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Executives

Jeffrey L. Mobley – Senior Vice President-Investor Relations and Research

Aubrey K. McClendon – Chief Executive Officer

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

Steven C. Dixon – Executive Vice President – Operations and Geosciences and Chief Operating Officer

Analysts

Brian Singer – Goldman Sachs

David Kistler – Simmons & Company International

Doug Leggate – Bank of America Merrill Lynch

David Tameron – Wells Fargo

Biju Perincheril – Jefferies

Charles Meade – Johnson Rice

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Robert S. Morris – Citigroup

Jason Gilbert – Goldman Sachs

Scott Hanold – RBC Capital Markets

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

Bob Brackett – Bernstein Research

Joseph Magner – Macquarie Capital Markets

Chesapeake Energy Corporation (CHK) Q2 2012 Earnings Call August 7, 2012 9:00 AM ET

Operator

Good day, and welcome everyone to the Chesapeake Energy 2012 Second Quarter Earnings Results Conference Call. Today's conference is being recorded. At this time, I would like to turn the conference over to Jeff Mobley. Please go ahead, sir.

Jeffrey L. Mobley

Good morning, and thank you for joining our conference call today. I'd like to introduce the members of the management team that are on the call this morning. We have Aubrey McClendon, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Steve Dixon, our Chief Operating Officer; John Kilgallon, and Gary Clark from the Investor Relations team, and this is Jeff Mobley speaking.

Following the comments of the management team, we will take your questions this morning. And as I’m sure you can understand, we are not going to be able to comment on matters that are subject to litigation or other enquiries. As usual, our call will last one hour. And now I'll turn the call over to Aubrey.

Aubrey K. McClendon

Good morning and thank you for joining us today. Despite experiencing the lowest natural gas prices in over 10 years during the 2012 second quarter, we're pleased with the company's performance during this challenging time for our industry. For example, our production surged ahead by 25% year-over-year and 4% sequentially. However, had it not been for our 330 million per day gas curtailment during the quarter, Chesapeake's production would have actually been up a remarkable 36% year-over-year.

These production increases are obviously impressive, but they are especially so for a company as large as ours. Most importantly, our oil production growth has really taken off. Starting from a base of 26,700 barrels per day in January 2010, in the past 10 quarters we have increased our oil production by 201% to 80,500 barrels per day.

Our natural gas liquids production growth has been very strong too, growing from 10,600 barrels per day in January 2010 to nearly 50,000 barrels per day in the second quarter, an increase of 370%. Taken together, Chesapeake’s total liquids production over 130,200 barrels per day has now risen to 21% of our total production mix and we expect this percentage to continue trending upward to 35% of total production by 2015.

In addition, our second quarter liquids production was up 65% year-over-year and 15% sequentially. Looking across the industry, our year-over-year liquids production growth is the third best in the industry on an absolute basis, and on a percentage basis, it is the second best. Chesapeake is now the 11th largest liquids producer in the U.S. and we hope by 2015 to be knocking on the door of the top five liquids producers in the U.S.

You may recall that in 2010, when we had a very modest liquids production of about 30,000 barrels per day, we set a goal of reaching an exit rate of 250,000 barrels per day of liquids production in 2015. In 2011, we accelerated that goal to be an average of 250,000 barrels per day during all of 2015 rather than just an exit rate. Given that Chesapeake’s production already exceeds 50% of our objective, it appears our ambitious target can likely be exceeded if present trends continue.

Turning to gas production, I hope you noticed that we are now projecting a decline in Chesapeake’s gas production of approximately 7% in 2013. This will bring to an end our likely unprecedented public company record of 23 consecutive years of gas production growth, which has taken Chesapeake’s gas production from 10 million cubic feet per day in 1993 to more than 300 times that level currently and in the process has helped transform U.S. gas market.

Moreover, Chesapeake’s projected 7% downward trend in gas production for 2013 will likely continue beyond that year and till such time that gas prices rise to levels that make returns from drilling in our gas plays competitive with returns available from drilling in our liquids plays. In fact, by year-end 2013, we expect Chesapeake’s gas production rate to have declined by 430 million cubic feet per day or 14% from our peak rate of 3.4 Bcf per day in 2012.

Including the production of our non-operating working interest owners and our royalty owners, the total decline in Chesapeake operated U.S. gas production is likely to be around 800 million to 900 million cubic feet of gas per day. And based on the substantial gas drilling rig count decline, last week reached the 12 year low in the embedded high decline rate in the country's existing natural gas production base.

We believe it won't be long until the EIA-914 data shows U.S. gas production on a confirmed downward trend. We believe this trend of declining gas production could continue as long as gas prices do not permit gas producers to earn an attractive return on the investments necessary to finish developing the big new unconventional gas fields that led to America's greatly increased gas production over the past five years. In addition, the gas storage overhang is decreasing by an average of 2 to 4 Bcf per day each week. If this trend continues and we experience a normal winter, the U.S. gas market could reverse its 900 Bcf year-over-year storage surplus established in April 2012 and lead to potential gas storage deficit in April 2013 of up to 900 Bcf.

As a result of this potential storage reversal, rising demand for natural gas across the economy and likely production declines from many gas producers as they continue shifting their CapEx towards more profitable liquids production, we expect gas markets to look very different during the next few years than they have looked during the past six months.

Chesapeake's management believes that based on the foregoing, the U.S. is likely in the very early stages of a multi-year up cycle in gas markets fundamentals and clear evidence of this new up cycle is readily apparent. Gas prices have bounced strongly upward, from $1.84 level set on April 19, which we believe marks the low in the four year down cycle that started in 2008.

Now I’d like to return to Chesapeake's operational performance during the first half of 2012, we added proved reserves of 4.2 Tcfe through the drillbit or the equivalent of about 700 million barrels of oil equivalent at a very attractive finding and development costs of only $1.14 per Mcfe or [$6.84](ph) per boe. Using current NYMEX strip pricing these added proved reserves at $10.2 billion of PV-10 value.

So to drive this important point home, I’d like to reiterate that in first half of 2012, we invested $4.7 billion in our drilling programs. And from that drilling, we created $10.2 billion of future PV-10 proved reserve value. That means that for every one dollar that we invested in drilling in the first half of the year, we found $2.17 of PV-10 proved reserve value. In total that's a margin between finding costs and PV-10 value of $5.5 billion, or about $7 per share of net asset value creation for our shareholders, and that $7 per share value creation in just the first six months of 2012. We believe that's an exceptional performance especially during the six-month period of very low gas prices.

I believe it is this metric above all others that showcases the effectiveness of Chesapeake’s drilling machine at converting large blocks of undeveloped leasehold into very large quantities of proved reserves. And we believe Chesapeake’s performance can improve even further from this very high level as we progress from operations, designs for new asset identification and capture to more manufacturing like operations approach designed to maximize efficiency and returns as we shift more fully into harvest mode.

We are now able to increasingly focus on developing just the core of the core areas of our plays taking advantage of first well infrastructure, benefiting from economies of scale and development mode drilling efficiencies and also capitalizating on our substantial investments in human resources experience and technology.

In doing so, we're now projecting to reduce our capital expenditures from 2012 to 2013 by $6 billion, or about 45%. Clearly we have listened to investor feedback on this important topic.

We also enjoyed a very successful quarter in advancing our asset sale. As you know, our planned asset sales for the year are designed to help us afford to increase our liquids production, tighten the focus on our core assets, while also reducing our long-term debt by 25% from year end 2010. To achieve this important shift to a closer balance of liquids and natural gas production, we have invested billions of dollars over the few years.

While low gas prices have made this shift to liquids focused production more difficult to achieve, those falling gas prices also made the shift more urgent. However we've now captured what we set out to capture in terms of our resource base, this will now permit Chesapeake to be in asset harvest mode for a very long time.

As a result, we anticipate much higher returns from our portfolio than you’ve seen in the past. With regard to specific asset sale information during the second quarter, we closed on $2.7 billion of asset sales, bringing our total for the first-half of the year to $4.7 billion. During the third quarter, we anticipate entering an asset sales agreements of approximately $7 billion, which would bring our asset sales to approximately $11.7 billion year-to-date. We continue to identify additional assets to sell, during the fourth quarter that will help meet our updated goal of $13 billion to $14 billion in asset sales for 2012.

In addition, we are planning $4 billion to $5 billion of asset sales in 2013. So, by year-end 2013, I believe we will have completed sufficient asset sales to have met our objectives and to have transformed Chesapeake by shifting our production mix to more profitable liquids, tightening the focus on areas where we have industry-leading scale and expertise, reducing our debt by 25%, reducing our total CapEx by $6 billion, slashing leasehold spending and at the same time increasing our returns, while continuing to generate production growth.

When we have completed our asset sales, we anticipate Chesapeake will still retain core positions in 10 plays, which we believe will be 10 of the 15 best plays in the country. In each of those 10 plays, Chesapeake will be either the number one or number two producer. We are not aware of another company that will be number one or number two in more than three of these 15 best plays.

It has certainly been a long and arduous journey during the past seven years to build an asset base of this uniquely high quality. But it was a very important and worthwhile endeavor to pursue at a pivotal time in the history of our industry. We have appreciated investor support and their capital during this time, which enabled us to complete this important phase in our company’s history and position Chesapeake very favorably for the years ahead.

I’d also like to express appreciation to my 13,000 Chesapeake colleagues, who have continued to work hard and meet all of the challenges over the past few months. Their talent and dedication will certainly be critical in helping Chesapeake reach its goals in the years ahead.

Finally, as you know, a lot has changed since our 2012 first quarter conference call three months ago. I would like to especially thank our new independent Board Chairman, Mr. Archie Dunham and our newly reconstituted Board of Directors for jumping right in to get up to speed about our strategy and operations. Their involvement should enable us to further sharpen our focus on driving higher returns from Chesapeake’s assets while maintaining a strong balance sheet. without a doubt, these efforts should lead to improved operational and financial performance for years to come.

I’ll now turn the call over to Nick.

Domenic J. Dell'Osso, Jr.

Thanks, Aubrey.

It was a very good quarter operationally, and I’m particularly pleased to highlight our strong production results. we produced 3.8 Bcfe per day, an overall sequential increase of 4%. but more importantly, we achieved a 15% sequential increase in liquids production. this quarter, we began reporting oil and NGL separately, now that our NGL production reserves have increased to a material level. I’d like to highlight the liquids production volumes for the second quarter was about 62% oil and 38% NGLs, and also that our rate of growth in oil production has substantially outpaced our growth in NGL production over the past year.

We’re also very pleased with the continued strength in our oil price realizations, which were 96% of NYMEX before the effects of hedging this quarter. These high realizations are a direct result of the hard work by our subsidiary, Oilfield Trucking Solutions in the Eagle Ford as well as enhanced pipeline connectivity out of the basin, both of which contribute greatly to robust overall pricing. Thanks to strong growth in the Eagle Ford, 45% of our companywide net oil production during the quarter is now sold at a Louisiana light sweet correlated price versus 0% in the year-ago quarter.

looking ahead to 2013, we are currently forecasting flat year-over-year oil differentials, but we do see potential for these to improve further. You will see in our results that like many of our peers, we reported challenging NGL price realizations. however, we believe these realizations are bottoming and expect them to improve moderately for a couple of reasons.

First, we currently sell 50% of our NGL to Conway. in 2013, we will access Mont Belvieu pricing for a portion of those volumes based on new pipelines and resulting basis compression. Second, industry wide rejection of ethane has kicked in which should begin to ease the ethane oversupply situation and prompt a modest increase in pricing.

Finally, more propane export capacity is being developed along the Gulf Coast and East Coast, which should begin to ease the supply overhang before year-end. Coupled with the traditional seasonal balance associated with the onset of colder weather, these factors should lead to better propane prices in the fourth quarter. So we expect one more quarter of very weak NGL realization and then some relief in the fourth quarter, both of which we have built into our guidance.

As a result of our strong production performance in Q2, we are increasing our production guidance for both 2012 and 2013 by approximately 110 Bcfe and 90 Bcfe in each year respectively. After adjusting for the changes in expected production decreases associated with asset sales, which are detailed in our outlook, and adjusting for reduced 2012 curtailments, our organic production guidance has been increased by approximately 75 Bcfe or 6% in 2012 and approximately 140 Bcfe or 10% in 2013.

On the CapEx front, we are increasing our 2012 drilling and completion CapEx guidance by about 6.5% to $8 billion to $8.5 billion. This is purely related to the high activity levels from year-end 2011 and the first half of 2012 that is still working through this system as we ramp down in most of our plays. However, as expected, we have seen our month-over-month spending begin to decline in both June and July as our rig count has dropped pretty dramatically, which Steve will detail for you shortly.

On the leasehold side, we are increasing our 2012 estimated spend to $2 billion, lowering our 2013 estimated spend to $400 million. Given that about $1.3 billion leasehold spend year-to-date, you can see that second half of 2012 spend is considerably less than the first half and the ramp down in activity is complete.

I might also add that approximately 50% of this leasehold spend was wrapping up our Utica leasehold acquisition efforts and the Mid-Continent contributed another 25% of the leasehold spend this year. Even more importantly, our 2013 drilling and completion CapEx has been reduced by $750 million to a range of $5.75 billion to $6.25 billion reflecting rig count reductions and efficiency gains from our core of the core strategy.

I’m very pleased to point out that even with drilling CapEx about $2 billion lower in 2013 than in 2012, we are actually raising our 2013 production guidance by 7% due to strong performance in our liquids plays. Also very notable in our 2013 CapEx spending forecast is the significant decrease from our prior outlook of $1.275 billion as a result of the sale of our Midstream business. Total decrease in 2013 spending relative to our May 1 outlook is over $2.1 billion and again we’ve been able to increase our production guidance despite the significant CapEx reduction.

Our adjusted EPS for the quarter of $0.06 per share was negatively impacted by approximately $0.06 per share due to the effect of higher DD&A related to price related revisions primarily from Barnett and Haynesville PUD eliminations. If gas prices follow the current NYMEX Strip, these reserves may be eligible to come back on our books in 2013 subject to our forecasted pace of drilling in those areas.

I’d like to point out that we did not have a ceiling test write-down this quarter, as we have built a full cost pool cushion as a result of our low finding costs and profitable asset sales in recent years. As a full cost company, we are not able to recognize gains in our income statement when we sell E&P assets and are instead required to apply the asset sale proceeds and decrease of our full cost pool resulting in lower DD&A rates over time.

We do expect to have a ceiling test write-down in Q3 as we substitute three more months of low 2012 gas prices to the trailing 12 month SEC calculation. I’d like to note however that as the 10 year average strip pricing our PV-10 is $5.2 billion higher than under the SEC methodology as shown on page five of our earnings release. You’ll also see in our release that we’ve added significant GAAP hedges for the second half of 2012, at an average price of $3.03 per Mmbtu. While we don’t view the current natural gas price strip as long-term sustainable, we did see that there is an opportunity to take a significant amount of fall shoulder season risk off the table.

We remain quite bullish on gas prices in 2013 and beyond, and accordingly have begun to reduce some of our previously written half year natural gas call positions. We are making great progress on our asset sales and are looking forward to having more share of investors in the next month or so. We will use the proceeds from our Permian and midstream sales to retire $4 billion term loan put in place in May, and plan to apply the remaining proceeds from these sales and others to any outstanding balances on our $4 billion corporate revolver, which was 100% undrawn at June 30. We also have a very favorable call feature on the $1.3 billion notes we issued in February of this year, which allows us to call the notes at par between November 15 of this year and March 15 of 2013.

Our goal is to exit 2012 no more than $9.5 billion in long-term debt, which implies having nothing drawn under our $4 billion corporate revolving credit facility. Going into 2013, this revolver liquidity plus the discretionary liquidity associated with the $1.3 billion of callable notes, would give us $5.3 billion of available liquidity, irrespective of the amount of our 2013 assets sales. To be clear, we intend to complete our 2013 projected asset sales of $4.25 billion to $5 billion, and finish 2013 with no incremental net debt. However, we did not expect to be dependent on the 2013 asset sales program to meet our liquidity needs.

Lastly before turning to call over to Steve, I want to point out that few weeks ago, we posted an appendix to our investor presentation that included more detail on our VPP’s midstream commitments and drilling and compression sale leasebacks. There isn’t much written about these items in the past few months and we wanted to make sure that facts were disclosed and available for all to analyze. Please let us know if you have any questions regarding these new slides. Steve?

Steven C. Dixon

Thanks, Nick. I am very pleased and impressed with our operational performance, and I am very proud of the efforts and the results that our team at Chesapeake has been able to deliver for our shareholders this year. As Nick just outlined, our strong liquids production growth during the second quarter has prompted us to raise our forward liquids production guidance outlook for the remainder of 2012 and 2013, to an average of 135,000 barrels per day to 170,000 barrels per day respectively. These are increases of 12% and 9% respectively and are net of volumes associated with projected asset sales.

I’d also like to point out that the majority of this growth will be in our oil production versus our NGL production. We mentioned in our last quarterly call that in response to low natural gas prices we would reduce drilling in our dry gas plays from 47 rigs at the beginning of 2012, to just 11 rigs by year-end. We have accomplished this goal and now plan to further reduce this amount to eight rigs at year-end.

At our high-water mark back in March 2010, we were drilling with 104 gas rigs. As you might imagine, this will have profound impact on our gas production. In 2013, we are now projecting a 7% decline in gas production.

Moving on to the cost side of our business, we are beginning to realize significant benefits from lower service costs and rising drilling efficiencies as we optimize our activity levels and move more fully into harvest mode. Consequently, we plan to drill the same number of net wells with fewer rigs operating and have accordingly reduced our projected yearend 2012 liquids rig count from 115 down to 93.

In the second half of 2012 and in 2013, we plan to spend approximately 85% of our drilling completion capital in oil and liquids plays.

I’d also like to point out that I'm especially proud of our operating cost control efforts as we have ramped up our liquids production, but yet we still expect per unit production expenses to remain relatively flat at approximately $1 per Mcfe for 2013.

Moving on to specific plays, I’d like to start with the Eagle Ford Shale. It's attracting 28% of our capital in 2012 and 33% in 2013. Second quarter net production from Eagle Ford was 36,300 boe per day, which is a 58% increase over the first quarter and 615% year-over-year.

During the quarter we connected 121 wells or nearly one-third of our 337 total producing wells in Eagle Ford. Importantly at June 30, we had 220 wells at various stages of completion and pipeline connection. This provides a foundation for strong liquids growth runway into the quarters ahead.

In addition to rapid growth and robust activity levels, the Eagle Ford is particularly exciting as we have experienced higher per well initial production rates, an oilier production mix and lower well cost. During the second quarter, 31% of the wells we placed on production had peak rates in excess of 1,000 boe per day. And furthermore 91% of our wells placed in production at peak rates in excess of 500 barrels per day and that’s up from 81% in the year ago quarter.

Approximately 66% of our Eagle Ford production volumes during the quarter were oil as compared to 57% in the first quarter. This is an important increase given the much higher margins associated with oil production relative to gas and NGLs.

These metrics help demonstrate that Chesapeake’s Eagle Ford acreage is located in the core of the very best oil acreage in the western portion of the play. With regard to cost control, our completed well cost in the Eagle Ford are tracking 15% lower than a year ago and we expect further reductions in the months ahead. This will enable us to target year end exit rate of only 25 rigs, down from 28 currently and from a peak of 35 rigs, three months ago.

Turning to the Anadarko Basin, we have 4 key plays that provide a very strong base for continued liquids growth production, the Miss Lime, the Granite Wash, the Cleveland and the Tonkawa. At June 30, we had 51 rigs running in these plays and combined second-quarter net production of 88,100 boe per day. Production mix in these four plays consist of 34% oil, 23% NGLs, and 43% gas.

Looking ahead to 2013, we anticipate these plays will comprise approximately, 19% of our total production and that oil will continue to rise as a percentage of the production strength.

As Nick mentioned in his remarks, we are working with others to jointly obtain infrastructure enhancements, such that our NGL production from these areas will access more favorable Mont Belvieu pricing.

Also in the Anadarko Basin, I would like to highlight our emerging Hogshooter Wash play, which could become a meaningful contributor to our oil volumes over the next few years.

Our Thurman Horn 406H well which we first announced on June 1 has produced nearly 330,000 boe in its first 60 days on production, almost 80% which is oil. We are pleased to report this well has already generated over $16 million of gross revenue that paid out in one month. We believe this has been the best onshore well in America in the past two months and may continue to grow even though as production starts to decline from extraordinary levels in the past few months.

And off-set well, the Thurman Horn 4010H is now drilling ahead and will provide valuable information from this immediate area and its ultimate recoverability. Just recall, it’s approximately 30,000 acres perspective in the Hogshooter Wash and has identified 60 potential drilling locations. 11 wells are scheduled to spud in the play before the end of '12, so stay tuned for more updates. In addition we believe the liquids rich Missouri Wash, will also emerge as a key play for us down in the Texas Panhandle later this year and 2013.

In the Powder River Niobrara play we’ve finally cracked the code with numerous recent wells drilled in our newly identified over pressured liquids rich core area of 100,000 net acres, delivering outstanding flow rates of more than 1,500 boe per day. However due to limited gas takeaway infrastructure and processing facilities, production growth in the Powder River Basin has not yet begun in earnest, but we expect to see this area take off in 2013 and beyond as we’ve identified over 1,000 potential locations in the Niobrara core.

In addition, we believe a significant portion of our overall 350,000 net acres of Powder River lease hold will be prospective for other formations such as the Teapot, Parkman, Sussex, Shannon and Frontier formations. We’ve eight operated rigs currently running and plan to ramp this up to 11 by year-end. I might add that CNOOC is paying for 67% of our drilling costs in the Powder River Basin and we project that that will remain to the end of 2014, as we earn our remaining drilling carried, which was approximately 520 million as of June 30.

I’ll now turn to the Utica Shale in Ohio, where we are the leading leasehold owner, driller and producer with 12 operated rigs currently working to evaluate our 1 million plus net acres. We continue to delineate the wet gas window as well as HBP some acreage in the highly productive dry gas window towards the east. The Utica oil window is being tested by Chesapeake on both an operated and non-operated basis as well as by other industry competitors that are beginning to report results. Well completions are progressing at a quickening pace in the Utica as much needed midstream infrastructure begins to come into service. We’ve recently submitted the number of new wells to the Ohio DNR which will soon be posted on their website. We remain very pleased with our results to date in the Utica.

To conclude my remarks, I hope our report today makes it abundantly clear that we believe liquids rich plays are working exceptionally well and we expect drilling and completion cost to come down further or per well operating costs remain constant. The Eagle Ford is our most active play, continues to attract the largest amount of our capital, while our bread-and-butter liquids plays in the Anadarko Basin, the Miss Lime, Granite Wash, Cleveland and Tonkawa contribute to a steady upward trend.

In addition, the Niobrara in the Powder River Basin should become a significant contributor to our liquids growth and we are looking forward to strong contributions from the Utica in 2013 and beyond. and of course, we retain exceptional upside optionality and leverage to potential 2013 rebound in natural gas prices that Aubrey outlined in his opening remarks.

As Nick detailed in the outset, our corporate production guidance takes into account oil production losses from our expected 2012 and 2013 asset sales, and also reflects our substantially lower capital budget for 2013, which is predicated on the reduction in average rig count from a 131 down to just 100. despite these adjustments, our strong underlying property base and enviable leasehold position still enables us to project positive production growth for 2013.

Operator, we’ll now take questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) And we’ll go first to Brian Singer of Goldman Sachs.

Brian Singer – Goldman Sachs

Good morning.

Aubrey K. McClendon

Good morning, Brian.

Brian Singer – Goldman Sachs

Wonder if you could connect a few dots with regards to the production and asset sales guidance that you’ve revised. It seems like you expect less proceeds from asset sales in aggregate in 2012 to 2013, a greater negative impact on ongoing production resulting from these asset sales. But as you highlighted both oil and gas production guidance was taken higher, in the interest of trying to determine how much of this change in guidance is driven by performance versus restructuring. can you just add a little bit of color on the moving pieces please?

Domenic J. Dell'Osso, Jr.

Hi, Brian. When you talked about less asset sales proceeds, I think what you are really pointing to is that we took VPP off a while ago. The increase in production relative to performance and unrelated to asset sales is about 140 Bcfe in 2013. Does that answer your question?

Brian Singer – Goldman Sachs

Yeah. And I guess can you break, since both oil and gas was impacted, can you break that down or I know you highlighted Eagle Ford in Steve comments, but are there major drivers on the oil side versus the gas side?

Domenic J. Dell'Osso, Jr.

There are, and so it’s approximately 50-50 of that would be gas versus liquids and then the oil and NGL split would be as related to our base production, so a little better than 60-40 to the oil.

Brian Singer – Goldman Sachs

Okay. And then, you highlighted your Eagle Ford backlog, you’ve got a big backlog in the Marcellus, what are your expectations for how this backlog will change and what’s baked into that guidance for 2013?

Steven C. Dixon

Brian, this is Steve. We are working part of that off and part of that was our overspend on capital running quite a few frac crews in the Eagle Ford to catch that up as well as Marcellus.

Brian Singer – Goldman Sachs

Got it. I’m sorry, so do you expect that backlog to be eliminated by the end of next year or is that what’s baked in?

Domenic J. Dell'Osso, Jr.

A big portion of our Eagle Ford backlog is normal course.

Brian Singer – Goldman Sachs

Okay.

Domenic J. Dell'Osso, Jr.

So we don’t expect it to be eliminated. And the Marcellus backlog will stay with us for some time, as we are doing some appropriate backlog reduction there but we are not exactly raising.

Brian Singer – Goldman Sachs

Thanks. And if I could ask one more, you highlighted in the release an expectation for may be a greater strategic update with the third quarter results, can you just talk to whether you think that will be dramatically different versus this latest change in 2013?

Aubrey K. McClendon

I do not expect it to be dramatically different, no.

Brian Singer – Goldman Sachs

Thank you

Aubrey K. McClendon

Okay. Thank you, Brian.

Operator

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

David Kistler – Simmons & Company International

Good morning guys.

Aubrey K. McClendon

Hi, Dave.

David Kistler – Simmons & Company International

Just following up on Brian’s real quick, can you break out just specifically the Eagle Ford, VPP and the implications that had on production guidance for 2012 and for 2013.

Domenic J. Dell'Osso, Jr.

Well, the VPP in and of itself was projected into our 2012 and 2013 production guidance. When we pulled it out, we had a reduction or an add back of about 30 Bcfe in 2012. And again about 50% of that is – sorry, I misspoke really when I gave the number to Brian – about 50% of that is oil, 25% NGL, and 25% gas of the Eagle Ford. Of what we are adding back in the 140 Bcfe to 2013 that is performance related, that's about 50-50.

David Kistler – Simmons & Company International

Okay, that's helpful. I appreciate that and…

Domenic J. Dell'Osso, Jr.

In 2013, the VPP impact was about 35 Bcfe.

David Kistler – Simmons & Company International

Okay, great. I appreciate that and then, are we to come to the assumption though that VPP for the Eagle Ford is completely off the table or is that something that comes back on the table as perhaps crude prices get a little bit better, NGL prices get a little bit better, any color on that would be helpful as we think about divestiture plans into 2013.

Domenic J. Dell'Osso, Jr.

For now, it's off the table.

David Kistler – Simmons & Company International

Okay, appreciate that. And then one last one just on the Niobrara as you guys talked about cracking the code there, can you talk a little bit about what's your thinking? The initial rates of return on those wells look like and maybe anything around well cost, well design et cetera.

Steven C. Dixon

Yeah, Dave, this is Steve. It’s still pretty early there. I think we have improvements that we want to make on our well cost, but we’ve certainly found a sweet spot with this over pressured high in liquids basin center that we’re really hoping to get some production history and improve on.

David Kistler – Simmons & Company International

Okay, so to be determined over time is the best way to think of it?

Steven C. Dixon

It’s still early. We’ve got some, I think some big improvements to make on the cost side. We’ve been still doing a lot of science in defining this sweet spot.

Aubrey K. McClendon

David, I’d just say that, anytime when we’re in a liquids play, the goal is to have greater than 50% rate of returns. So if we’re for some reason not there yet on these production rates we intend to get our cost to that point. So these are big wells and they can come in at 1,000, 1,500 boe per day. We’ve got some gas production takeaway issues that are going to take a little bit of time to resolve, we probably have some flaring issues associated with that, but we really like where we are and of course we’ve got CNOOC paying most of the cost there. So if you take into consideration the carry, our returns from the Niobrara basically- well, through the stratosphere when you’re only paying for a quarter of your cost.

David Kistler – Simmons & Company International

Great, I appreciate the added color there. Thanks guys.

Aubrey K. McClendon

David, thank you.

Operator

We will go next to Doug Leggate of Bank of America Merrill Lynch.

Doug Leggate – Bank of America Merrill Lynch

Thank you, good morning everybody. I am going to try just a few quick ones, if I may. I don’t know how much you can share about the assets sales at Aubrey, but obviously you talked about 1.5 million acres in the Permian and you’ve give a range of values around that. It looks like you’ve spilt into more than three packages. Could you give any colors to, order of magnitude, what’s still left on the table and I guess level of confidence that these are going to get done in the third quarter? I’ve got a few follow-ups, please.

Aubrey K. McClendon

Okay, sure. Doug, when we started out, we operated in both one entire package, but also in the data room there were three packages, there was the Midland Basin package, which was the smallest and then there was the New Mexico Delaware Basin, and the Texas Delaware Basin. So we’ve mentioned, we've signed a purchase and sale agreement with EnerVest, we’ve mentioned that we have two acceptable bids on the other packages, and we are negotiating purchase and sale agreements there. So we would have loved to have been able to have all three come across the finish line by the end of the quarter, but just weren’t able to get there, but as Nick mentioned in his remarks, we expect to get those completed in the next 30 days or so.

Doug Leggate – Bank of America Merrill Lynch

So Aubrey you are very clear in the release that you sold the producing assets in the Midland, does that mean that there are still bunch of acreage, undeveloped acreage, still on the table?

Aubrey K. McClendon

Yeah, sure, Doug. we will have our remaining acreage in the Midland Basin to either develop ourselves or more likely to go through another process and look for a home for it, there are lots of different ideas there, private equity ideas, there are other producers who were maybe intimidated by the size of the package and now when you take the production out of it, I think we'll get some more kind of growth to the drill bit companies to come back and take a look at the acreage. So we’ve got a lot of options there, and it’s just kind of emerged in the last few weeks that we’ll go through frankly a fourth process to finish up basinal exit from the Midland side of the Permian.

Doug Leggate – Bank of America Merrill Lynch

Okay, I don’t suppose you’d care to comment on the $4 billion to $6 billion original range you gave relative to your, what you think you're going to realize?

Aubrey K. McClendon

Doug, no, we will continue to just let the process play out and as we have final numbers we will certainly share them with everybody.

Doug Leggate – Bank of America Merrill Lynch

Great. My only other one is really on the activity levels particularly in the Mississippi Lime. I guess similar kind of issue on the joint venture there, any update you can share there. But it also looks like you’ve lowered the rig count from the original planned to 18 versus I think it was 22 originally, so is it just better well results and if so are you prepared to take the type curve up. And just a general update on the Miss would be appreciated and I’ll leave it there. Thanks.

Aubrey K. McClendon

Okay, couple of things there. First of all, we have reduced the rig count in the Miss Lime but we haven’t done so in all of our plays. That’s just basically the scale down of our enterprise from – at the start of the year we were planning to run 200 rigs in 2013 and now we are planning to run 100. So we certainly needed to scale down.

In addition in the Miss Lime, we have decided to pursue [less just] (ph) pure HBP drilling and go into some core and some infill drilling there to help our returns and also to not get too far ahead of our infrastructure. You can spend a lot of money on infrastructure across a big area there.

With regard to EURs, last time I checked we haven’t taken them up although I noticed in what we call JV 1 area I think we are pushing 600,000 boe on the numbers that I saw, but I don’t think we’ve taken our pro forma up across the whole area.

Let’s see JV is still continuing our discussions, there is obviously private equity interest there, there is international interest. And we’ve also been approached for 100% exit some parts of the Mississippi as well.

So we will have lots of options there during the couple of months as we sort out what we want to do in that area. But we’re certainly pleased with our results and obviously watching EURs creep up from other players in the area as well.

Doug Leggate – Bank of America Merrill Lynch

Thanks, Aubrey.

Aubrey K. McClendon

Okay. Doug, thank you.

Operator

We will go next to David Tameron of Wells Fargo.

David Tameron – Wells Fargo

Hi, good morning. Asset sales, let’s go back to that. 2013 or two questions, one, the third quarter, does that include any assumptions for Mississippi Lime JV or is that pushed off for the time being?

Aubrey K. McClendon

I don’t believe that’s in our third quarter. That’s more of a fourth quarter expectation.

David Tameron – Wells Fargo

Okay. So then if I think about 2013, what packages, I mean what - the numbers you threw out for your asset sale target, what do you have, what would that be? Would that be – obviously, Chaparral is still out there, some of the services business, but can you talk about big picture, what would be included in that package?

Aubrey K. McClendon

First of all, it’s a much smaller number than we’ve been looking at this year. So you are right that Chaparral is out there, we’ve announced that we intend to sell a non-core asset like that, we’ve mentioned that we’d like to exit our investment in Frac Tech or FTS International at some point at well, and then we have our service company IPO that we have put-off to 2013. Beyond that I’m not going to say, but we have plenty of other bits and pieces of assets that we have that we’ll be shaving off to reach the goal of $4 billion or $5 billion in 2013.

I would like to emphasize as Nick mentioned that from a liquidity perspective, we don’t have to sell anything next year, but we certainly want to be able to continue to keep an undrawn revolver and associated with keeping our debt at the $9.5 billion level.

David Tameron – Wells Fargo

Okay. And then one more question, if I just look at what you did on the hedging side, it looks like you are kind of implying the 3, somewhere in the 3 to 3.25 is kind of where you think gas topped out at least for the remainder of this year. can you talk about, is that the right read on what you did based on your hedging and if so can you talk about your projections for the second half of the year, where you guys think gas…?

Aubrey K. McClendon

Sure. Yeah obviously, we had a nice run from the lows of late April to the above the $3 level. And I think we just wanted to be careful and conservative about our budget in the second half of the year, knowing that even with hot weather, we were going to be working off a lot of storage overhang, but there were obviously potential issues in September and October if storage got full, it looks like we’re probably going to avoid the storage box now. So we’re not intending to hedge anything at this point for 2013. At today’s levels, we don’t think there’s any chance that you have a 2013 strip that stays where it is today, if you have a complete reversal of the 900 Bcf overhanging it’s had in April of 2012, if you get the 900 Bcf storage deficits in April of 2013. But clearly you’re going to have to have higher prices in the $3 in 2013 to incentivize producers to come back. So for us, it’s got to be a pretty healthy price to pry our rigs away from our liquids production, our liquids focused areas. Steve, remind me, in 2013, how many rigs did we have allocated for dry gas?

Steven C. Dixon

Looks like eight.

Aubrey K. McClendon

So I think yeah, eight rigs out of the 100 in 2013 for dry gas. So this has been a four-year down cycle, and a lot of headwinds in the last four years. but we think a multiyear up-cycle is now underway, and frankly, all the die has been cast, Chesapeake’s is on the table, have been played and now it’s just a matter of physics and time for them to play out.

David Tameron – Wells Fargo

And just following up on those comments, do you have any feel for and I realize it’s play specific, but do you have any feel for where gas would have to get back to before you start to allocate away from liquids into - back to gas?

Aubrey K. McClendon

No, we’re not going to give out those kind of numbers, it’s different from play to play. But it’s a number, and I think the industry has said that the number is probably a north of $5 before gas plays generate the same kind of returns, which you can get from oil around $90. The Marcellus may be a little bit lower than that, but gas prices have a way to go to catch up to levels that equal the returns we get from our liquids-focused plays. And we’ll just wait for it to play out, and we’ve got enormous backlog of gas drilling opportunities, and we’ll take advantage of those when the gas market pays us to do so.

David Tameron – Wells Fargo

All right, thanks for the color.

Aubrey K. McClendon

Okay, David, thank you.

Operator

We'll go next to Biju Perincheril of Jefferies.

Biju Perincheril – Jefferies

Hi, good morning. A couple of questions, first in the Utica, in the oil window can you give us some color, how many wells you have now completed? And Aubrey, in the past you’ve said, Utica, it’s at least it’s as good as the Eagle Ford. Can you make that statement about if you’re only looking at the oil window of the two plays?

Aubrey K. McClendon

I don’t think I would make that statement comparing the oil plays, it’s just way too early on the Utica side, and we’ve not focused much of our efforts in that area, most of our acreage is in the wet gas and the dry gas side. So, we’re basically allowing other companies to work on the oil side; we’ve got plenty of acreage over there. But right now we love what we see on the wet gas side and frankly the dry gas side is just as good as the Marcellus. So we’re only drilling there, though where we kind of have to for acreage exploration issues. So we think when it's all said and done, the wet gas in the Utica, and the wet gas in the Eagle Ford are likely to be competitive. But I'm not willing to compare oil and oil yet because I just don't have enough information out of Utica. It goes without saying that we love what we’re doing on the oil side in the Eagle Ford.

Biju Perincheril – Jefferies

Got it. And the Eagle Ford, you’ve mentioned, I think 15% decline in cost, can you say what costs are running currently?

Domenic J. Dell'Osso, Jr.

Little over $7 million, right around $7 million per well.

Aubrey K. McClendon

Biju, did you hear that $7 million?

Biju Perincheril – Jefferies

Yeah.

Aubrey K. McClendon

Okay.

Biju Perincheril – Jefferies

Yeah, that's all I have for now. Thanks.

Aubrey K. McClendon

That's great, thank you.

Operator

We’ll go next to Charles Meade of Johnson Rice

Charles Meade – Johnson Rice

Good morning gentlemen. Couple of questions, if I could go back to that divestiture question for 3Q, you guys put in your headline for that section in the press release, a target of $7 billion. Am I right in that the two biggest pieces of that are number one, the Midstream, the remaining $2 billion Midstream sale to GIP and then the Permian sale, I guess the question really is, is there another big piece that’s going add up to that $7 billion?

Aubrey K. McClendon

Just to clarify, Charles, the $2 billion sale to GIP, that actually occurred in the second quarter, so it's done. What is projected in the third quarter is the remaining part of our midstream business, which is housed in an entity called CMD, that's our 100% owned Midstream. What got sold in the second quarter was CHKM now remain a CMP I think, access. So those are the two headline events in the third quarter and of course we will have some miscellaneous assets to sell off.

Charles Meade – Johnson Rice

Okay. Great, and then going back to the Utica, could you tell us what the lateral links were for those 28 wells that you highlighted in your focus area?

Aubrey K. McClendon

I don’t know if we’ve got it exactly but we can go ahead and tell him, what on average we do there.

Steven C. Dixon

Little over 5,000.

Charles Meade – Johnson Rice

Got it. And the TVD I know it kind of – it goes down as you descend into that gas window. But in general what’s the kind of that TVD range for the wet gas down to now?

Steven C. Dixon

6,500 to 7,000.

Charles Meade – Johnson Rice

Got it.

Aubrey K. McClendon

One of the attractive parts of that of course is we are now seeing wells get down to TD in 15 to 18 days something like that, so one could all the way drill the horizontal out. So as we really move into manufacturing mode there one of the advantages that the Utica will have over the Eagle Ford and some other plays will be that it’s a shallower and a bit cheaper.

Charles Meade – Johnson Rice

Well, and that’s exactly, you knew exactly what I was trying get to – are you prepared or do you have anything you’d share for what you think a development mode will cost you there?

Aubrey K. McClendon

That Steve can make a core estimate.

Steven C. Dixon

[It’s more like] (ph) down to about 6.

Charles Meade – Johnson Rice

Got it, got it. And then one other question for you Aubrey, is there anything that you can share about what the focus of some of the new Board members has been or what area is their attention has been drawn to or what questions that are top of mind for them?

Aubrey K. McClendon

Sure. We’ve only had one meeting to date. We just finished it last week. So it was a – we decided to have a mid-cycle meeting to get everybody acquainted with each other and they are looking at the things that you’d expect them to look at, the big topics for us, which are asset sales and CapEx, and efficiency of our operations. So that’s where the needle get’s moved and that’s obviously where their level of interest is.

Charles Meade – Johnson Rice

Great, thank you very much guys.

Aubrey K. McClendon

Okay, Charles, thank you.

Operator

We’ll go next to Neal Dingmann of SunTrust.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

So a quick follow-up Aubrey, just on the Utica, maybe for you or Steve, just wondering on those wells now, are you still I guess in that kind of wet window that you're drilling in letting most of those wells still rest after you complete those or what are you doing on that front?

Aubrey K. McClendon

Yes, sir, we are - most to these will come on - have been waiting on pipeline really for the most part, but yes, there have been having some set time.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

So you still believe, I mean – and is that kind of really going on - on a go forward basis, Steve you’ll continue to do that even if you have the takeaway you’ll continue to do that to a degree?

Steven C. Dixon

Neal, it ranges from dry towards liquids in the heavier oil and liquids, we think more benefit from it. So it will be a variable.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Got it, got it. And then just wondering on the Marcellus, you mentioned about the gas rigs you are going to let go. I think in the press release, so you talked about in the Marcellus having at least still six rigs going for dry gas, the reminder of ‘12. So would you let some of those go after ‘12, is that what that is implying or what will you do in that dry gas Marcellus window?

Steven C. Dixon

Yes, we think we can get down to four rigs there and hold our key acreage.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Okay, okay. And then just lastly, you just had a small increase, I noticed on the acquisition of unproved properties. Just wondering is that just bolt-ons or what was just the small add-in guidance on that part?

Aubrey K. McClendon

Yes, it's basically just accounting for the fact that we had to clean up a number of transactions in the Utica. I think Nick may have mentioned that about half of our leasehold spend for the 2012 is targeted for the Utica, I think another 25% for the Anadarko Basin including the Miss Lime and 25% spread everywhere else. so it’s dropping very dramatically. in fact, I think our first quarter’s leasehold spend was about $955 million, and dropped to $375 million or so in the second quarter, and we’ll continue to drop off quite remarkably dramatically rather, which I guess will be remarkable. But we’re targeting for 2013 a $100 million a quarter. and we think that maintenance mode will be even lower than that. I’d love to say, we could get to a lower number than that in 2013, we’ll certainly try to, but there’s still a lot of little holes out there, particularly in the Utica and often in the Marcellus as well, and it jeopardizes a much bigger investment when you fail to go out and kind of complete your unit. but in the Eagle Ford and most of our other plays really down to almost zero in terms of additional leasehold buys.

Neal Dingmann – SunTrust Robinson Humphrey, Inc.

Okay, thanks guys. Solid quarter, and great progress.

Aubrey K. McClendon

Okay, great, thank you Neal, I appreciate the support.

Operator

We’ll go next to Bob Morris with Citi.

Robert S. Morris – Citigroup

Good morning. Steve, a question on the rigs, you’re going to drop down to 100 rigs at year-end and that’s what you’re planning to hold that for next year. as I recall, 100 rigs is what Chesapeake own [at Ryder] (ph) under sale leaseback. So at that point, do you expect you’d just be running your own rigs and to drop out third-party leased rigs then by year-end?

Steven C. Dixon

We’ll still have some third-party rigs. and so we’ll have to stack some of our older mechanical rigs.

Robert S. Morris – Citigroup

Has Nomac tried to lease some of your rigs to third parties at this point or do you think you might be able to do that in the future?

Steven C. Dixon

Yes, sir. We have, I think 10 or 12 lease to others right now.

Robert S. Morris – Citigroup

Okay, all right. Thank you.

Aubrey K. McClendon

Bob, thank you.

Operator

We’ll go next to Jason Gilbert of Goldman Sachs.

Jason Gilbert – Goldman Sachs

Hey, good morning, guys. Most of mine have been asked already. I was wondering, I think you had mentioned in the past your desire to do a couple more JVs in the Utica, just wanted to hear what your latest thinking was there?

Aubrey K. McClendon

Certainly, Jason, we’ll do at least one in the dry gas part of the play, and we’ll wait till 2013 though to do that when we’ve got better gas prices. So that is certainly one of the assets sales that we have in mind for 2013.

On the oil side, it just remains to be seen, if the results allow us to do that and we also have a couple of other JV ideas out there. So we think the JV market is still strong, and it's been supplemented by the interest of private equity players during the past year or so. It’s probably been the biggest change in the market out there in the past year, which is the arrival of frankly several tens of billions of dollars of assets that private equity players have brought to the table.

Jason Gilbert – Goldman Sachs

Thanks. And then my second one was, on the spending guidance increase you mentioned in the comments that were just spillover from late '11 and early '12?

Just sounds like inertia, really. But if I remember correctly, you had reiterated your guidance as recently as July in the investor presentation, which maybe suggests to me that you don't always have a lot of visibility with this. And I was just wondering if you can say with confidence that these spillover costs are now behind you and that we’re over the hump on the CapEx increases.

Aubrey K. McClendon

We really think they are, and in terms of affirmation in July, I don’t remember that so much other than we only change our guidance once a quarter. So in July it would have been what we put out in April, and so we kind of just live with it till we have a earning into the quarter earnings release like we have now. So this is obviously something that we scrub very hard, we’re not happy about the increase, and really determined that with our new numbers that they are numbers that we can not only meet but to live with them.

Jason Gilbert – Goldman Sachs

Great, thanks. I’ll turn it back.

Operator

And we’ll go next to Scott Hanold of RBC Capital Markets.

Scott Hanold – RBC Capital Markets

Good morning.

Douglas J. Jacobson

Hi, Scott.

Scott Hanold – RBC Capital Markets

So on the 100 rigs you’re going to be running in 2013, how many of those do you think are going to be HBP versus drilling for economics?

Aubrey K. McClendon

First of all, I’d say that even if it’s drilling to HBP acreage, I mean it will be an economic activity, but I think I understand your question, certainly well that – is the second or third well in the unit and is likely to be better than the first well. So, Steve do you have an estimate of that or not?

Steven C. Dixon

Fairly small percentage, we are focusing in the core, like you said HBP-ing within the core, but not necessarily multiple wells within the unit.

Scott Hanold – RBC Capital Markets

So as most of your, I guess – if you look at your leasehold, how much do you think with the reduced rig count is, I guess the term would be at-risk for exploration or is some of the stuff that could expire in that stuff that could be potentially up for an asset sale and/or you may not want it anyway?

Aubrey K. McClendon

I think that’s really the right way to think about it. Scott, one of things we’re doing is not only selling assets that are not core, but also looking at our 10 core areas, and determining what we just don’t have the capital to get to, and what we don’t have the time to get to.

So I think you will see us sell some of our leasehold in plays that are absolutely core to us, and over the next six months or so as we recognize that, we have acreage that may fit other companies better or we have acreage that would expire unless we went and drilled it.

So as we pull in our horns and focus and concentrate our drilling in areas that are going to generate the highest returns, it’s a very different strategy than what we viewed for last few years, which is to lock down this asset base that we’ve taken from being a temporary asset base subject to exploration to a permanent asset base.

And so for example nobody today thinks a whole lot about value from the Haynesville but we’ve had something like 7,000 wells to drill in the Haynesville that are HBP, so that are future drilling opportunities on acreage that’s been HBP. So that’s - I don’t think it’s fully baked in our forecast going forward, the increases in efficiency that are going to be generated, and certainly the increases and returns on investment as we continually move towards a program of drilling wells that will be on acreage that’s already HBP rather than on acreages that’s just sitting out there to be drilled at some point.

So stay tuned for other areas or parts of our core areas that we might be willing to let the rest of the industry take a look at rather than spend our own capital chasing those opportunities to HBP further acreage.

Scott Hanold – RBC Capital Markets

Okay, I appreciate that. And one follow-up, just so I understand that’s right. So when you look at your drilling CapEx in 2013 being down $750 million, I mean when I look at that, how much is related to just better drilling efficiencies, versus a planned further reduction to rig count versus I guess changes in planned asset sales or divestitures?

Aubrey K. McClendon

And there is certainly some associated with efficiency and hopefully some cost savings as well as obviously the price of fracs have come down in other parts of the drilling and completion operation, but mostly it just drop of rigs as we move down to 100 rigs for 2013.

Scott Hanold – RBC Capital Markets

Okay, so most of the stuff you directly could control in theory?

Aubrey K. McClendon

We’re not saying that we’re going to assume there is a 15% efficiency factor and that allows us to drop our CapEx by 15% or something like that; it’s really related to rigs and if we’re able to drive efficiencies higher, if we are able to drive cost lower than that hopefully will be icing on the cake for us.

Scott Hanold – RBC Capital Markets

Thanks guys.

Aubrey K. McClendon

Thank you. Scott, one other thing I might – mentioned, as you lower your cycle time, you can drill more wells, with the lower number of rigs, so for example in the Eagle Ford as we drop I think, Steve, we’re scheduled for 25 in 2013. Is that right?

Steven C. Dixon

No.

Aubrey K. McClendon

22, sorry.

Steven C. Dixon

22, and we are already seeing lots of wells in the teens and so I hope that that can go down even more, 22 rigs (inaudible).

Aubrey K. McClendon

22 rigs. [Ultimate] (ph) number of rigs [rather than] (ph) days, so the point is that as our efficiencies get higher, we can reduce the number of rigs and our CapEx may not go down, but your return on that investment will go up as you get more wells drilled with the same number of inputs.

Scott Hanold – RBC Capital Markets

Got it, thanks, guys.

Aubrey K. McClendon

Okay, thank you, Scott.

Operator

We will go next to Matt Portillo of Tudor, Pickering, Holt.

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

Good morning, guys. Just a couple quick questions from me, just a quick follow-up on the Eagle Ford question. Could you give us an idea, I think in the second quarter you guys drilled around 121 wells in the Eagle Ford versus the first quarter of 62. What’s the – I guess the expected run rate over the next few quarters in terms of completions in the Eagle Ford? And then I guess kind of once you get down to 22 rigs in 2013, what would be a normalized quarterly well count for you there?

Steven C. Dixon

Matt, this is Steve. It should be similar to this, low 30s per month [turn] (ph) in line base.

Aubrey K. McClendon

The way I’d like to think about, Matt, during the last quarter we completed a Eagle Ford well every 18 hours and going forward, I think we can probably do better than that.

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

Perfect. And then just in terms of the wells you put in the release, obviously a lot of detail on kind of the larger category of wells here, with I think peak IPs of around 500 barrels a day equivalent. Could you give us an idea of roughly what the 30 day rates look like there, and maybe just your new expectations around what the EUR would be?

Aubrey K. McClendon

I think Steve can help you with both of those. Matt, while he is looking do you have anything else?

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

Yes, sure, just two final questions from me. On the CapEx side, just curious on 2013 if you were to, at high enough gas price, desire to flat line your gas production next year what sort of capital increase would we need to see on your development budget to get to that level of flat production?

Aubrey K. McClendon

That’s a good question Matt. I don’t have that right now, but we can certainly dial it up for you. Again, it would take quite a bit stronger price than what’s in the forward curve right now for us to be interested in doing that, but clearly, we have the assets to do it now and have the capability to do it.

And remember, this is a issue where I think a lot of investors and analysts perhaps think about it in the abstract or in a vacuum which is what’s a gas price that gives you a reasonable rate of return on a well in the Marcellus or Haynesville or Barnett. and that’s only part of the equation. The other part of the equation is capital is finite obviously. and so you have to not only generate an attractive return, but you have to generate return as competitive with your other returns.

So it’s not do we make money at $4 gas or $5 gas, it’s do we make as much money drilling the gas well at that price compared to what we make drilling an oil well at $90 a barrel. And so that’s I think a part of the equation that’s missing for most people’s analysis of the gas market going forward. Steve, do you have anything to follow-up with on?

Steven C. Dixon

Yeah, I mean we actually break the Eagle Ford in multiple pro formas because we’re wet gas, [oil and the shale oil] (ph) but the blend is about 9,000 barrels for first month.

Aubrey K. McClendon

Anything on NGLs or gas? we don’t produce a whole lot of gas out there. I let him continue to look, and we can come back, and given that we’re kind of over our hour I don't know how many folks are left to answer your questions, but we’re - in courtesy to everybody, we’re going to take two more questions and then if for some reason, you didn’t get a question asked and answered, please dial it in to Jeff, John, or Gary and they’ll get back to you. Operator, we’ll take two more please.

Operator

Yes sir. We’ll go next to Bob Brackett of Bernstein Research

Bob Brackett – Bernstein Research

I had a question on the Utica, two-part, one is that it looks like you had a well producing in the Tuscarawas County, which is pretty oily. any color on that would be appreciated. And also ignoring land retention, where would you put that last rig, in the Miss Lime or in the Utica?

Aubrey K. McClendon

That’s tough man. First of all, good morning to you, let’s see I would say right now, Carroll and Columbiana counties are tough to beat. On the Utica, Alfalfa and Woods are tough to beat in the Miss Lime. So I’m not going to declare a winner between those two, but I would say that each of them has a little bit of HBP work to be done in those counties probably more to be done in Carroll and Columbiana, than in Alfalfa and Woods. But that’s a – we will go back and play with that a little bit, but both of those are very, very attractive areas and hopefully we’d end up being very competitive with any – for any incremental capital.

Bob Brackett – Bernstein Research

And that Tuscarawas county well.

Aubrey K. McClendon

Yeah, I’m not – do you have a name for it?

Steven C. Dixon

Yeah, I’ve got that, they came on about 227 barrels of oil a day and 1.3 million.

Aubrey K. McClendon

What’s the name of the well?

Steven C. Dixon

Gribi.

Aubrey K. McClendon

Yeah.

Bob Brackett – Bernstein Research

Okay. And are you guys looking to get any new plays or is that pretty much done?

Aubrey K. McClendon

We’re pretty much done. We have an acreage position in an area that we’ve not talked about. Probably that I’ve mentioned a little bit about a year ago. We still continue to poke around there. It’s pretty cheap area there and we will get some wells drilled or tested in the next three to six months and see if it’s something worthwhile or not. But we haven’t spent much money there to-date and if it becomes a core area for us, great, if not, we will be happy with the 10 that we have.

Bob Brackett – Bernstein Research

Thank you.

Aubrey K. McClendon

Okay. Bob, thank you.

Operator

And we will take our final question from Joe Magner of Macquarie Capital.

Joseph Magner – Macquarie Capital Markets

Good morning. Thanks for taking my question. Just any update on the divestiture efforts for the DJ and Utica properties that were announced over the last couple of months?

Aubrey K. McClendon

I don’t think so, but those would both be pretty – well, DJ would be modest I think given our lack of success in that area and the industry hasn’t done well outside of Wattenberg. So we’ll get what we can there and move on.

Utica [French] (ph) process is underway. We’ll have something to say there in the next couple of months as we definitely will have successful leasehold sales in that area. And the Utica is clearly an area of intense interest for the industry. Given our first mover status there, a lot of people who want to establish positions come to see us. So we look forward to sharing some good news there later.

Joseph Magner – Macquarie Capital Markets

Okay. And along the lines of Utica, can you update us just on takeaway capacity, what we might expect to see some of those – I guess, wells could turn to sales and production start to ramp up there?

Aubrey K. McClendon

Mostly in 2013, but Nick, if you want to address that or Steve, you want to address that, we’ve got a big program there underway and kind of lost track with all the different entities involved but you want to try and put that up?

Domenic J. Dell'Osso, Jr.

Well, I don’t have any real specific dates other than there is one big infrastructure project underway and we’re have it all mapped out and looking forward to bringing on more wells. We’ve been trying to focus our drilling as close to existing pipelines as we can, and so we are doing our best to minimize it in the meantime, but there is lot of infrastructure added to the Utica.

Aubrey K. McClendon

Yeah, processing, there is going to be NGL takeaway adds in their projects, one that go to Philadelphia projects, one that go to Belvieu. So we are going to be a foundational shipper likely in any project that originates from the Utica. So there is going to be plenty of liquids there and we think plenty of opportunities to get the Belvieu pricing or Belvieu equivalent pricing over time.

Joseph Magner – Macquarie Capital Markets

Okay. And just one last one. Nick, any anticipated amount for the ceiling test write down in the third quarter and could you provide us with what I guess where the cushion sits (inaudible)?

Domenic J. Dell'Osso, Jr.

No anticipated amount, there is too many in and outs between now and then to give a number even within a range. So I’d like to hold off on doing that right now. And the cushion is pretty significant in my view, but I don't think we’re prepared to disclose what that is today.

Joseph Magner – Macquarie Capital Markets

All right, that's all I have, thanks.

Aubrey K. McClendon

Okay Joe, thanks for your questions. And thanks to everybody else. And again if you have additional questions send them in to our IR team, they will get back to you shortly. Thanks again. Bye, bye.

Operator

This does conclude today's conference. We appreciate everyone's participation today.

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