times are improving so much. So just like the Eagle Ford not reduction in number of net wells to turn on, but just our efficiencies are improving. But with the pace that we are on, we will be able to meet those objectives and significantly grow production here in the last half of this year.

Neal Dingmann – SunTrust Robinson Humphrey

And in your slides though you mentioned on that co-unit, how you’re able to cut cost? On these pads, what’s kind of an average these days as far as what you’re doing as far as lateral length and then in kind of frac stages? Is that staying pretty constant or you are able to or are you reducing that as you are able to bring cost down?

Steven C. Dixon

Yeah, those cost reductions really aren’t achieved by downsizing the well so to speak, so we’re typically going 6,000 feet in the Utica anywhere from 13 to 18 stages we are doing some experimentation on our completions and delineating the field the main cost, savings really come from utilization of the pad, of the infrastructure that we have to spend money upfront and then just the drilling efficiencies that we see by learning from subsequent wells, so it’s very exciting very repeatable and we’re not degrading performance in any way with our designs in fact these are just very, very strong well, so our well performance continues to improve in the field and we’ll do some more experimenting on completions and optimization there is a lot of talk about that we’ve got some great folks that do that work and are well in tune with the latest technologies.

Neal Dingmann – SunTrust Robinson Humphrey

And as you said, I know you mentioned about kind of self, still some of the non core in that play just optimally, what ideally you would end up maybe was at the end of the year or maybe not really specifically broken that out yet?

Steven C. Dixon

Yeah, no specifics on that yet, Neil.

Neal Dingmann – SunTrust Robinson Humphrey

Okay, and then just lastly in order to hit some of these goals lot of guys have talked about lot of their asset sales et cetera, maybe for Nick or one of the guys just your thought to would you still consider putting some of these more mature assets in like a royalty trust structure or VPPs, have you done in the past or is it just pure asset sales we’re looking at?

Steven C. Dixon

At this point we really focused on straight asset sales, we see pretty good value there today and it certainly allows us to achieve less financial complexity.

Neal Dingmann – SunTrust Robinson Humphrey

Okay, thank you all, great quarter.

Steven C. Dixon

Thank you.

Operator

We will go next to David Tameron with Wells Fargo.

David Tameron – Wells Fargo

Hi, good morning, couple of questions for whoever, can you talk about what subsequent you have built into your four year guidance?

Steven C. Dixon

We don’t have any ethane rejection in our guidance at this point.

David Tameron – Wells Fargo

All right Eagle Ford. I think Jeff mentioned well costs your target [6.5] at that 570 EUR what are your current well cost in the Eagle Ford?

Steven C. Dixon

Current well cost are in the $7 million range, I think we discussed that at the operational update a month ago, again steady improvement down from 9 early in the play I think 8 a year ago, and we’ve got very high confidence in our 6.5 projection, keep in mind we are drilling a little bit longer laterals and some in the play at 6,300 feet, we made and push that a little bit more. But that’s where we are at.

David Tameron – Wells Fargo

Okay, fair enough and condensate, what’s your condensate in oil cut in the basin?

Steven C. Dixon

You are talking about Eagle Ford?

David Tameron – Wells Fargo

Eagle Ford, I am sorry, yeah.

Steven C. Dixon

Yeah, I think we are roughly at 60% oil, 20% NGL and 20% gas, we will check those numbers that most of our liquids production there, at least on the oil side is 45 degree gravity oil we’ve got some condensate down in the wet gas window, but think of our mix is 45 degree spot on premium oil

David Tameron – Wells Fargo

Okay, good. And then last question, Anadarko Basin gets about 30 year CapEx but can you give us more clarity I was going to say kind of get the short shift, but can you give us more clarity exactly, outside the Mississippi Lime which is obviously well documented. Can you talk about the Granite Wash, Cleveland, Tonkawa, Hogshooter? Can you write those for tell us or just tell us where the focuses are? I know you said you had three, four rigs in different plays. So can you just give us some color on overall what you’re doing out there?

Steven C. Dixon

Sure, Dave. In Western Oklahoma for the most parts some of that overlaps in Texas Panhandle, so it’s in Chesapeake’s kind of core Anadarko Basin position. And our asset teams are just targeting the highest potential wells and focused on drilling our very best well next. And you know there is a variety of pace in Anadarko Basin and we’re allocating depending on what this prospects look like. Again Jeff, can you add on to that Jeff?

Jeffrey A. Fisher

Yeah, I would just add that we group the Anadarko Basin at our conversion today just because we look at it as a very broad prolific basin with multi-pays and its stack pays, its Stratigraphy trends throughout the basin. And we just have a huge core acreage position there that we are exploiting. I’ll take you as far as some advancements in our Hogshooter, Cleveland, Tonkawa plays for teams we’re doing a great job of breaking down the science on these. These most of our plays in the Anadarko are not statistical resource type plays. They are Geosciences driven plays that require a different approach and we just got the critical mass and the economies of scale to commit to that and our teams are continuing to improve our well results and we’re just, we’re very excited. And we’ll talk about those five plays today, but in three to five years, that will be another three or four plays, probably as this continues to develop.

David Tameron – Wells Fargo

I’m taking a shot at this, would you go Hogshooter, Cleveland, Tonkawa and the Granite Wash as far as rank order today of prospectively or am I forcing that?

Steven C. Dixon

I mean it’s on product prices, because they do ship some for complete oil to much higher gas and then some have, higher IPs. So that helps rates of return, we’re pleased with all of them and we allocated our resources into our best prospects.

David Tameron – Wells Fargo

Okay. Fair enough, all right. Yeah, I hear you. Thank for all the question, all the Q&A, appreciate it.

Steven C. Dixon

Thank you.

Operator

We’ll hear now from Jeff Robertson with Barclays.

Jeff Robertson – Barclays

Thanks. Steve, it’s a follow-up on the Anadarko Basin. Can you rank order in terms of returns at current commodity prices and results you are getting the returns in the various plays that you outlined?

Steven C. Dixon

Jeff, certainly don’t have that here with me. And those we’ve listed the top five plays, there is actually, I think we drilled horizontal laterals in 12 different zone stacked in the Anadarko Basin. So, it’s just a great legacy asset for Chesapeake as we have already own all the land, there is HBP. And so, as Jeff mentioned, these are not resource plays, these are prospect specific, and we’re just drilling our best prospects next.

Jeff Robertson – Barclays

Can you talk about what the well costs are up there?

Steven C. Dixon

Again, a variety, Jeff, they’ve ranged from fairly deep Granite Wash wells to very, very cheep shallow Mississippian well. So it’s a wide range from eight plus to under four. So….

Jeff Robertson – Barclays

Okay. And then Nick a question on just as you will look at the types of assets that you hope to sell over the course of 2013. Will that have any impact on the amount of interest that Chesapeake capitalizes?

Domenic J. Dell'Osso

No, I don’t really anticipate a significant change in our capitalized interest rate for this year. We’ll keep looking at that as we go forward.

Jeff Robertson – Barclays

Okay, thank you.

Operator

And Charles Meade with Johnson Rice has our next question.

Charles A. Meade – Johnson Rice & Company LLC

Good morning gentlemen. Well thanks for taking the question here at the end of the hour. First going back to the Eagle Ford, I think you mentioned a little bit earlier that you guys are drilling longer laterals at 6,300 feet on average. But for the wells that you, that good well that you put in your press release, (inaudible). Can you talk about with the configuration of that well, the lateral length and how many stages? And how are you evolving overall in the play as far as lateral length and stages?

Steven C. Dixon

Well, Charles, I don’t have any specifics on that well. And how it was competed with lateral length as Jeff mentioned that’s an average. And so depending on how the leases layout some are shorter, some are longer than that. We are not really trying to extend that much further, that’s pretty long lateral for an average program again it will have 7,500 foot wells but I was in there some, but for an average program that’s pretty long. So I don’t anticipate that changing dramatically.

Charles A. Meade – Johnson Rice & Company LLC

Okay, thank you. And then going back to your comments, your prepared comments I think I believe I heard that in the Anadarko Basin, there was a weather impact of 5,000 boe a day for the first quarter and I was curious two things, one is, is that gross or net and then two, is that the total weather impact or is that really the weather impact versus your baseline expectation for weather in that first quarter of the year?

Steven C. Dixon

Go ahead, Jeff.

Jeffrey A. Fisher

Yeah, the 5,000 boe per day is net and it really resulted from a significant number of snowstorms believe it or not that we had in Northwest Oklahoma, and I wasn’t sure I followed the rest of your question?

Charles A. Meade – Johnson Rice & Company LLC

It was really, presumably, you have some amount of downtime baked in every first quarter for snowstorms, but I was just curious that was that the total impact or was that really the impact beyond what you normally expect?

Jeffrey A. Fisher

Sure, now I understand that would be incremental to what we would consider normal downtime

Charles A. Meade – Johnson Rice & Company LLC

Great. Thank you.

Operator

Biju Perincheril with Jefferies & Company has our next question.

Biju Perincheril – Jefferies & Company

Hi, good morning. Steve looking at the guidance, I think you’ve mentioned in there that 42 bcfe that you are removing for asset sales, it sounds like there is some incremental above and beyond the Miss Line and Eagle Ford is that can you talk about is that a various pieces or are there some major components there?

Steven C. Dixon

Well, there are variety of packages, lots of little packages out and some have small production like the Marcellus that was announced with just 2 million a day some have slightly more, so it’s just a variety from the packages, we identified the production associated with those.

Biju Perincheril – Jefferies & Company

Okay, so as far as major producing assets, is it fair to say it’s the Miss Lime and Eagle Ford?

Steven C. Dixon

Certainly those would be bigger ones.

Biju Perincheril – Jefferies & Company

Okay. And then the well cost that you mentioned in Utica, first of all on that pad versus the subsequent wells, is that how much of that improvement is operational gains versus the cost for the first well did that include your site cost?

Steven C. Dixon

Yeah, the first well would have included the location costs, the roads in, moving the rig in those kinds of big dollar amounts. And so all of those are saved on the subsequent wells. But definitely there would be a piece of that what will be, what the knowledge base for both fast we drill but also how we target on the well. So we can drill those subsequent wells faster than the original well normally.

Biju Perincheril – Jefferies & Company

Okay. And typically how much are those location costs running?

Steven C. Dixon

Pretty expensive in the east, I don’t have an average number but 500,000 pretty can easily be that high.

Biju Perincheril – Jefferies & Company

Got it. Okay, thank you.

Steven C. Dixon

Very good, we reached the top of the hour and I would like to thank you for joining our call today and your interest in Chesapeake. If you have additional questions, please follow up with Jeff or Gary later today. Thank you all.

Operator

And now we’ll conclude today’s conference. Thank you all for joining us.

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