Chesapeake Energy Corp (CHK) 2011 Q4 法說會逐字稿

Good day, and welcome to the Chesapeake Energy 2011 fourth-quarter earnings results conference call.

Today's conference is being recorded.

At this time, I would like to turn the call over to Jeff Mobley.

Please go ahead, sir.

Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2011 fourth quarter and full year.

I would like to begin by directing your attention to the slide presentation available on our website that we will refer to in our prepared remarks this morning.

The slides can be accessed at www.chk.com, then selecting the Investor tab near the top of the page, followed by the Presentations section in the menu bar.

I would next like to introduce the other members of our management team who are with me on today on the call.

Aubrey McClendon, our Chief Executive Officer; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and John Kilgallon, our Director of Investor Relations and Research.

Our prepared comments today will be a bit longer than our typical call, as we have added additional detail on our operational performance that will be highlighted by Steve Dixon.

We will then move to Q&A.

I would now like to turn the call over to Aubrey.

Thank you, Jeff, and good morning.

We are very pleased with our Company's operational and financial performance during 2011.

Here are a few highlights to consider when analyzing our performance for the year.

Turning to slide number two, for the full year, we increased our production by 26% before asset sales and 15% after asset sales.

Chesapeake remains the largest gas producer in the US on a gross basis and the second-largest on a net basis.

More importantly, we moved up to the 11th largest oil producer in the US during 2011 from the 15th largest in 2010 and from the 21st largest in 2009.

We increased our proved reserves by 26% before asset sales and 10% after asset sales, and we now have proved reserves of approximately 19 Tcfe, or the equivalent of 3.1 billion barrels of proved reserves.

We found through the drill bit a remarkable 5.6 Tcfe of proved reserves at the very low drilling and completion cost of only $1.08 per Mcfe.

Stated on a BOE basis, we found almost 1 billion barrels of oil organically.

These results are unmatched in the industry and form the core of our ability to continue creating shareholder net asset value every year of at least $10 billion.

Chesapeake's risked unproved resources are now in excess of 110 Tcfe, and between our proved reserves and unproved resources, we control more oil and natural gas resources in the US than any other company.

Based on our present market valuation, this unproved resource base is, quite amazingly, available free of cost to our investors.

During 2011, our net long-term debt on an absolute basis declined by 18%.

And on a relative basis, which includes the benefit of the growth of our proved reserve base, net debt per proved reserves declined by 25%.

Further, we believe approximately $1 billion of our total long-term debt should be reasonably allocated to our Midstream and oilfield service businesses.

After this allocation, our E&P debt is only $0.49 per proved Mcfe, which is clearly an investment grade metric, and is in fact lower than at least one of our investment grade-rated peers.

We are focusing on creating per share value for our investors, and so we are proud to deliver strong operational and financial performance without incremental equity from the public markets.

During 2011, our fully diluted share count increased by only 0.6%, which is solely related to employee stock compensation.

I believe we still remain the only large cap E&P company that distributes restricted stock to virtually all of its employees; in our case today, nearly 13,000 people.

I believe this practice at least partially accounts for the hard working, creative and motivated organization that we have built.

Speaking of which, on slide number three, I am proud to highlight that recently Chesapeake was named by Fortune Magazine as the 18th best company to work for in the US, including the fifth best among companies with more than 10,000 employees.

In addition, we were number one among all companies in the oil and gas business.

This is our fifth consecutive year on this prestigious list, and we have moved up from number 61 to number 18 in those five years.

I would also like to mention that our fellow Oklahoma City producer, Devon, is ranked number 28 on the list.

That means that of the more than 400 publicly-listed oil and gas producers in the US, only three made the top 100 best companies to work for, and two of those three are located right here in Oklahoma City, a very noteworthy achievement for our community.

Turning to slide number four, during 2011, we sold assets for $8.5 billion, reaping pre-tax economic gains of $5.6 billion from those sales, or a profit margin of approximately 65%.

Please note, however, that because of the conservatism of full cost accounting, only $437 million of those gains appeared on our income statement.

On a percentage basis, our liquids production increased by 72% in 2011 versus 2010.

This is the second best track record of oil production growth in the industry on a relative basis.

On an absolute basis, our liquids production increased by 36,000 barrels per day, also the second best performance in the industry.

Further impressive liquids production growth lies ahead for Chesapeake.

For 2012, we believe our liquids production will increase by more than 70%, or approximately 63,000 barrels per day, compared to 2011.

We remain convinced that Chesapeake will become a top-five producer of liquids in the US by 2015 with more than 250,000 barrels per day of liquids production.

Moreover, on slide five, we announced our 25/25 plan in January 2011 that stated we would reduce our net long-term debt by 25% and increase our production by 25% during 2011 in 2012.

I am pleased to report that during 2011, we achieved 72% of our debt reduction target and 60% of our original production growth target.

With regard to unproved leasehold, always a popular topic among observers of our Company, we invested $3.5 billion during the year and collected $4.4 billion in sales of unproved leasehold, resulting in a net cash unproven leasehold inflow of $900 million.

At the beginning of the year, I committed that our undeveloped leasehold sales would be at least equal to our undeveloped leasehold acquisitions during 2011.

As you can see, I was off by $900 million, but off to the good side.

I further commit that in 2012 and 2013, we will also likely generate more cash from undeveloped leasehold sales than we will spend in undeveloped leasehold.

Please keep in mind these numbers are cash only and exclude the benefit of drilling carries that we receive when we sell portions of our undeveloped leasehold.

If we included carries in our calculations of leasehold sales, these numbers would obviously look even better.

The final takeaway, I think, on leasehold investments should be this.

Whatever we spend on leasehold acquisitions in a given year, we will more than offset it from undeveloped leasehold sales.

How are we able to continue doing this, you might ask?

It is actually quite simple.

Chesapeake is the best in the industry at finding new, unconventional plays, acquiring big leasehold positions in the heart of the plays and then selling off a minority interest to a bigger company from elsewhere in the world that cannot do what we do, but has access to capital that we do not have.

These are truly symbiotic relationships that benefit both companies, and I'm proud to say Chesapeake was the first to recognize this extraordinary business opportunity back in 2008.

To date, we have entered into seven JVs that have generated $7.1 billion in cash from undeveloped leasehold sales and $9 billion from drilling carry, for total value generated of $16.1 billion.

Our cost basis in the assets sold was only $3.8 billion.

That's an economic profit of $12.3 billion, or more than a three-to-one return.

However, again, due to the conservatism of full cost accounting, none of these gains are presented in our income statement.

Turning to slide six, during 2011, we were the first company to establish commercial production from the Utica Shale, the first big new shale play since the Eagle Ford was discovered in 2008.

We are very excited about the Utica, our results to date and its future potential.

Steve Dixon will have some new well results for you from the Utica in a few minutes.

To date, we have invested approximately $2.2 billion in the play and have sold off roughly 20% of our leasehold, for total cash and carry value of about $2.3 billion.

Said another way, we recovered 105% of our costs to date and yet still have 80% of our acreage left.

That is exceptional under any circumstances, but especially when you consider that Chesapeake's average holding period in its Utica leases is only about one year.

On slide seven, I wanted to point out that in 2011 we generated gains of $437 million from a drop-down transaction with our Midstream affiliate, CHKM, that trades on the New York Stock Exchange.

Please remember that most of our peer companies, unlike CHK, fail to capture midstream profits for their shareholders.

We believe this is a very key element as to why Chesapeake's integrated business strategy is a superior business model.

Also during 2011, we formed COS -- that is Chesapeake Oilfield Services -- a company that holds our various oilfield service businesses.

Inside of COS, we own nation's fourth-largest drilling contractor, the nation's largest oilfield trucking company, one of the nation's largest oilfield tool rental businesses, and we are also building under the name of Performance Technologies Limited, or PTL, what will become a top-five fracture stimulation company.

We now have two PTL frac crews in the field, and by the end of 2012, we will have a total of eight frac crews active.

And by the end of 2013, we will have a total of 12 crews in the field.

We believe that by having Chesapeake's own in-house fracing capability it leads to greater efficiencies and lower costs.

We believe COS will make an excellent candidate for an IPO later this year, and it is another example of the benefits of Chesapeake's vertically integrated business strategy.

Also in the service industry, with strong support from Temasek and RRJ Capital, we helped recapitalize Frac Tech Services in 2011, which is today the fourth-largest fracture stimulation company in the US.

We own 30% of this fine company, and have a cost basis in it of only $100 million, meaning we have an embedded profit that will likely exceed $1 billion.

Slide number eight shows that our commodity hedging program generated strong gains again this year.

After our gains of $1.6 billion in 2011, we have now generated $8.4 billion of hedging gains in just the past five years, by far the best track record of hedging success in the industry.

And finally, even in the face of sharply lower natural gas prices, our 2011 adjusted EBITDA and cash flow increased by 6% and 3% compared to 2010's numbers.

We think this is a pretty extraordinary achievement, given what happened to natural gas prices in 2011.

On slide nine, during the year we also continued our industry-leading effort to increase demand for natural gas.

One such project was to help lead $400 million of investments through multiple transactions in Clean Energy Fuel, stock symbol CLNE on the New York Stock Exchange.

Clean Energy is the nation's largest provider of natural gas as a transportation fuel and they have very strong momentum in building out the infrastructure for America's natural gas superhighway.

I can assure you that the move is underway to move the nation's transportation sector increasingly away from imported diesel and gasoline towards domestically-produced and much cheaper natural gas.

You might also take note of yesterday's press release, in which the 3M Company and Chesapeake agreed to jointly deliver a breakthrough in CNG fuel tank technology that will help lower the cost of natural gas vehicles.

Also, for the benefit of our entire industry, we have curtailed approximately 15% of our gross operated production, or approximately 1 BCF per day.

Our share of this curtailed gas is about 50%.

This is, of course, far more than anyone else in the industry has announced, and we think it speaks volumes about Chesapeake's financial flexibility and operational strength, that we can make this sacrifice and still reach all of our objectives for the year.

On slide number 10, the most important element of our ongoing success is Chesapeake's very high asset quality.

I am proud to report that Chesapeake now owns the largest or second-largest positions in the following 15 leading US unconventional plays.

Starting first with gas shale plays, we are number one in the Haynesville, number one in the Bossier, number one in the Marcellus and number two in the Barnett.

Moving to liquids-rich plays, we are number one in the Utica, number two in the Eagle Ford Shale, number one the Cleveland tight sands, number one in the Tonkawa tight sands, number one in the core area of the Granite Wash, number one in the Mississippi Lime and number one in the Powder River Basin Niobrara Shale.

And in the Permian Basin, we believe our overall acreage position of 1.5 million net acres is tied for the second-largest in the Basin.

In this largest oil-producing basin in the US, and arguably the hottest basin in the world, we have leading positions in the Wolfcamp, Avalon, Bone Spring and Wolfberry plays.

So even if we were to sell 100% of our Permian Basin assets, Chesapeake would still retain a number one or number two position in 11 of the nation's best gas and liquids-rich plays.

We are not aware of any other company that can claim more than two or three of such positions.

Reviewing this extraordinarily high quality lineup of assets, it should be no surprise to you that Chesapeake has single-handedly generated 30% of all the natural gas production growth in the US during the past five years.

It should also help explain how we have increased our liquids production by 170% in the past two years and how we intend to increase it by a further 190% in the next four years.

As a result, we believe Chesapeake will likely turn in the best liquids production growth performance in the US and one of the best in the world during the next few years.

On slide 11, we enter 2012 with strong momentum and sound business strategy to continue making the shift from a 90% natural gas producer in 2009 to a much more balanced producer in the years ahead.

However, we acknowledge that this shift away from gas to oil has required us to outspend our cash flow, and we also acknowledge this has caused anxiety among some investors and observers of our Company.

However, with our detailed announcement of February 13, we have now clearly articulated a strong plan of action that should enable us to generate $10 billion to $12 billion of proceeds from asset monetizations this year, that, when combined with our operating cash flow, will easily fund the gap between our operating cash flow and our capital expenditure spending for the year.

It will also probably pre-fund any gap in 2013 as well -- which will be much smaller, by the way than this year's gap, as natural gas prices will likely increase as supply growth wanes and demand growth comes on strong.

More importantly, Chesapeake's production mix will continue to tilt towards more liquids production, and therefore will generate more revenue per unit of production.

By 2014, we are confident the Company will have reached breakeven between its operating cash flow and capital expenditures, even if natural gas prices remain at depressed levels, which given the rapidly changing supply and demand fundamentals emerging in real time before us today, we think is very unlikely.

However, despite the obvious very good place where we are headed with our surging liquids production and despite the obvious very bad place we would be if we had simply stayed within our cash flow and remained a 90% natural gas producer, I still read a surprisingly large amount of analyst commentary that remains singularly and, in my opinion, unimaginatively focused on how much CapEx we have spent.

Our job as the management stewards of shareholders' capital is to create the highest amount per share net asset value possible within our overall financial capabilities.

That is why we focus on the outputs of our business, while it seems other people seem to obsess over the inputs to our business.

But it is not the inputs that matter at the end of the day; it is the outputs.

And our outputs are not only increasing in size, but also increasing in value on a per unit of production basis.

By achieving this quite remarkable and utterly complete transformation of our Company in just three years, we will arrive at a place in 2014 when we are cash flow positive, and to a place in 2015 when our cash flow should be $10 billion to $11 billion and our Company will be valued at several multiples higher than our total enterprise value today.

This will create enormous value for our shareholders in the next few years.

Again, if inputs were the only thing that mattered, then we would live today within our cash flow, and sit here and hope and pray for higher natural gas prices.

But it is indeed outputs that matter, and so that is what our focus is on -- to increase those outputs and total volume and to increase the per unit value of those assets -- or outputs, rather -- while at the same time delevering the Company by 25% on an absolute basis and close to 40% on a relative basis in just two years.

And by the way, we will get all this done in an environment of sub $3.00 natural gas prices.

It is not easy, and I read that several analysts this morning are skeptical about our ability to achieve this transformation.

But their skepticism will not be rewarded at the end of the day, while indeed our shareholders will be greatly rewarded.

I will now turn the call over to Nick for his further comments about the Company's financial performance.

Thanks, Aubrey.

It has been an exciting start to 2012, and we are very pleased about where we are headed.

First, to cover our Q4 and full year results, I would like to point to our $2.80 per share in EPS, driven by production growth and cost control.

Our LOE for the fourth quarter came in at $0.88 per Mcfe, a decrease of $0.02 per Mcfe over Q4 2010.

In addition, current year LOE includes approximately $0.11 per Mcfe from the effects of EPPs.

This is evidence of some of the efficiencies we've been able to create within the country's largest drilling program and vertically integrated model.

We do expect this metric to pick up a bit in the future as producing oil and NGLs is more expensive.

However, we are quite proud of the base from which we will grow, and will continue to take advantage of our model to deliver a best-in-class cost structure.

From a balance sheet perspective, our production and year-end debt balance show great progress towards our 25/25 plan.

One quick note I would like to add to the previous comments on our production growth target moving back to the original 25% level as a result of our curtailment decision is that in our outlook on Schedule A of our earnings release, we note a total assumed curtailment of 130 Bcfe during 2012.

If we had chosen to produce the curtailed volumes, we would've achieved an additional 13% production growth, or total 38% production growth from 2010, a remarkable level for a company of our size.

We will certainly be poised to take an advantage of rebounding gas prices when they occur.

It has been our strategy to continue executing on two of our primary goals in 2012, increasing oil and liquids production and decreasing our financial leverage.

We made the decision to stay the course on these goals, even in the face of low natural gas prices, as we feel achieving a balance in our production profile and decreasing leverage are key to growing long-term shareholder volume.

As a result, as Aubrey mentioned earlier, we have been planning to outspend our operating cash flow this year.

We were pleased to provide more transparency on how we plan to do that last week with our announcement regarding the significant asset sales and other monetizations we plan to pursue in 2012, and hope that the table at the bottom of our 2012/2013 outlook makes all of our investing activities for the year very clear to you.

This summary of cash inflows and outflows should highlight that we have given ourselves quite a bit of headroom in 2012, and inclusive of that carryover, will have quite a bit in 2013 as well.

To clarify a few things we read last night and this morning, we have made very little material changes to CapEx, and only tried to provide more detail and transparency through the view on what is being spent and what is being monetized.

We, of course, have been working on these monetizations announced last week for quite some time, and always maintain a good amount of optionality in how we think about funding our business, given our asset-heavy business model.

Our diversity of assets, which include proved reserves, natural gas and oil production, large acreage positions and vertically integrated Midstream and Service company investments, provide a variety of assets for which there are many different buyers that can find attractive assets within our portfolio.

Great examples of the variety of assets we choose to monetize to buyers seeking different return profiles are our Colony Granite Wash Royalty Trust, where primarily retail investors receive an income stream tied to the specific production of a certain field, and our Utica West gas JV, where an international major took a significant exposure to a largely undeveloped play in Ohio with tremendous upside exposure.

Further in the outlook in our press release today, I will point out that we have lowered our gas price forecasts to more closely match the strip, and now project 2012 operating cash flow before changes in working capital to be $4.85 billion at the midpoint of our range.

Please remember that approximately 60% of our revenue in 2012 will come from oil and natural gas liquids at the prices modeled here, and we've hedged 43% of that production at approximately $102.50 per barrel.

Also, please note that our operating cash flow projections are expected to increase by 65% in 2013 versus 2012.

If you look at slide 15 in this morning's presentation, you will see that even if prices were to remain flat, our cash flow will jump by 35%.

That is very exciting growth and really highlights the benefits of our shift to liquids-focused assets and the return we are seeing on our investment in liquids-rich acreage positions the last several years.

With that, I will turn the call over to Steve to give an overview of some of our recent significant operational achievements.

Thanks, Nick.

Moving on to slide 17, 2011 marked another outstanding year for Chesapeake operationally.

We are very proud of the results in 2011 by our entire team as we continued our best-in-class performance and in reserves and production at a very low cost, while maintaining our high standard for safety and a keen focus on environmental stewardship.

During 2011, we produced nearly 1.2 Tcfe on a net basis and increased our gross operated production to 6.4 Bcf per day.

We finished the year with 18.8 Tcfe of proved reserves, based on SEC pricing, and that is after sales of 2.8 Tcfe of proved reserves, primarily from our Fayetteville Shale transaction with BHP.

Our operational teams performed exceptionally well during a rise in oilfield service cost environment in 2011.

And we delivered 5.6 Tcfe of proved reserve additions through the drill bit at a drilling completion cost of only $1.08 per Mcfe, or approximately $6.50 per BOE.

Notably, our reserve additions in just that in year, 2011, exceeded the total proved reserves of all but just a handful of our competitors, many of which have been in operation for more than 20 years.

As an operator, we drilled a total of 1680 gross wells and connected more than 1400 wells, or about one every six hours.

And substantially all of these were horizontal wells.

This is an unprecedented level of activity, performance the industry has never seen before.

We have also participated in another 1250 wells drilled by others, and those operators turned 1050 wells online during the year.

Slide 18 shows in executing its business, Chesapeake enjoys tremendous competitive advantages through the size and scale, but also by utilizing the largest data set in the industry that benefits from - the most active drilling program in America, the largest US leasehold position and the unique ability to evaluate technical and petrophysical data at our Reservoir Technology Center, that has analyzed more feet of shale core since its opening in April 2007 than the rest of industry combined.

Our company has developed key abilities in new play identification, leasehold acquisition, large-scale drilling and completion programs, where we have ramped up to 20, 30, even 40 rigs in a single play.

Our operations are further enhanced by our vertical integration into Oilfield Service and Midstream operations.

Our goal in the end is to conduct our operations better, faster, cheaper and safer than our competition so that we can lead the industry at per-share net asset value creation.

As a result, Chesapeake has clearly become the partner of choice for many international companies seeking access to the lucrative, low-risk US onshore natural gas and liquids plays.

And we look forward to completing additional partnerships in transactions later this year.

I would next like to highlight a few operational results in some of our key liquids-rich plays.

On slide 19, in our Eagle Ford Shale play, our total net production averaged over 17,700 BOE per day in 2011's fourth quarter.

That is up 60% versus last quarter and 370% year-over-year.

Our current gross operated production from the play is 45,500 BOE per day and 22,600 BOE per day on a net basis.

Our production mix in this play is approximately 50% crude, 20% NGLs and 30% natural gas.

We continue to be very pleased by our performance in the Eagle Ford, and it is a driving force behind our liquids production growth targets in the months and years ahead.

To date, we have 108 wells that tested with peak oil rates of 500 barrels of oil or more.

And that is not on an equivalent basis; that is black oil in the tanks.

We are producing 178 wells in the play to date and have a backlog of almost 200 additional wells to be completed and connected in the coming months.

This will fuel our production ramp-up through the end of the year and into '13.

We finished 2011 with seven frac crews running in the play, and we will be up to 11 by mid-March of this year and 13 by the end of 2012.

We have also doubled our drilling efficiency in the play.

Since January 2010, based upon drilling feet per day, we're now at approximately 725 feet per day, and this has driven down our days between wells and helped reduce cost.

Great progress has been made in building infrastructure in the play with the addition of 350 miles of pipeline during the year.

We expect to gain greater transportation capacity as 80 more miles of pipeline and regional rail and loading terminals are put in.

And we also are adding 85 oil-hauling trucks from Chesapeake's very own trucking company within Thunder Oilfield Services.

These actions help ensure that our oil moves to markets that give us the highest oil price possible.

I would next like to focus on the Anadarko Basin, where we dominate several very successful liquids-rich plays, including the well discussed and prolific Granite Wash plays.

For this call, though, I would like to highlight three plays that we previously have not highlighted in detail for competitive reasons, the Miss Lime play in northern Oklahoma and southern Kansas, and the Cleveland and Tonkawa plays in western Oklahoma.

In the Miss Lime on slide 20, our total net production averaged over 10,500 BOE per day in the fourth quarter.

That is up 31% compared to last quarter and up 141% compared to the period last year.

Our current net production is 11,300 BOE per day.

Our production mix in the play is approximately 40% crude oil, 15% NGLs and 45% natural gas.

The play is one that Chesapeake discovered with the industry's first horizontal well drilled here in 2007, and today, it is dominated by Chesapeake and our friends at SandRidge.

We continue to drill prolific wells across a wide area in Alfalfa and Woods counties in Oklahoma.

We are currently operating 22 rigs in the play and will maintain that level through 2012.

To date, we have participated in 33 wells that have tested peak oil rates of 500 barrels of oil or more.

We previously announced to you our intention to bring in a JV partner in the play and hope to have a successful transaction to share with you later this summer.

Next, I would like to cover the Cleveland and Tonkawa plays on slide 21, where we also have a dominate acreage position.

Our total net production from these two plays averaged nearly 18,000 barrels of oil per day in the 2011 fourth quarter.

That is up 20% compared to the last quarter and up nearly 125% compared to this period last year.

Our production mix in this play is 50% crude, 15% NGLs and 35% natural gas.

To date, we have participated in 70 wells that tested with peak oil rates of 500 barrels of oil or more.

We are currently operating 20 rigs between the two plays and expect to maintain that level through 2012.

Next is the Permian Basin on slide 22, which we recently disclosed we are considering a joint venture or an outright sale.

Most recognize the Permian is the most prolific basin in the US, and it garners significant incremental capital from the industry at current oil strip prices.

Our 1.5 million net acre Permian acreage position is focused on key development plays, the Avalon, Bone Spring, Wolfcamp and Wolfberry.

Fourth-quarter net production was approximately 33,000 barrels of oil equivalent per day.

That's an increase of 22% compared to the fourth quarter last year.

And in 2011, we tested 21 wells with an average peak rate of over 1000 barrels of oil per day.

We look forward to sharing more information with prospective partners and/or buyers in our upcoming dataroom process.

Finally, I am pleased to highlight our latest large-scale discovery, the Utica Shale, that is on slide 23.

This is where we recently welcomed Total to the wet gas window in the play as our JV partner, as a follow-on transaction to our mutually successful partnership in the Barnett Shale.

We are continuing to delineate efforts in the play, with six rigs running in the wet gas window and one each in the oil and dry gas windows.

We will plan on ramping up to 20 Utica rigs here by year-end 2012.

To date, we've drilled 42 wells in the play, with seven of those on production and 35 waiting on completion or pipeline connection.

Two recent completions include our Burgett and Shaw wells in the Utica, which produced at peak 24 hour rates on average of 700 barrels and 3 million per day.

We are already starting to see drilling efficiencies in this play, and have at our recent best well drilled spud-to-rig release at only 16 days, and that is compared to two or three times that for our earlier wells.

Through our Midstream efforts, we have installed 200 miles of pipeline -- will install 200 miles of pipeline in 2012, and our local field office presence continues to grow.

All the major oilfield service providers are establishing a footprint locally as the result of our activity, and this is a driving significant boost to Eastern Ohio.

Moving on to slide 24, we are operating 161 rigs and have accomplished approximately 90% of our planned transition to liquids-rich plays.

We do expect our operated rig count will stay relatively level for the year at an average of approximately 161 rigs for the year.

This is including 33 rigs in the Eagle Ford Shale, 22 in the Miss Lime play, 20 in the Cleveland and Tonkawa plays, 14 in Utica Shale play, 13 in the Granite Wash plays and 10 in the Permian Basin.

During the reminder of the first quarter and into the second quarter, we will continue to see a drop in natural gas rigs until we get down to 12 rigs in the northeast portion of the Marcellus and down to six rigs in the Haynesville.

We are already at our stated goal of six rigs in the Barnett.

We expect to spend $7 billion to $7.5 billion on proved and unproved drilling and completion activities in 2012, approximately 85% of which will be directed towards our liquids-rich plays.

Finally, I would like to conclude by highlighting two important achievements that demonstrate the Company's commitment to best practices in the environmental health and safety areas; it's on slide 25.

I'm pleased to report that 2011 was Chesapeake's safest year ever in conducting its operations.

Our 2011 total recordable incident rate was an impressive 0.53.

While our company has continued to grow, our OSHA reportable incidents have continued to decrease.

Since implementing the SAFE program in 2010, which stands for Stay Accident Free Everyday, COI has improved our safety performance by 34%, while increasing employee count.

2011, we set a new record by working over 1.5 million employee hours without a recordable injury.

This is a very important accomplishment, and we are very committed to making 2012 also the safest year in the history of the Company.

We also make environmental stewardship a priority, and in early 2011, Chesapeake furthered its commitment to progressive operational environmental safety standards by formally adopting the set of operational principles for the Company's employees, contractors, suppliers and vendors to guide its oil and gas exploration and production operations throughout the country.

These guiding principles represent our commitment to our surface owners, mineral owners, local citizens, shareholders, government officials and regulators and all stakeholders to make progress at improving our operational performance by working in an environmentally respectful way.

In addition, during 2011, Chesapeake joined a nationwide public registry, fracfocus.org, that discloses the additives in the Company's hydraulic fracturing operations.

We currently have more than 1300 wells posted on fracfocus.org, accounting for more than 11% of all the wells posted to date, more than any other operator.

In summary, Chesapeake had an outstanding year operationally in 2011 and we look forward to providing further strong growth, particularly in our liquids-rich plays, as the year progresses.

We would now like to turn the call back to the operator and open the call up for questions.

Operator.

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch.

Thanks.

Good morning, everybody.

I'm going to try a couple, if I may.

On the production outlook, you have kind of caveated in your commentary that the guidance excludes the potential of several deals over the course of this year.

My question is really about the longer-term, the target to get to 250,000 barrels a day of liquids.

Assuming that you do execute some of the transactions that you are talking about, particularly the potential exit of the Permian, how would you see that longer-term trajectory in terms of liquid targets move around?

Is it material, or will it essentially remain unchanged?

Remain unchanged, Doug.

Can you give us some idea as to what the headroom is?

Well, it is enough to handle a full divestiture of the Permian, if that is your question.

It is about 5% of our current production.

So we continue to have a lot of headroom.

You can frankly see it in our curtailments, where we have lowered our guidance for 2013 by 50 Bcf on a midpoint perspective.

And yet we are modeling a curtailment of about 130 Bcf.

So if we weren't curtailing gas, we would actually be taking our gas production up for the year.

So I think there is plenty of headroom, and we've modeled that we can still get to our 250,000 barrel number by just reallocating capital away from the Permian to other plays.

That's the benefit of our business strategy is that we have leading positions not just in one or two plays, but in 11, and we can spend additional money in the Anadarko Basin or the Eagle Ford or in the Utica Shale.

Got it.

Thanks for that.

My second one is really on the CapEx program, and I guess the disposal indications that you provided, specifically on the Oilfield Services line item.

It looks like the CapEx there compared to your previous guidance has moved up a bit.

And I'm not sure if there is something else in there beyond Midstream and Oilfield Services.

But if you could maybe give us some color on that.

And at the same time, the $2 billion disposals you're talking about in the Midstream, I know there is a lot of moving parts in there, but Nick has previously given some color as to how you guys see the value of those assets.

I wonder if you could just give us a quick recap on what is making up that $2 billion and what some of the menu items are there that you might look at.

And I'll leave it at that.

Thanks.

We are not really changing our Midstream and Services CapEx by any material amount.

There is a little bit of additional Midstream CapEx.

You saw yesterday that we had an announcement with a company called Gavilon to jointly develop a pipeline.

And there is two or three other pipelines like that where we have equity options, and together, they amounted to maybe a 10% increase in Midstream CapEx.

But that is a rough number, and those are options, so we have to determine exactly what we are going to do.

So we have given ourselves in our guidance here some room to participate in some of those projects, which we think will be highly accretive.

Ultimately, though, what we do have there is Midstream CapEx, Services CapEx, and then we hadn't previously given specific guidance on other CapEx.

And so that is an additional element here.

Other would include seismic, it would include corporate -- capital expenditures for things like software and other things that get capitalized in our budget.

What we really tried to do this time was give a complete picture of our ins and outs, and so we lumped that in there.

We are quite purposefully not giving very detailed specific guidance on both Midstream and Services this time.

You will remember that -- you asked in your question here -- about what are the items that we think will deliver the monetizations.

One of those items, we believe, will be an IPO of our Services business.

And so we need to start being pretty careful about the guidance we provide outside of an SEC process and don't plan to do that.

So it will be that.

It will be Midstream drop-downs.

And then we have said that we would like to see something happen with Frac Tech.

They also have an S-1 on file, so there is not a lot we can say about that either.

All right, fellas.

I'll leave it there.

David Heikkinen, Tudor, Pickering, Holt.

Just kind of thinking about your -- you gave guidance for Chesapeake Oilfield Services in your projections and then Chesapeake Midstream Development.

I know you are talking about doing an Oilfield Services IPO.

Kind of thinking about the margins, though, of revenue versus operating expenses, they look a little low, but then they expand.

Can you walk through what your assumptions are that go into, first, that set of guidance?

We at the moment are just entering the pressure pumping business.

We fraced our first well in the fourth quarter.

We now have two spreads running.

Terrific success early in the life of Performance Technologies LLC, our fracing company, and look forward to continuing to grow that business.

That is, of course, a high-margin business relative to the overall base that we have there, which is dominated by our contract drilling business.

And so we do expect the margins to improve as a result of the rollout of PTL.

You probably will notice that the fourth-quarter margins on a summary basis show a little bit less profit from COS.

One thing that did occur there is we did have some additional roll off of contracts that were operating previous to our Bronco acquisition for third parties.

And so as those rigs go to work for Chesapeake wells, we obviously have to eliminate a bit of that profit.

Whereas in the third quarter, that was pure profit, Chesapeake working for a third party.

And then thinking as you talk about that IPO, selling roughly 20% of the business as a target, is that a reasonable assumption?

That is a reasonable assumption, David.

We are way early to give you any firm guidance on that, but that is as reasonable an assumption for now as anything.

If you sold more than 20%, does that have any tax implications or would that change how you would have to report capital expenditures or anything along those lines?

Those are all things we are looking into, and we don't have a structure finalized yet that we will pursue.

So I would like to just pass on that.

Okay.

Shifting kind of to the operating side, one of the thoughts and questions around your Permian assets -- and Steve, you talked a little about the 21 wells in 2011.

Can you give us a breakdown of what zones, just the split of what those wells were, to get an idea of how many acres you have in each play and kind of where you've actually had well results?

It is predominately in the Avalon and Bone Spring, and the Delaware basin.

We do have three rigs running in the Midland basin and Wolfberry play, but it is predominately those big wells are all in the Bone Spring and Avalon.

Okay, that's all I needed.

Thanks, guys.

David, this gives us an opportunity to say one thing.

We did see in some analytical work over the last day that there is a view that we went out and acquired 800,000 acres in the fourth quarter in the Permian.

That is not correct.

What people I think are referring to is -- Jeff, would it have been in our third-quarter report where we showed how many acres, and then now it's 1.5 million?

And the reason is because you had 600,000 acres in the other category?

Correct.

In the third-quarter drilling inventory we had listed a portion of our Permian Basin acreage in the unconventional liquids rich play.

As I recall, that was 820,000 or 830,000 acres.

Also, there was approximately 650,000 net acres in the bottom category that has grouped with our other conventional and unconventional plays.

So we had 1.5 million net acres in the Permian at the third quarter.

We have the same amount of acreage today.

And also for a point of reference, I will also guide you to our disclosures in our annual report last year, where we had reported 1.2 million net acres in the Permian.

So no big acreage spend, and some others have kind of missed that point.

Thanks.

Dave Kistler, Simmons & Company.

Real quickly, taking the rig count down to 12 in the Marcellus, six in the Haynesville, six in the Barnett, obviously could certainly redirect that capital towards other liquids-rich assets.

What is the incentive for keeping those rigs running there at all?

Does that have to do with pipeline obligations?

If you would just walk me through that, I'd appreciate it.

It is primarily a combination of things, Dave.

There is still some acreage lockdown that needs to occur in all those plays that will tend to peel off or become less of an item for the Haynesville as we go through the year.

In the Barnett, we have permits that are kind of use it or lose it type permits.

And so for the initial well on a pad or we want to get a well into production, and then we can hold off on the incremental drilling after that.

There are some firm transport issues in some of the plays, but we are willing to try and take some of that, and also we are going to try to renegotiate and reshape some of our firm transport as well.

So I've heard some companies say because of firm transport they will just continue to drill gas wells and lose money.

And our view is we should be able to take a little more commercial approach to that.

So I would just say it's a combination of things that put us in a position where we can go to these levels on an absolute low basis, and then we will take a look at it from here.

These levels of drilling do cause a decline in our production in the Barnett and a decline in our production in the Haynesville.

So we think that is certainly a good thing for the marketplace, and we look forward to that playing out to the marketplace in 2012 and beyond.

Great.

Then looking at kind of your '13 guidance and comparing it to your '12 guidance, dry gas production is getting about $900 million of CapEx in '12.

Then in '13, you didn't adjust that production guidance down from what you gave us at 3Q.

Is there going to be an uptick in CapEx to dry gas production at this point, or is that the anticipated plan?

Dave, I just don't think we know enough about what the gas market is going to look like in 2013.

So we kept it where it is for now.

And also, we have a significant curtailment this year as well as 130 Bcf.

So I think there if the gas market is attractive enough, there is a likelihood that we could produce more gas in 2013 than what we presently have modeled.

Okay.

Appreciate that.

One last one, if I can.

Looking at your commentary around the financial transaction for Ellis and Roger Mills Counties in Oklahoma, Cleveland, Tonkawa, I'm guessing kind of same sort of structure to what you had previously done in the Utica.

If we think about that as sort of 7% financing before an overriding royalty interest, how do I compare that to then debt financing you just did at 7%?

Realizing you want to hit investment grade rating, that 7% seems attractive versus giving up an overriding royalty interest and a 7% distribution to the financial partner.

Dave, I'll take that.

We really view that transaction as an alternative to a strategic JV.

Strategic JVs in this part of the world are complicated for us because of the overlapping geologic plays that exist.

And so we can take a specific zone and do this financial transaction.

The relative cost of capital to a strategic JV is vastly different here, given the structure.

The overall return on this one will be less than the Utica just because this one includes some current production and reserves and is a more well-defined play.

But you are right; it will be a similarly structured investment.

Okay, that's helpful.

Thank you so much, guys.

Jeff Robertson, Barclays Capital.

Thanks.

Aubrey or Steve, in the Utica, you all talked about having one well active in the oil part of the play.

Can you talk about your plans for the oil part and whether that is included in the Total joint venture that you all announced back at the end -- in December?

Sure, Jeff.

First of all, it wasn't one well.

It is one rig running in the oil window, and then one in the dry gas window.

So think about, if you would, the Utica having three phases, just like the Eagle Ford.

Except rather than south to north on gas to oil in the Eagle Ford, in the Utica, we go east to west; so gas on the east side, wet gas in the middle and then oil on the west side.

The deal we did with Total is simply right in the middle.

It is the wet gas window, and we purposely kept our dry gas assets back for a better day.

And then on the oil side, we just simply haven't drilled enough wells to be able to establish just what our EURs are going to be there.

So there is a lot of interest in a joint venture with us on the oil side, and interestingly enough, a fair amount on the gas side as well, as there are a number of companies that are signed up to export gas from the US or planning to export gas in the US, and want to back that up with some physical assets.

And the Utica would be a great place for them to go.

We have about 400,000 acres in the dry gas window and I think about 400,000 in the oil window as well.

So we are going to continue to develop both of those sides of the play, but the primary amount of our drilling will be in the wet gas window.

Aubrey, will you all have more than one rig out there over the course of this year in the oil part of the play, trying to test that?

Yes, probably go up to maybe two.

And I think, Steve, we exit 2012 -- how many new rigs in the Utica?

20 rigs.

20, and we are at nine today.

Is that right?

Yes.

So it is going to be kind of proportional, I would say, Jeff; as we more or less double our wet rig count, we will do the same on our dry and oil.

Okay.

And then moving over to the Rockies, can you all just provide an update on where you stand in the Niobrara and what your plans are for that for 2012?

I'll let Steve provide a little more detail.

On the DJ Basin, like with other companies, our results have been spotty.

And today, I don't think we are drilling anything in the DJ Basin in the Niobrara.

On the other hand, our Powder River Basin play is working quite well, and Steve may want to highlight a couple wells there or highlight what our activity levels are going to be there.

We just kind of got ramped up through last year.

We are up to eight rigs in the Powder River now, wanting to grow that to maybe 15 by the end of the year.

And we are seeing 500 barrel a day IPs there.

So we have some delineation to do, but as we bring in extra rigs, we can start focusing part of those in the sweet spot also.

So we are looking forward to full growth in the Niobrara.

I might also mention that in both those areas, it is not just the Niobrara; we are investigating lots of different other formations, as other operators are as well.

So I think for the DJ, I wouldn't say all is lost if you are outside of Greater Wattenberg; that there is going to be some other ideas.

But we have certainly shifted our focus in the Niobrara play to the Powder River Basin.

Last question, Aubrey.

Can you comment -- if you contemplate a complete exit of the Permian, can you compare the returns that you all anticipate on the different plays in the Permian to what you would be keeping in the Eagle Ford and the Utica and the Midcontinent liquids plays?

Sure.

I think the returns from our projects in the Permian are first-rate, and I think that is why you see so much industry interest in the Permian, and frankly why you see so much investor interest.

Just looking at the valuation of some companies that are pure Permian basin players, we are tempted to spin out our Permian asset and just make it a separate company.

But at the end of the day, it is probably best for our overall goals this year to work the JV approach and also to work the 100% approach as well.

So Bone Spring, Wolfcamp, Avalon, these are all plays that everybody wants to be in.

And I don't need to repeat the rate of returns that everybody is talking about getting there, but they are very strong.

And our situation is just a real simple one.

We are making a transition from strictly gas to oil, and along the way, we need to sell some of the assets that we develop, and this is an asset that we think that will attract a great deal of industry interest.

And also, from our perspective, it only being 5% of our production, it was never going to be a play like the Eagle Ford, where right now we are spending 25% of our CapEx on it.

Likewise, a play like the Utica could ramp up over time to be a very significant player; we spend about 25% of our CapEx in the Anadarko Basin.

We just didn't see the Permian ever getting to a point where it could be as important to us as some of these other assets.

So that is why we are considering the various asset monetization proposals that we've talked about.

Thank you.

Brian Singer, Goldman Sachs.

Thanks.

Good morning.

Appreciate the additional operational disclosure by play on the call, and wanted to follow up a bit for some more color on the two Utica wells that you referenced.

Specifically, if the wells from a lateral length perspective are analogous to the two Carroll County wells you disclosed in late September, how much of the liquids are oil condensate versus NGLs?

And then with the drilling efficiencies that you are seeing, what your drilling and completion costs are in the play.

I don't have the lateral lengths with me, Brian, but they should be average.

I don't think there were any longer.

And those are preprocessed.

That was condensate production on those wells, averaging over 700 a piece.

Capital costs, -there is still a lot of science going on, a lot of pilot holes, still learning a lot.

So as you can see from 45 days, in some 16 days, there is a variety of costs also.

But in 18 to 20 days, we should be able to get the costs down to -- what?

Oh, we can get them down to below $6 million.

Brian, that is what I'd kind of think about on a long-term plan, is a $5.5 million to $6 million CapEx plan for let's call it 5000-foot lateral or so.

That is helpful.

So from the wells that you've drilled and completed and brought on now, what percentage of your wet gas acreage would you say you feel like you have de-risked?

There has been a lot of focus on Carroll County.

Or do you feel that you've de-risked a much wider chunk of that acreage at the moment?

I think we feel like we've de-risked 100% of our wet gas acreage, given not only just our results today, but also just our petrophysical work to date.

And remember, this is a formation that has been penetrated hundreds of times, as companies have drilled to deeper objectives, like the Knox.

So we are 100% confident on the wet gas, 100% confident on the dry gas.

It is the oil that we still haven't yet fully proved up how much of that is going to be prospective.

There are a lot of other operators that are going to be throwing results out into the marketplace throughout 2012.

The difference is, I think most people would look at the play and see where our acreage is concentrated and think that we've got really the heart of the core pretty much locked up.

And so we are very excited that we are likely to be able to deliver the best results.

But my hope is that other operators who are around the fringes will also have success as well and that can only benefit us at the end of the day.

That's helpful.

Thanks.

And lastly, you highlighted a decent backlog in the Eagle Ford shale, then to a lesser degree in the Utica.

Can you just talk to how and when you expect that to change in 2012?

Is it just bringing on the additional frac crews in the Eagle Ford or the Midstream bottlenecks that you anticipate easing or not easing as well?

It is really both.

It is ramping up our ability through Services to complete wells faster, more efficiently.

But also, it is the Midstream, and we've got a lot of activity going on there now.

And our ability to transport oil is increasing significantly just in the last few months and in the coming months.

So would you expect the 200-well backlog in the Eagle Ford to be entirely eased or 50% eased by the end of the year?

Or is it offset by the ramp-up in activity?

No, we expect for it to get worked off this year, Brian.

That's great.

Thank you.

That is why we are going from seven frac crews to 13.

Thank you.

Neal Dingmann, SunTrust.

Just wanted a clarification.

Aubrey, you were just talking briefly on the Utica cost, could you comment again on that liquid window what the costs are running now for yours, Steve?

And then kind of well design, what you're doing kind of on laterals, if you could comment there.

What I said before, a 5000-foot lateral, we are driving towards a $5.5 million to $6 million well.

And of course, to get there, we need to be doing no science to it, and that is really where we are moving into - the science part is over now and Steve mentioned we've already got a 16-day well, and I think some of our first wells are 40 to 45 days.

So it is really a pretty attractive depth.

TVD, Steve, here is 6000 to 7000 feet.

So it is not nearly as deep as a number of the unconventional plays.

We've said from the beginning we love this play, and we are very excited about what we've seen to date.

The dry gas is going to work when gas prices get a little better.

And then on the oil side, we hope to have some breakthroughs this year as well and hope others in the industry do also.

Just one follow-up, Aubrey or Steve.

In the Eagle Ford area, do you mostly do pad drilling there?

And then the second part of that, have you looked and do you believe there could be other prospective liquid zones in parts of that play in addition to the Eagle Ford?

On the pad drilling, we've only been able to dedicate just a few of our rigs to pad drilling.

Most of them are still out holding new leaseholds.

And we have not come across another liquid play yet.

There is certainly a dry gas play in the Pearsall, but we are not looking for dry gas right now.

Very good.

Thank you all.

Marshall Carver, Capital One Southcoast.

On the third quarter call, you all had 1.4 million net acres in the Mississippian plays.

I think I had 1.1 million in the original play and then 300,000 net acres in the extension.

Then in last week's release, you were talking about 1.8 million net acres in the Mississippian Lime plays.

Where would you classify those 1.8 million acres, and where do the extra 400,000 acres go?

We are only buying in the core right now, so it depends.

Other companies may have a different definition of the core and have a different definition of the extension.

But we are trying to focus our leasehold buy in areas where we are pretty comfortable with what the outcome is going to be.

So you were very active in the Mississippian acreage front over the last three months?

Yes, although it is starting to slow down as things get blocked up.

But it is one of our remaining plays where there is still some acreage to be picked up.

And given the level of interest that we see in our Mississippi Lime joint venture, there is a lot of value to be captured for our shareholders by making sure we square up our positions before we enter into a JV.

Okay, that's helpful.

Thank you.

And one more question.

On the long-term liquids growth target to the 250,000 plus barrels a day in 2015, how should we think about that in terms of crude production or condensate versus NGLs?

Do you have any color on that front?

I think we modeled it about the same way that our production is today.

Steve, do you have that, or Nick do you have the split?

I think the split is about 35 to 40% oil to NGLs and the balance being crude and condensate.

Yes, so just call it mid-60s, maybe two thirds oil and the rest NGLs.

That is where it is today and where we expect it to remain.

Okay.

Thank you very much.

Biju Perincheril, Jefferies.

Good morning.

A couple of questions.

On the gas production side, Aubrey, in 2012 numbers, I think you are only looking at about a 5% drop versus the previous guidance.

And I would have expected something more, given the curtailments.

The question is what is embedded into that guidance, as far as when you think those productions will be back on?

Really the answer is simply that had we not curtailed production, we would have well exceeded our production forecast for 2012, and would have had to take it up.

So I think I've mentioned this in an earlier question, which is we went down from 1020 to 970, and then are also curtailing, though, 130 or at least planning on it.

We don't know how the year will play out.

So obviously, we would have had to increase our guidance for 2012 for gas production had we not chosen to curtail as much as we are now curtailing.

Got it.

But you are not assuming that production stays off for the rest of the year, though.

Is that a fair assumption?

I think we have it internally modeled to be off through October.

Okay, and then on '13, and I think you mentioned earlier that you are just waiting to see how the markets shape up before you give more specific or update the 2013 guidance.

But given the reduction in activity to date, do you need to increase from current levels to hit the guidance that you have provided now for gas?

No, I mean, we are long gas right now.

So I wouldn't be concerned about our ability to meet 2013 gas guidance, I think I would mark that one off.

Okay, that's fair.

So with the activities there, you are still looking at an increase in 2013.

Yes, we are.

And again, without knowledge of the gas market.

But if you were to look at our midpoint of the range this year at 970 and add 130, that means our true capacity this year was 1100, or 1.1 Tcf.

And so we are modeling next year 1050.

So we were modeling at a 4% decline in 2013 from full capacity in 2012.

But that is pretty remarkable, given the kind of drop in activities that you are talking, to still get that uptick.

Is that because of activities that are more liquids rich and the associated gas production, or it is just the areas -- the shale plays are that much more prolific than we've been thinking?

I appreciate you recognizing that performance is indeed remarkable.

It is.

And that is what has driven gas production levels in the US to where they are; we are responsible for 30% of it.

So we feel also somewhat responsible for trying to contain ourselves a little bit.

I think when you just boiled it down, it is just the sheer productivity on a per well basis.

So if the play cycle times are down, recoveries on a per well basis are up.

Associated gas helps a little bit, but it is not nearly the factor that I've read a lot of people.

What I see a lot of analysts do is just model an associated wedge for the industry and just put it on top of flat shale production.

We think the declines from the Barnett and the Haynesville will offset any gains from the Marcellus.

And then we think the rest of the system is in decline.

So when you take us out of the system as being a contributor to growth, it is pretty hard for the rest of the system to grow.

And we'll wait for demand to catch up.

We absolutely believe that will be the case, and we see evidence of it every day.

If you burn diesel in the US today, you are absolutely focused on trying to burn natural gas instead.

And you can read more evidence of that every week in terms of what companies are doing to embrace it.

So we are well on our way to the demand revolution in natural gas that will solve the overhang that we are experiencing today.

All right.

Thanks.

Bob Brackett, Bernstein Research.

Could you give us an update on the Williston Basin?

You've deemphasized it a bit.

Are you doing more science there?

Are you more positive, more negative?

Bob, yes, we've drilled a couple of wells up there, and not crazy about what we've found to date, so kind of recalibrating there.

We have just under half a million acres south of Dickinson.

And really the Three Forks idea for us, and I suspect the western part of our acreage, which kind of abuts where Whiting is operating, will probably work out fine.

We drilled our initial wells more towards the south and east.

So disappointed to date in what we've seen in the Bakken, but have a huge acreage position there.

We didn't spend a whole lot of money on it, so not too worried about that.

And really just moving our rigs over to the western side of the play and kind of cozy up a little bit more to what Whiting is doing there.

As a follow-up, on those 1250 non-op wells from 2011, can you talk about where those are in the mix of horizontal/vertical oil/gas, and what the call on capital of that non-op program might be.

We can answer that.

They're virtually all horizontal.

Hardly anybody we do business with is drilling vertical wells.

Steve, in our overall budget, are we 20% non-op?

What's our --?

It's about 15%.

So we're about 15% non-op.

And of course, Bob, that is included in our CapEx guidance.

Sure, sure, sure.

And where are those?

Are those mostly Midcontinent?

Western Oklahoma.

Scattered.

We'd be in a lot of Marcellus.

We have non-op positions there.

Not so much in places like the Eagle Ford or the Utica, where we are the operator.

But I would say Permian, Midcontinent and Marcellus are the main areas where we have non-op interest.

Thank you.

Joseph Allman, JPMorgan.

Aubrey, in terms of leasehold acquisitions, I know you are budgeting to spend $1.4 billion net, given that you're ramping up in the Mississippian.

So how much have you spent so far, gross, if you can give us that number?

And when you say $1.4 billion net, is that net of just the existing JVs, or are you factoring in future JVs as well?

It's a good question, Joe.

The net is from reimbursements from existing partners.

So initial first time down-payments on leasehold are not included in that.

So it's really not a gross number.

It is just like there is no such thing as gross CapEx.

You go drill a well and your partners reimburse you for their share of the CapEx costs, and you report your net CapEx, and that is what we do on undeveloped leasehold.

We do have partners who have obligations to buy leases alongside us.

So the $1.4 billion is what we spend, and it does include some partner reimbursement, but does not include expected payments from first-time JVs or from just leasehold we will sell just in the ordinary course that may be superfluous to our core operation.

Okay.

So just to clarify, so you are going to spend $1.4 billion net on leasehold this year.

That is your target.

Now you've spent money late last year and early this year ramping up the Mississippian.

So you don't have a Mississippian JV yet.

So that $1.4 billion, that includes what you've spent so far in the Mississippian.

Does it also make an estimate of not necessarily the upfront payment, but the reimbursements you get for the future Mississippian JV?

Okay, let me try and clarify a couple things.

First of all, you commented that the $1.4 billion includes all we've spent to date on the Mississippian.

No.

It is our expected expenditure this year, of which some of it will be the Mississippian.

And in that, we do anticipate that there will be, later in the year, some partner pickup of some of our leasehold.

But it is not net of the initial down payment that a partner makes when they come into the Mississippian.

So the primary driver of the $1.4 billion this year, I think we budget to spend more in the Utica than anywhere else.

And then after that, it kind of falls down pretty rapidly into a wide variety of plays where we continue to kind of square up positions.

So I hope that makes sense to you?

Yes.

It doesn't necessarily fill in the details, but so will the leasehold spending be concentrated in the first quarter versus the balance of the year?

I don't know if it is going to be concentrated.

It is going to be more front-end loaded, because, again, we project that we are spending less money in the third and fourth quarters in the Utica than we are in the first and second quarter.

And the first quarter always has some spillover from the fourth quarter of the preceding year.

Okay, so I think I understand.

So a different topic.

In terms of working capital, one thing we noticed is in the fourth quarter of 2011, the change in working capital saw a big increase and it was bigger than we saw in prior quarters for a while.

And we just want to get behind the numbers.

I know we spoke to you guys last night, and I know part of it is just prepays from partners.

So could you actually explain that?

And also, in terms of Accounts Payable, are you managing your Accounts Payable any differently than you had been?

No, Joe.

There is just a lot of activity that occurred in the fourth quarter and it resulted in higher total current liabilities.

No difference in how we manage our AP.

We do have partner prepays that resulted in higher current liabilities.

The way that works is when we have significant partner relationships like we do in our JVs, we have the ability to prepay or to prebill them for CapEx.

And when they pay that to us, it becomes an accrued liability until such time as we form the activity.

And then that is reclassed into the full cost pool as an asset.

So there is no change into how we are doing things.

I do think that as we spent less on leasehold this year than we did on a run rate in the fourth quarter and for the year, you could see that number come down a little bit this year.

Certainly we will be growing our rig count not at all.

In fact, for the first quarter, it dipped a little bit.

So our activity levels in general will have come down a little bit in the first quarter.

So we will see where it all shakes out.

There is always a lot of timing differences in that number.

For example, we had some accrued interest expense that just based on the timing of when 9-30 hits versus 12-31 hits was a bigger number in the 12-31 balance.

So there is always some noise.

Okay, anything else?

I've got a couple more.

Joe, given the time, I'm going to let you call Jeff back on that and let everybody else get back to their business.

Thanks for your questions today, and I appreciate everybody else's participation.

If you have follow-up questions, please direct them to Jeff or to John, and we will talk to you guys down the road.

Thank you much.