Chesapeake Energy Corp (CHK) 2012 Q1 法說會逐字稿

Good day, and welcome to the Chesapeake Energy 2012 first-quarter earnings results conference call.

Today's conference is being recorded.

At this time, I would like to turn the conference over to Mr.

Jeff Mobley.

Please go ahead, sir.

Good morning, and thank you for joining our conference call today.

I'd like to begin by introducing the members of the management team that are on the call today.

Aubrey McClendon, our Chairman and CEO; Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and from the Investor Relations research team, John Kilgallon, joining us as a Senior Director.

And we have a new person on the team I'd like to introduce to you, Gary Clark, who joined us from an investment firm in Tennessee.

As usual, our call will last one hour.

And so now I'll turn it over to Aubrey.

Thanks, Jeff.

Good morning, and thank you for joining us today.

Let me begin by acknowledging what everyone is clearly aware of.

This has been a very challenging two weeks for all of our shareholders, bondholders and other stakeholders; and also for our friends and employees.

There's been enormous and unprecedented scrutiny of our Company, and of me personally.

And a great deal of misinformation has been published, and uncertainty created.

Your mother told you not to believe everything you read or hear for good reason.

And that's certainly been the case for the past two weeks.

I am deeply sorry for all the distractions of the past two weeks.

Through all of this I've learned that there was a desire for more information regarding the FWP program; which, as a reminder, has been in place since 1993, the day that the Company's IPO was approved by shareholders in 2005; and I believe, as always, has always aligned my interests with the Company's interest and insured that I had skin in the game, uniquely among other CEOs.

Consequently, last Thursday, I disclosed a substantial amount of personal financial information regarding my FWPP interest.

Furthermore, Chesapeake's preliminary proxy, filed on April 20, also includes enhanced disclosures regarding the FWPP, and discloses a multitude of positive governance changes that you should take the time to review.

Hopefully those measures, along with the decision to split the role of CEO and Chairman, and to terminate the FWPP 18 months early, adequately address the questions and misunderstandings that have been bouncing around in the marketplace and the media.

I would like to reiterate that as part of the agreement, I will not receive any compensation or any benefit for the 18 months of the FWPP rights that I've agreed to forgo.

The Board and I are both very pleased that this compromise, which I would like to highlight, also has been supported by our largest shareholder, Southeastern Asset Management, which owns a 13% ownership position in the Company.

In addition, you have seen that Chesapeake's Board has begun a search for, and will name, an independent nonexecutive Chairman of the Board in the near future, which is something that I enthusiastically support.

This step reflects our determination to be proactive and uphold strong corporate governance standards.

It will also allow me to have more time to concentrate my full time and attention on the execution of the Company strategy, the implementation of our substantial transformation to a major oil producer, and the completion of our asset monetization and joint venture objectives.

Despite all the noise of the past two weeks, my primary job as CEO has been, and always will be, to build long-term value along with attractive short-term returns for the Company and all its stakeholders.

That is the task at hand, and that is and has been my primary focus for the past 20 years.

Those that know me know that I will work tirelessly to achieve that the goal.

And no, I will not allow myself or your management team to be distracted from that mission.

I'd now like to shift our discussion to other important topics, including the results from the 2012 first quarter, a quarter in which we experience both positives and negatives.

The four most important positives for the quarter were -- number one, our production growth was strong, especially in liquids growth, up 69% year-over-year, and 7% sequentially.

Number two, our finding costs were only $7.14 per barrel of oil equivalent.

Surely that's the lowest among the large-cap E&P's, if not the entire industry.

Number three, the amount of new reserves we found was 1.8 Tcfe, or 300 million barrels of liquid equivalents.

That was exceptional; and, again, I suspect industry-leading for the quarter.

Number four, all of our plays are working very well, and we don't have any bad operational news to share.

Quite simply, in the field, it's all good.

However, we did experience two negatives for the quarter to offset some of the positives.

Number one, because of extremely low natural gas prices and also NGL prices, combined with wider-than-expected basis differentials, slightly higher operating costs due to oil wells being more expensive to operate than gas wells, and certain non-cash losses on two of our in equity investments, and Frac Tech and Chaparral, we reported adjusted EPS of $0.18 per fully diluted share, which is below the average analyst consensus of $0.29.

That is our first significant earnings missed in many years, I believe, and hopefully our last.

Number two, because our CapEx for drilling completion leasehold has been significantly front-end loaded this year, that in combination with reduced cash flow from low gas prices, caused our net long-term debt levels, net of cash, to rise roughly $2 billion during the quarter.

We had anticipated and planned for such an increase, but possibly many others didn't.

So I can imagine that some might think we have abandoned our $9.5 billion year-end net long-term debt target and our 25/25 plan for year-end 2012.

The short answer is no, we certainly have not.

It's just that 2012 CapEx will be more heavily skewed to the first quarter, while operating cash flow and asset monetizations will spread out throughout the year.

So we'll have to work a bit harder on the asset monetization front to counteract currently soft US natural gas prices to hit our year-end target.

The good news is, the positives for our Company are enduring, and the negatives, we believe, are short-term in nature.

Importantly, we expect the run rate of out CapEx spending to greatly decrease during the remainder of the year.

So if one were to simply multiply our first quarter CapEx numbers by four, they would arrive at a very wrong conclusion about our planned full-year CapEx spending.

Another point about CapEx that I would like to emphasize is that the levels we have budgeted for in 2012 and 2013 are absolutely required, if we are to escape the downward gravitational pull of natural gas prices and capitalize on the very attractive prices for oil and natural gas liquids available for us in the marketplace.

The payoff for this corporate transition we have underway should be increasingly clear for all to see in our liquids production growth over the next year, and in the years ahead.

Please remember from a base of only 30,000 barrels a day of liquids production at the end of 2009, we are well on our way to delivering liquids production, even after planned asset monetizations of more than 150,000 barrels per day in 2013; 200,000 barrels per day in 2014; and 250,000 barrels per day in 2015.

And this will all come from assets that we already own.

We believe this could turn out to best the liquids volume growth story in the US industry, and perhaps one of the best in the world as well.

Returning to CapEx for a minute, Chesapeake's 2012 first-quarter front-end loaded CapEx levels were attributable to several items that will not persist through the year.

Steve will have more to say on drilling CapEx as part of his prepared remarks.

But my quick summary is that during the fourth quarter of 2011 we ran as many as 172 rigs, because we were rapidly ramping up our liquids-focused drilling while, at the same time, we were deliberately but more slowly ramping down gas drilling.

Because of the time requirements to execute this shift and the time lag of completions, the first quarter took the brunt of that elevated drilling level from the fourth quarter.

I'm happy to report that today we have already dropped 18 operated rigs to reduce our total to 154.

And our drilling during the year will decline further to around 125 rigs by the third quarter.

So as the year moves along, we'll be drilling with about 25% fewer rigs than we used in our fourth-quarter peak.

And CapEx on drilling and completion should move down sharply, in tandem with this rig decline.

Importantly, our gas drilling will drop even more significantly than our overall drilling levels.

At the beginning of 2012, we were operating 50 gas rigs.

But during the 2000 first quarter, we averaged 38 and within 90 days from now we'll be down to only 12.

So I'd like to re-emphasize that -- 50 rigs in January 2012; drilling gas wells down to 12 rigs in just 90 days; a drop of more than 75%.

Another way to look at the 2012 first-quarter drilling CapEx is to analyze actual dollars spent on plays, gas plays such as the Haynesville and the Barnett.

On those two plays alone, we spent approximately $575 million during the 2012 first-quarter.

However, for the next three quarters we plan to spend up just about $100 million each quarter in these two plays, or more than an 80% reduction per quarter.

One final aspect of our drilling CapEx spend during the first quarter is that we still had a big backlog of uncompleted gas wells that we had to complete to finish the steps necessary to hold our valuable leasehold by production, and make them permanent assets.

In fact, we completed 57 more gas wells during the quarter then we spud.

And so we already have completed more than 50% of the gas wells expected for the full year in just the first quarter of this year.

Next, I'd like to address leasehold CapEx.

It was also strategically and purposefully front-end loaded, with about $525 million of the quarter's approximately $900 million leasehold spend, focused on the Utica and Mississippi Lime plays.

This plan was designed to complete our leasehold purchases in conjunction with our completed or planned JVs in these areas.

Now that the most important areas have been captured, these two areas, and in reality all of our remaining plays, will see greatly reduced leasehold spending during the remainder of 2012.

We have built an exceptional portfolio of assets during the past seven years, in what I call the great unconventional resource revolution.

And from here on, it's all about exploiting these assets to the maximum benefit of the Company and its shareholders.

As evidence of that strategic transition, we have greatly reduced our leasehold CapEx budget in 2013 to $500 million, down from a high of $1.25 billion.

And that's a level that we believe will be on the high end of our typical out year leasehold maintenance CapEx level.

This is an important point, and so I would like to reiterate it.

We are all set with our asset base, with the exception of the sale of the Permian and a few other minor odds and ends that we have left for sale later in 2012 and in 2013.

Quite simply, as a result of our innovative approach to the business and hard work during the past seven years, we now have a very focused and exceptionally high-quality asset base.

In fact, we think it's the best in the industry.

We've now established #1 positions in the Utica, Mississippi Lime, Granite Wash, Cleveland, Tonkawa, Powder River and Niobrara, Marcellus, Haynesville and Bossier plays.

In addition, we have established #2 positions in the Eagle Ford in the Barnett.

No one else in the industry has assembled anything close to this scale and quality of an asset portfolio.

In short, we built this very strong foundation of 11 #1 and #2 positions in the nation's best plays.

And to make sure I'm crystal clear on this, we have no interest in going to Canada or anywhere else outside the US.

With the very best asset base in the business, it's now time to transition our business from being an aggressive new play identifier, leasehold acquirer, and play developer, into a more deliberate but very high-quality manufacturing company that will focus on achieving exceptional returns on capital on the assets we already own.

So what will all of our hard work actually do for our shareholders?

And what will lead to future stock price performance they deserve?

And why have we been willing to spend multiples over cash flow on liquids-rich drilling at a time of low natural gas prices?

Because it's in order to position the Company to become cash flow positive in 2014 and beyond, and to run a more balanced company as well.

Having now captured and paid for decades of low-risk drilling opportunities that are not more evenly balanced between natural gas and liquid plays, we very much like the future path that we are on compared to the path we were on previously, which was essentially a 100% natural gas focused company.

This transition to oil will enable us to deliver strong returns to our shareholders, and an investment grade balance sheet to our bondholders in the years to come.

And our long-term goals will remain to increase Chesapeake's production and cash flow each year by at least 10% to 15%, while generating exceptional returns along the way.

I've never been more excited about the Company's position in the industry, the strength of our assets, and the coming improvements to our balance sheet.

As a reminder, we have a total of $11.5 billion to $14 billion of asset monetizations planned for 2012, of which we've completed more than $2.5 billion to date.

Throughout the year we plan to bring in another $9.5 billion to $11.5 billion from asset monetization, including the sale of our Permian basin assets; a joint venture in the Mississippi Lime; a volumetric production payment in Eagle Ford shale; the sale of the various non-core oil and gas assets; and partial monetizations of the Company's oilfield service and Midstream assets.

We believe those actions will lower our debt by year-end 2012 to our $9.5 billion 25/25 Plan target, and will fully cover our capital expenditures planned for the year.

Making this transition in just a few years during any time is hard work.

But it's been exceptionally challenging during the time of $2 natural gas.

And even though it's not been easy, it's been worth it.

Consider where we would be had we not embarked on this transformation.

Our operating cash flow for the year would likely have been half what it is now, including liquids.

And based on these metrics, I'm convinced we would have had a single-digit stock price, had we not started to make this shift to liquids four years ago and accelerated last year and early this year.

We expect to be largely finished with this transformation by year-end 2013.

I'll conclude by reminding you what five tasks we are focused on completing for the remainder of the year.

First, we intend to meet both of our objectives on the 25/25 Plan, despite our large production curtailments on the gas side, and despite low gas prices themselves.

We expect to end the year at $9.5 billion in long-term debt, and we'll have grown our production by at least 25% during 2011 and 2012.

Second, we monetize intend to monetize the total of $11.5 billion to $14 billion of assets this year through property sales, JVs, and other asset monetization transactions.

Third, we intend to continue to demonstrate that we can consistently find new proved reserves at an all-in cost of less than $10 per barrel of oil equivalent.

In the first quarter, our finding costs were only around $7 per barrel of oil.

And you can't go wrong in this industry if you can find oil and gas in the US at $7 per barrel.

Fourth, we will remain focused on our goal of reaching 150,000 barrels per day of liquids production in 2013; 200,000 barrels per day in 2014; and 250,000 barrels per day in 2015.

This is all net of planned asset monetizations.

During the 2012 first quarter, our liquids production was up 46,000 barrels per day over the year ago quarter, to a level of almost 114,000 barrels per day.

We believe this remains the second-best liquids volume growth story in the industry, and in time could become the best.

And if you look at where some of our oilier peers trade today, it appears that Chesapeake's value in the marketplace could be almost fully supported by our oil business in the nation's largest gas resource base is being valued at close to zero.

Fifth, we believe that with a reasonable recovery in gas prices in 2014, along with growth of our liquids production as modeled, our operating cash flow should match our drilling CapEx; and the CapEx funding gap that we have experienced this year and next year and in a couple of years in the past, will be an issue of the past.

By 2014, we intend to be generating around $7 billion of operating cash flow; to have around 4.5 billion barrels of oil equivalent proved reserves; and will have completely transformed our Company from being and only an 8% liquids producer in 2009 to a producer with much greater balance and strength in the years ahead.

These are five big goals to achieve, to be sure, particularly in this low gas price environment, but five that we are confident that we can achieve.

And five that should create significant levels of shareholder value as we complete them.

We are eager to leave behind the controversies of the past few weeks and focus all of our energies on delivering on these key objectives during the remainder of the year.

We appreciate you hanging tough with us.

I'll now turn the call over to Nick.

Thanks, Aubrey.

I'll begin by reviewing our first-quarter results in more detail.

From an earnings perspective, this was on noisy quarter.

So I thought I would address a few of the most significant items right up front.

Approximately $0.03 per share of our earnings miss related to lawsuits and investments accounted for under the equity method, specifically at Frac Tech and Chaparral.

Another $0.03 was driven by higher than expected per unit production expenses, which were a function of increased costs associated with oil wells, which are more expensive to operate than gas wells; and the new Marcellus impact fee, which the state assessed retroactively on all operators.

I'll further note that despite a big increase in the first quarter, going forward we have only increased our budgeted production expenses per unit by $0.05 per Mcfe, and some of this was clearly one-time in nature.

Beyond these two largest factors, gas prices and differentials, including NGL realizations, also played a fairly significant role.

Moving on to liquidity, we had approximately 2.3 billion in cash availability at the end of the quarter, versus 3.1 billion on December 31.

I'll also note that our working capital deficit decreased from its peak level at December 31, 2011.

As more of our production shifts to higher-value liquids, and activity levels decline this year, we expect this deficit to continue to decrease.

We did enhance liquidity during the quarter with a Senior Notes offering, which has a very advantageous feature -- allowing us to call the notes at par later this year with the proceeds from asset sales.

While $2 gas prices have for sure created headwinds for us, as evidenced in our lower operating cash flow projections for the year, we still anticipate monetizing sufficient assets to meet our 25/25 plan.

Those monetizations are moving along as planned, with good success from the Granite Wash VPP and Cleveland Tonkawa subsidiary preferred, both completed in Q1.

The next significant transactions planned are an Eagle Ford VPP and Miss Lime JV and the Permian basin sale.

Further, I'll point out that upon reaching our debt pay down target at the end of the year with proceeds from these asset sales, inclusive of calling the notes issued in February, we will have a nearly undrawn revolver which has a capacity of $4 billion.

As relates to our CapEx spend this quarter and over the last several periods, it's very important to note the glide path downward we are now firmly making.

We did expect to see that start in Q1 of this year, but as Aubrey noted, lingering activity while ramping down, and cost spillover from the fourth quarter held us up a bit.

However, drilling and leasehold CapEx from here begins to dip; the latter, fairly dramatically.

This of course is due to having captured the assets needed to grow liquids production.

And while the time lag from asset capture to cash flow generation will still take a bit more time, and is fighting the headwind of lower gas prices, I'd also like to point out that we have grown proved reserves 34% over the last eight quarters; and SEC PV-10, 84%; with the latter growing much faster due to the higher value assets we are adding today.

Our PV-10 at SEC pricing at March 31 was over $20 billion.

And that the 10-year Nymex strip, it was over $24 billion.

That is nearly 2 times our GAAP balance sheet debt, and well covers the even more conservative analyst debt plus other obligations analysis.

Proved reserves will continue to grow rapidly on the strength of non-proved reserves we already have the rights to develop.

And the increase in our PV-10 is the proof that benefit of our spending programs of the past period.

In addition, we also own substantial Midstream and services businesses, and the latter Company retains an extraordinary collection of assets.

We have lots of options going forward on how to best fund our continuing transition to a liquids-focused company, from our historical gas-only focus.

We remain unhedged on the gas side and are hopeful some of the worst gas prices may be behind us.

From a liquids perspective, we are 60% hedged for the remainder of 2012 at an average price of approximately $103 per barrel.

I would like to mention that we removed our oil and natural gas hedges during the market swing caused by Greek debt worries early last fall.

The plan was to put them both back on, but gas prices never recovered enough to do so, in large part due to the abnormally warm winter.

However, on the oil side, we collected $46 million of cash last year for 2012 hedges that we lifted, and later in the year were able to enter into new swaps with prices roughly $6.40 higher per barrel than the market price when hedges were removed.

On the gas side, we collected $353 million of cash by lifting the 2012 hedges last fall, the gains of which will flow through our income statement this year and provided $0.58 per Mcf of uplift this quarter.

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

Thanks, Nick.

First-quarter 2012 was another very successful quarter in our transformation from an exclusively natural gas-focused driller and producer a few years ago, to a more balanced liquids-focused driller and operator today.

I'm pleased to report overall production for the quarter grew to nearly 3.66 bcf a day, which is now 19% from oil and natural gas liquids.

That's up from a 13% liquids mix a year ago.

This tremendous organic liquids growth is quite an amazing feat for a company of our size.

Our liquids production has increased from 30,000 barrels per day back in fourth quarter of 2009, up to 67,500 barrels a day in the first quarter of 2011, to now approximately 113,600 barrels a day in this quarter.

That's an increase of 46,400 barrels per day, or 69% in just one year.

Taken alone, that 46,400 barrels per day of growth would place Chesapeake's last 12 months of production growth as the 21st largest producer of liquids in the US.

These results are positive reflection of the great liquids assets that we've built; our flexibility to move quickly as a result of our vertical integration; and the operational skill of our organization.

Anyone who thinks we're still just a natural gas story, please take another look.

In fact, we are one of the world's best oil growth stories.

Our front-end loaded CapEx spending in the first quarter on drilling completion activity includes a sizable lag for much higher drilling activities in the fourth quarter.

This gas drilling and completion activity that's accounted for over half of this year's expected activity in just one quarter, as well as we had a considerable amount of non-op participations.

Even though gas rig activity reductions are well underway, from 50 operated rigs at the beginning of 2012 to an expected 12 gas rigs by the end of next quarter, the completions of previously drilled gas wells had to be performed in order to hold the leasehold by production.

As Aubrey mentioned, we completed 57 more gas wells than we spud during the quarter.

We are also reducing previously expected drilling CapEx on select liquids-rich plays; as in some of these plays -- as in many of our plays, we are moving in to more of a development mode that will provide cost savings as well.

We also expect to realize cost savings in the coming months from reduced service costs, and improved operating efficiencies as our ramp-ups in key plays start to level off.

We have negotiated new lower service agreements with key providers in each of our major plays on a broad range of services, the most significant being pressure pumping.

And we expect these reductions will have more significant impact on our capital spending in second quarter and the rest of the year.

Switching to specific operational performances, we'd like to start with our growth in the Eagle Ford shale, which is setting Company production records on a weekly basis.

Just last week we produced more than 55,000 barrels of gross operated crude.

That's a gain of 30,000 barrels of oil since January 1 of this year, which is an increase of 120% in just four months.

We are currently producing gross operated 75,000 BOE per day in this outstanding play.

Our production gains come from across an expansive acreage position; we have a collection of recent wells IPs over 1,000 barrels a day.

And we believe our 475,000 net acres of leasehold were very selectively chosen, and today covers some of the most prolific portions of the entire trend.

Our Eagle Ford operational teams have done a great job adding barrels, and now their further focus is on efficiency.

We have made improvements in our stimulation and completion processes resulting in a higher production without added cost.

In fact, we were able to lower per-well costs by approximately 15% due to faster drilling times and lower stimulation cost.

Infrastructure build out is still key within the Eagle Ford, and we expect to have future production growth fully connected to pipeline infrastructure by early 2013.

And this will help price realizations greatly, and lower our transport costs by about two thirds.

We are currently running 35 rigs in this play, and will average approximately 30 for the year.

In the Miss Lime play in northern Oklahoma and southern Kansas, we have a very active program.

We have 133 horizontal producers and 22 rigs running in the play.

Net production in the first quarter averaged almost 13,000 barrels of equivalent a day.

In terms of liquids-rich play, we find the Miss Lime very attractive economically, given the shallow depths and the cheaper drilling completion cost associated.

We have data room currently active in pursuit of a JV partner, which we hope to wrap up in the coming few months.

In the Powder River Niobrara play, we have nine operated rigs currently running, and our plans are to maintain that activity level threats rest of the year.

We have experienced several recent drilling completion successes in the play, due to our growing understanding of the reservoir, and focusing on the higher pressure and optimally mature areas.

Recent IPs have been around 700 barrels of oil and 1.5 million per day.

And please don't confuse this with the DJ Basin Niobrara, where we and others have struggled outside of the greater Wattenberg field to make this formation economic across a broader area.

Up in the Powder River, the Niobrara is 5000 feet deeper than in the DJ.

And we have now identified an area of approximately 60,000 to 100,000 acres that is overpressured with super-rich liquids.

We believe the returns in this area will be outstanding, and no other public company owns leasehold in this particular super-rich area.

Now in the Cleveland and Tonkawa tight sand plays in Roger Mills and Ellison Counties in Oklahoma, and Hemphill County in the Texas Panhandle, we have 15 operated rigs running across both plays and plan to reduce that to 13 by year-end.

Production for the first quarter was 18,500 BOE per day.

Initial rates for these wells routinely exceed 850 BOE per day.

We are working with others to jointly get infrastructure enhancements in place to move our oil onto Cushing and to gain access to Mt.

Bellevue for our liquids.

And lastly, the Utica Shale play in Ohio, where we are by far the leading leasehold holder and operator, with 10 operated rigs currently working to evaluate our 1.3 million net acres.

We continue to delineate the wet gas window with our JV partner, Total, with outstanding results.

The overall pace of delineation should increase now that other operators are starting to drill in the play.

The dry gas window towards the east is highly productive.

And large portions will be HBP'd by the overlap on our efforts in the wet gas window of the Marcellus.

In the Marcellus we are up currently operating six rigs, and recently tested several new wells with over 300 barrels a day of condensate.

The Utica oil window still needs additional drilling and study, and we are not ready to disclose specific thoughts just yet, although we remain confident that we will have very positive results to share by midyear.

We are testing various completion techniques in oil window, and want to see how they work for us before we release any public information.

To wrap this up, our liquids-rich plays are working exceptionally well.

Eagle Ford is our major force, and is attracting 30% of our CapEx this year, followed by solid contributions from all across our key portfolio plays in the Miss Lime, Niobrara, Granite Wash and Cleveland Tonkawa.

The Utica is our developing giant where we will control all aspects of the development of the play, because of our massive first mover and discovery advantage.

We've trued up our corporate production guidance to exclude all production from expected near-term monetizations, and have tightened our belt on natural gas expenditures, and even trimmed some liquid-rich activity.

Our front-end loaded CapEx in the first quarter 2012 may be misunderstood by some.

But even if so, it still produced excellent finding and development costs of around $7.15 a barrel, and we added 180 million BOE of proved reserves from our liquids-rich clay alone in the first quarter.

We do expect lower rig counts and lower unit cost on all of our plays, and as we move further down the development cycle.

Operator, we'll now take questions.

(Operator Instructions).

Scott Hanold, RBC Capital Markets.

So, obviously, there's a lot of focus on pre-cash flow or the deficit that's out there over the next 18 months, excluding planned monetizations.

But when you step back and look at it -- and obviously there's a pretty call on you guys being successful due to the monetizations.

When you look at it, what is the minimum on the spending you all think you need to do in 2012 to hold your acreage?

Could you cut a little bit more?

Or are you basically running at bare minimum right now to hold your acreage?

Scott, from our perspective it's not really the consideration that drives us.

Our goal is to get away from being this over weighted towards gas producer.

And to do that, we have to spend money.

The good news is, we can spend more money than our cash flow quite significantly, and yet still reduce our debt and not increase our share count.

So, to me, that should be the focus.

Sure we can cut our rig count significantly from here, but I think that does expose some of our leasehold to potential expiry.

On the gas side, we're basically about done.

I think when we get down to two rigs in the Haynesville and that's all we'll need.

The Marcellus, we're actually in a lease renewal program to try and enable us to get down to that 12 rigs we talked about.

So again, this is all a very deliberate plan and today the focus of the call could have been, we're going to live within our cash flow.

It's all going to come from gas.

And, frankly, I think that would be a pretty sad story.

So our plan, instead, starting over a year ago, was to make this transition.

And we knew we had a mess of assets in the attic, so to speak, that we could sell them and yet still and grow our production by 25%, and still pay down debt by 25% and make that transition.

And, of course, to do so in a $2 gas world is tough, but we're up to it.

And that's what we intend to do.

Back to the heart of your question, we have a lot of optionality with regard to rig counts right now.

We're trying to find the optimum level that minimizes leasehold problems and minimizes firm transport problems and also accelerates the transition away from assets that don't produce much cash flow today -- which are gas assets -- to assets that produce a lot of cash flow, which are oil and natural gas liquids assets.

Okay.

The bottom line is, I guess -- I'm not questioning your ability to execute on the monetizations because you've got a pretty good track record.

Can you give us an update, then, where you are with regards to the next few important ones, like the Permian, Mississippi as well as the Eagle Ford VPP?

Yes, sure.

I'll let Nick speak to the VPP, but that's in the not too distant future, I think.

And with regard to Permian, the data room opens next Monday, our physical data room.

I think the virtual data room has been open a little bit.

We have a long line of people who want to be in.

It's the hottest basin in the world, in all likelihood.

From our perspective, it's just not a place we were ever going to be number one or number two.

And I think when all the dust settles here and you look at the Company, what do we want to achieve?

We want to achieve the best returns in the business.

And to do that, I think you've got to be the best at what you do.

And for us, that's going to be to be number one or number two in 11 of the most important plays in the nation after we sell the Permian.

The Permian will get bought either in three packages -- in a group of three packages -- or individually in those three packages.

And there will be companies that either want to establish a presence in that basin, or who want to solidify that.

So we hope to have an announcement there in the first part of the third quarter, and to get it closed in the third quarter.

Miss Lime data rooms have been open now for several weeks.

And I'm pleased with the interest that we see in that asset, and look forward to announcing that as well.

That will probably happen, I would think, before the Permian.

Nick, do you want to add anything on the VPP?

No, it's like you said, it's relatively near-term.

And we're working through that.

But those are transactions, obviously, that we have a lot of confidence in.

We've completed ten before and we have a lot of confidence in this one as well.

Okay, fair enough.

And one last question on your founders well program.

If I'm not mistaken, that wasn't necessarily a conveyance of well bores.

Do you do hold acreage when you opt into the wells?

Is that right to any kind of down-spacing opportunities, would you also be involved in?

I believe, Scott, the language is governmental spacing unit.

And so, yes, I paid for that acreage and then I receive an assignment of the governmental spacing unit.

Understood.

Thanks, guys.

Doug Leggate, Bank of America Merrill Lynch.

My question is on the projected guidance net of the asset sales, because clearly you've got confidence in the line of sight now to give us an indication of what happens when you monetize your assets.

What I'm trying to understand is, the longer-term guidance hasn't changed, and obviously you're knocking out a fair amount of production on liquids next year.

Can you help us with the moving parts?

What are you assuming from the VPP, the Permian asset sale and the Miss Lime?

And then, looking longer-term, what's coming in extra that's making up the difference, that allows you to stand by the 250,000 barrels that you target by 2015?

I'll take the longer-term target and let Nick talk about the shorter-term.

Long-term, Doug, is simply that we don't have to have all of the assets we have today to meet those targets.

And so while selling the Permian or selling 25% of the Miss Lime certainly impacts 2012 and 2013 production -- and that's why we brought down our guidance -- it doesn't do anything in terms of our ability to meet our out year targets because we'll simply have drilled more Eagle Ford wells or more Utica wells or more Cleveland Tonkawa wells that we otherwise would have.

Of course, remember the Miss Lime JV also allows us to accelerate drilling on the assets.

So not only does it save us CapEx, but it also drives our production higher from an asset after we do a JV.

So the Company has the ability, through all of its liquids-rich asset plays, to meet its out-year goals.

It's simply the $2 gas that's required us to take a little bit of a step back here, and sell more deeply into the portfolio.

But it doesn't have any impact on 2014 and 2015.

So I'll let --

Yes, from a near-term perspective, Doug, we baked all of this into our guidance now, as you point out.

And one of the changes is from previous looks at this, we've moved our Eagle Ford VPP up in the year, and so that has a bigger impact on near-term production as a result.

VPPs are , of course, are assets that we've transferred the rights to production, but only in certain well bores.

Those well bores decline, so the impact of that VPP sale over time diminishes greatly.

So that's one of the reasons why you sell a lot of production up front and that changes your near-term production guidance, but it doesn't change it as much in the out-years.

And, of course, we don't sell any rights or anything around those well bores, so we retain all of that growth prospectivity around the Eagle Ford.

That's really what drives some of that

Okay, I appreciate that.

My follow-up, Aubrey, is really more of a conceptual question.

Clearly, the market doesn't really seem terribly receptive to what's been happening here recently.

And looking at your share price now, you're basically laying out more than $15 billion of asset sales over the next two years.

My understanding is some of your newer leases, the liquids-rich leases, have longer dates of expiry.

So maybe you've got a little bit more flexibility there perhaps.

But my question is why not redirect some of that capital back to buying back your stock at these levels?

We first have to get our debt down to where we want it, Doug, and then I think that can be a legitimate portion of our strategy going forward.

Clearly, you get half of something for free here when you buy our stock, in my opinion.

You buy our gas business and you get the oil business for free.

Or you buy the oil business and you get the gas business for free.

You buy -- Nick mentioned the PV-10 of our proved assets using just the ten-year strip of $24 billion.

That doesn't include our oilfield service business, our midstream business; so that means you get all the unproved for free.

So there's something free here that is substantial, no matter how you look at it.

And so we're trying to get to that promised land as quickly as possible.

And maybe some people think you should just sit there and be stuck in the mud of $2 gas prices but we don't believe that's the way to go.

So, as a consequence, we're going to spend the capital needed to make that transition but we're going to decrease our debt and not increase our share count to do that and I think it's pretty extraordinary.

If in 2013, we get to a point where our debt reduction targets have been met, we're satisfied our funding has been met, and our stock price still represents a compelling opportunity, there's no reason why we couldn't redirect capital towards that.

Aubrey, I don't want to labor the point, but let me be clear what I'm asking you.

If you've got a lot of flexibility in your capital expenditure, why not just defer that and buy back your stock today?

Because the Board and management's twin number one goals are to reduce our debt as we said we will under the 25/25 Plan and to make the transition from gas to oil.

That's the best way to have a long-term, sustainable company and to buy back our equity at this point, in our view, does not create the long-term sustainability that we want from a balance sheet perspective, and from a corporate asset productivity perspective.

All right, I'll leave it there, thanks.

Neal Dingmann, SunTrust.

Just two questions.

First, Aubrey, just wondering - I notice you tend to go non-consent on a few more wells than typical -- your comments on that, going forward; is that going to be a routine pattern, or how do you see that playing out?

Yes, but that's really only gas wells.

And specifically, primarily, the Haynesville.

We had a couple of operators there that still were -- are more active there than what we would care to be, and so we only lose a well bore when we do that.

And I'm not exactly sure on the non-consent penalties, but they can be 300/300 or 400/400.

So you're back in at some point.

But we have now, close to, I think, 6,000 wells left to drill in the Haynesville.

So we if we lose our well bore rights to a few that are operated by others, that's okay.

And we didn't do that in the first quarter because the elections for those wells would've been made in the third and fourth quarters of 2011, when gas prices were projected, obviously, to be about double where they are here.

We're in a situation where gas prices have been halved from where we thought they would be at the beginning of the winter and that doesn't have your cash flow from those assets.

It basically wipes it out, because you have obviously, fixed costs.

At any rate, as a consequence of where we are in the gas price world, we are obviously making lots of changes here, and not the least of which is to not elect in gas wells being drilled by others on a much more selective basis.

Okay, and then just moving on, and maybe either you or Steve, just wondering on two things here.

First, either in the Utica and then look at the Eagle Ford, obviously I think in the Utica because the state always wants that peak rate I understand why you put that out, or just maybe seeing if you could help us understand -- behind either like the Shaw or the Burgett or any of the three that were talked about.

Maybe what the typical sustained rate is today, versus just that peak rate out there.

And maybe if you could do the same thing in the Eagle Ford, around that McKenzie D 3H, as well as the Blakeway.

Neil, I don't have that with me on what those wells are making today.

They're declining, like most all of our shale plays.

We're very pleased with the results - good IPs, it's oil, high-liquids so this is a great play but the reality is, we only have nine producers so, not much data yet.

I was just going to point out that the Buell, it's really an important well and the Buell was the well that was shut in for the longest before it came on.

One of the approaches we've taken in here is that we're not bringing our wells on immediately after completion.

Sometimes that's due to pipeline delay, but sometimes it's due to certain engineering and production performance benefits that we get by leaving them shut in for a while.

If you look at the Buell, at least 575,000 barrels of liquids, and 13 bcf of gas, it may very well be our best shale well ever so I think that's a great indication of what's likely to come going forward in that play.

But you are never going to get the information you probably desire from the state reports, because it's never going to report liquids.

And it's always going to be a peak rate so I think we will just have to watch the play develop.

The good news is, a lot of other producers are getting in the area and starting to talk about it more and I think you'll be able to triangulate in to what we see, which is how could we be more pleased with the play, when in one of your first wells you drilled your best shale well ever, after having drilled thousands of shale wells?

I think it really bodes well for the play going forward.

Aubrey, what's your forecast about the western flank of the Utica?

What are your expectations a little bit even further west than you've drilled?

Well if you mean by western flank, if you're meaning the oil window, I would probably characterize it a little bit differently.

We would look at our oil window as not being on the flank, but instead being right up against our wet gas window.

Again, we've been careful not to say how much of our oil window acreage -- which is around 400,000 acres -- is likely to be prospective, because we just don't know yet.

We haven't drilled enough wells there.

But, obviously, we're very encouraged by the Anadarko wells that have been drilled to the south in the oil window.

And so I think we'll know a lot more in the next 60, 90, 120 days, both from our own drilling but also that from others.

There have been a lot of people who said we couldn't crack the code in the oil phase of the Eagle Ford as well.

And we routinely bring in wells at 500 to 1000 barrels a day there.

We remain confident about the oil window at the Utica.

It's just that our focus to date has been on something that we knew would work well, and that was the wet gas side of the play.

Very good, thank you.

Monroe Helm, Barrow Hanley.

I'd just like to follow up on the comment that one of your colleagues made earlier, about taking hedges off last year.

Can you walk us back through what precipitated taking off your hedges on the gas side?

Certainly be happy to, Monroe.

So, first of all, to give you some context -- since 2006, I think, our gains have been about $8.5 billion.

I think that's by far the best in the industry.

Our track record is not perfect, but I think that's pretty good.

What happened last fall is that in one of the Greek-Euro market swoons oil prices dropped down to lower levels.

Gas prices dropped, we thought, without any regard to fundamentals.

So we took them off and looked to put them back on when things stabilized.

In oil, we did; we got, I think, all of our oil hedges back on at I think it was $7 or $8, maybe higher, than where we had put them on.

So that created a lot of value for us.

And gas just -- we never got the chance again.

Obviously we are not happy with that decision.

If we had to do it all over again, with the hindsight of winter, we would have obviously done something different.

But, to me, it's a little bit like owning a stock, and everybody's owned a stock.

It's met 80% of your expectations and then you begin to think about is the time to sell, is this what I came for?

And for us, we thought we had received a gift, a downdraft, unrelated to fundamentals of the US gas market and we thought we would take advantage of that.

We have routinely done this in the past and been quite successful.

This is the only time that I can remember that we took hedges off and then it just fell away from us.

So, we got most of what we came for.

And, honestly, we probably would have probably never kept them till today.

If gas prices when they started to fall aggressively in December, January, we would have continued to probably lift, for the reason that I stated.

We would have captured most of what we came for.

Today, where are we?

We're in a gas market that looks bad but at the same time you've got the demand pickup from coal, you've got producers -- look at us, we've gone from 100 gas rigs running at the start of 2010, and we're going to be at 12 in 90 days.

Our gas -- and we have talked about this, but our gas production from a peak production capacity in 2012, 2013 will decline 10 or 12%.

This is a company that is single-handedly responsible for 25% of the gas production growth in the whole US over the last five years and our production going down by 10% to 12%, really guarantees that there'll be a different gas market going forward and you're well aware of all the demand initiatives underway so I hope that gives you some further insight into the decision that we made.

Okay.

Can I ask a follow-up?

Sure.

Your gas wellhead realizations seemed to be lower than what would be indicated by the futures market or the spot market.

Are your wellhead prices being affected by the need to make payments to pipelines in you agreements for take-away capacity?

Or is there something else going on?

Or am I totally wrong?

I don't think we've had to make any firm transport payments yet.

I'll let Nick correct me, but --

Yes, we've made, as we've discussed in our filings, we've made some payments under minimum volume commitments; Chesapeake Midstream Partners, over the last couple of years.

If we've made any other FT payments thus far, they've been relatively small.

It's been a part of our calculations to determine how much gas we were comfortable with curtailing this year.

And so there are optimal points where you might be willing to make some of those payments versus producing the gas.

But, in general, transportation costs around the industry are relatively high.

Getting gas out of the Barnett is quite expensive; all that infrastructure had to be built.

And it eats into our differentials considerably.

Further, gas transportation out of the liquids-rich plays, can be expensive because the volumes are not all that high, but the infrastructure still has to be built in order to get the oil to flow.

And Monroe, we did increase our expected differentials, I think, in our outlook as well to try and account for that.

And in NGLs going forward, right now, they're below.

But we think plant turnaround season will bring them back up.

So long-term we've spent a lot of time studying NGL markets and believe that the growth in NGL demand will keep up with supply, generally.

But there will be times, perhaps, when NGL prices can be weak for a couple of weeks.

Okay, thanks for the answers.

Jeff Robertson, Barclays.

Aubrey, in the oil part of the Utica play, with the results you all anticipate later this year, is that a candidate for some sort of monetization in the future, either a joint venture or another one of these asset-level preferreds that you all have done?

Yes, definitely.

Jeff, we really have two more JVs we could do in the Utica.

One is on the dry gas side, and the other is on the oil side so I think ultimately we can do three there.

The question is just time.

I don't think now is the time to do one on the dry gas side.

If someone approached us with the right idea, we might look at it.

But in terms of the oil side, we just have to wait to be able to confirm that we've got a viable play there, and we think we do, but don't have enough wells yet to prove that.

I think if you look into 2013 and say, okay, well, you know, you've got another funding gap in 2013 as you continued to make this transition to liquids from gas.

Where's that going to come from?

I think the Utica is certainly another area that you could look at for us to do JVs that would create quite a bit of value for us.

Would a monetization there -- I guess it would then, probably, impact the liquids progression that you laid out, which, I think -- or will it?

No, it wouldn't, Jeff, I mean we really have very little contribution models from that area right now, so these out year estimates really do assume that we continue to meet our obligations.

For example, in 2013, we've already accounted for the fact that we'll be selling some assets.

We think that we've got that all accounted for, in both our short-term and our longer-term asset models.

And secondly, do your asset sales targets for this year include any other acreage monetizations, like the Woodford deal you all announced a month or so ago?

You've got acreage in, I think, you said the Woodbine.

And you all have had acreage up in the Williston, and probably other areas as well.

Yes, we're still working our Williston acreage.

It doesn't look like it's going to work for the Bakken or the Three Forks.

But we've got some other ideas there, so haven't given up there.

We're getting ready to complete a well in another formation.

DJ Basin, has not worked for us in the Niobrara, although the Powder River is working quite well.

Those are two areas -- plus, you mentioned the Woodbine -- all of which we've accounted for in our go-forward plan.

Again, sometimes you try to get in plays; and sometimes you're successful with where you want to be, and sometimes you're not.

Again, as we look at the Company going forward, we want to be real simple about our goal, which is, if we own it we're going to be number one or number two in it and if we can't get there, then we're going to sell it, let somebody else consolidate their position.

We're big believers in the vertical integration and also to have scale in these plays.

Because -- this is an important point -- that going forward, the Company is going to look dramatically different than what it's looked in the last seven years.

We've gone through a tumultuous time in our Company's history and in the industry's history.

The industry's 100 years of history has been completely remade in seven years, and we helped make some of that history.

And we participated in the rest of it.

But going forward, we are not looking to take what we've learned and go overseas or go to Canada.

All we want to do is drill wells on acreage that we already own, and to turn this into a high-margin manufacturing business.

And I think we can do that.

To go retool your factories while they're running and while they're running today, producing 84% gas, when the gas doesn't make much money, it's a daunting challenge but the alternative of sitting there and doing nothing and just waiting for gas prices to recover, I know that's a losing strategy.

And I think our strategy will be a very winning strategy, going forward.

And we've just got to get through what's going to be a tough year this year.

A lot of concern about our asset monetizations, but of all the things we've done well over the years, I think to deliver those has been certainly one of the things that we've done best.

Anyway, looking forward to getting into a time of better gas prices; but more importantly, a more balanced strategy, with regard to gas and oil and winnowing our asset base down to those things where we're only number one or number two.

Dave Kistler, Simmons & Co.

Real quickly -- in your prepared remarks, you mentioned being free cash flow positive in 2014.

Can you give us a little bit more color around the assumptions that drive that?

And would CapEx ultimately be the plug to achieve that commitment?

I'm sorry, was what the plug?

Dave?

CapEx, maybe?

Well, sure.

That, and if we had to sell an asset, that would be the plug.

But right now, we are anticipating around $7 billion of cash flow.

I think the oil price there is around 100.

And I think gas prices are in the $5 range.

So that's not much higher than where the strip would be, I think, particularly once we get through the summer and work off a lot of this balance.

You have prices today that are unsustainable and the good news about unsustainable trends is that they're unsustainable.

This will get itself fixed in at least the next year, if not closer.

Anyway, that's our goal in 2014 and we'll toggle CapEx to get there.

If we have a little bit of an asset sale at some point, we can do that as well.

Okay, that's helpful.

Just maybe following up on that, in your forward guidance for 2013, gas prices now targeted around $3.50 an MCF down from $5.

You talked a little bit about the 10% to 12% reduction in gas production between 2012 and 2013.

Seems like that might be a little inconsistent with that $3.50 number that's obviously contributing to a larger cash flow deficit versus CapEx that year.

Can you just give us color on why you think it's $3.50?

Are you airing on the side of caution?

Or is that firmly where you think you are?

Yes, no, Dave, that's exactly right, we are airing erring a bit on the side of caution.

We tried to true it up pretty close to the strip.

I think, actually, now we're a little even below the strip for 2013.

We give a range, of course, from 3 to 4 on 2013, and tried to pick something where the strip was approximately in the middle.

We're pleased that, frankly, it's relatively conservative.

And it's a good reminder that there are a lot of variables here at play and we continue to try and be flexible around those variables.

Right now, we're certainly focused on the fact that gas has been weaker than the entire market expected it to be in 2012.

And we're doing all the things that we think are prudent to aid in the recovery.

And we don't want to be optimistic about what gas prices are going to be in an improving way.

So, this is just being clear about what our expectations are, and how we think about running the business from a flexibility standpoint.

Okay.

And just building on that a little bit -- Aubrey, you had mentioned that the rig count cut had gone from 100 rigs on the gas side down to a projected level of 12, and that's driving a 10% to 12% reduction in indirect gas production for 2013.

Do you think that that's the kind of cuts we need to see across the whole industry in order to balance this out?

Obviously, we've seen 40%-plus cuts at this point but how much deeper do you think they have to go to true up to the same sort of experience you're having?

Well, I think the question is complicated, in the sense that you have to factor in the winter where you didn't burn a Tcf of gas, which is 4% of all the gas consumption in the US just didn't happen.

A lot of people, in my opinion, are looking at today's gas price and saying that that is a function of where gas supply and demand are at this price, when the reality is, if you put a Tcf of extra production or less demand into the market, as a consequence, you've got to get rid of it and to do that, you've got to lower the price.

And the good news is, for the producers -- while this is a very painful year -- we're going to incentivize decades worth of increased gas consumption as a result of what's happening this year.

You've just got to get through it.

We'll get through it.

My view is that we'll over-cut on gas drilling.

And you'll probably be surprised by the rebound in pricing.

That's one of the reasons why I'm so in favor of LNG exports, is I think it provides a relief valve.

This kind of yo-yo back and forth on gas drilling activity is hard on the industry; it's hard on the shareholders; it's hard on service companies; and, ultimately, it doesn't help the consumers, they are concerned about it as well.

Whereas if you had an export capability when you had a winter like this, you could just step up exports and have a balanced market.

I think we're headed there.

Cheniere will get us there, plus other facilities.

And so we view that we are taking the proper steps by curtailing production and slashing our gas drilling to a minimum and we're determined to be a big part of the solution to the gas market overhang that exists today as a result of the winter.

We'll see what the summer brings.

Hopefully, it will be 120 in Boston, 140 in Houston and we'll get rid of this in the same way that it came to us.

Appreciate that.

One last quick one on the curtailments.

Looking at the levels for February and January that you've done so far, and then looking at what you're projecting for the balance of the year, it looks like at some point this year you're going to be reducing those.

Can you give us kind of a timing of that?

Are you reducing them currently, and then expecting you might have some more in the fall?

Or how does that map out to true up full-year guidance on that?

Yes, we're not going to disclose specifics on that.

No need to telegraph our plans to the market.

But, clearly, if you look at our previous guidance to now, we anticipate the market cleaning itself up faster than maybe what we thought before.

We've seen pretty strong demand increase on the power side and so we feel like we'll be able to reduce some of our curtailments going forward but at this point, have no interest in being any more specific than that.

I hope you'll understand that, thank you.

To clarify one point you made though, we did not start curtailments until February.

Okay, okay.

I appreciate it.

Thank you guys so much.

David Wheeler, AllianceBernstein.

Aubrey, on the finding and development costs, you talk about $10 going forward.

I always think of the oil and liquids plays when I talk to companies and they give you the well costs and the EURs as something like a $15 to $20 F&D.

Can you talk a little bit about how you see the $10 F&Ds?

Is that sort of a benefit of the JVs carrying some of your capital?

Yes, David, I think there's quite a few things embedded in that.

First of all, we will go forward, always be able to find gas, and so I think our Marcellus finding costs are less than $1 and Haynesville and Barnett, if we ever get going there again, are probably just above that range.

So you'll always have that contribution.

And then we are in some low-cost plays.

If you look at the Mississippi finding cost, you look at Eagle Ford finding cost; we think, on a blended basis, that we should be able to be in that $10 per barrel number.

Remember, Dave, that's almost a 40% increase from where we are today so we are modeling that as we go forward, those costs should jump up, as more and more of our finding is related to liquids plays rather than gas plays.

Yes, as well the margins.

You mentioned cash flow -- I just wanted to ask you a couple questions on the long-term growth expectations.

You mentioned cash flow positive in 2014 and cash flow on the order of $7 billion and you also mention a 10% to 15% growth rate for production and cash flow.

I think that's a longer-term number.

Is it the right way to think about this, $7 billion of spending-ish should get you to 10% to 15% growth?

Yes, I think that's the right way to look at it, Dave.

And of course, it is dependent on gas prices.

If gas prices never get above $3 or $4, then we would continue to need to make asset sales but in our models, at $5 gas and $100 oil, we're balanced in 2014.

And that's our goal.

We've been trying to get to a point where we have a business model that -- we think what we have today is defendable and sustainable.

But when it depends on selling part of what you find every year, people will never be comfortable with signing on for that.

So what people always want to do, and this is proper, is to look at what you're operating cash flow is, and your projected CapEx, and look at if you got a deficit or if you got a surplus at that point and that's where we want to get to but we could never get to that balance in 2014 if we were to remain a 90% natural gas producer.

That's why all the heavy lifting in 2011, 2012 and 2013 to take the nation's second-largest gas producer and turn it into a top-10 oil producer.

Probably by the time we get done, we'll be close to a top-five oil producer in the country.

I think people will be, frankly, astounded that we've been able to do it, and been able to do it without increasing our share count, while still bringing our debt down.

Okay, good.

And one last one for you -- gas reserves, given the slowdown in drilling for gas wells, you guys have, I think, 7 tcf of one peak gas reserves that are undeveloped.

Do you anticipate some reduction in the proven gas reserves because of the slowdown in drilling?

I don't think it will be slowdown.

We'll probably lose reserves through this year as the impact of the SEC pricing rolls through.

You remember, we're now on a, basically, trailing last four quarters basis and so some of those PUDs certainly will be exposed to lower gas prices but they won't go away from a resource base.

They'll come back to us in 2013.

The five-year rule is we are fine there.

Because, again, we project to get back after it once gas prices recover.

And we think the market will continue to need more gas as these demand initiatives kick in.

If you see us lose reserves through the year, it will be from the mandated SEC pricing, not from having no expectation of being able to drill the wells.

Thank you.

Brian Singer, Goldman Sachs.

Following up on Dave Wheeler's question, if we look at your 2013 guidance for proved well costs, unproved well costs, Midstream capitalized interest and dividends, i.e., your ongoing cash outflows, we get to about $10 billion at the midpoint.

As you were just discussing, it seems like you're assuming a much lower ongoing rate of spending.

Can you speak more specifically about where that flexibility is to reduce?

And assuming that you do plan to maintain your 2013 rig count in future years, shouldn't we see some upward pressure as a result of carried interest from JV from joint ventures rolling off?

When you say pressure, you mean higher CapEx?

Yes, exactly.

One would assume that your 2012 and 2013 spending is benefiting from some of the carries from joint ventures.

Of course, you're planning on consummating new ones but wouldn't we see as, some of those carries roll off, and you don't reduce your rig count, that your CapEx pressure would rise?

Yes, let's review where we are right now.

Steve, help me on this.

Obviously our Haynesville carry is gone.

Our Barnett carry is gone.

Our Eagle Ford carry is gone.

Our Marcellus is done.

So we have no more left there.

So really the only carry we have left right now is the Utica wet gas and the Niobrara - we do have CNOOC carrying us in the Niobrara.

So actually, as those continued to roll, we'll actually be rolling on the new ones.

I think for the Utica oil -- and then, also, the Mississippian as well.

So, actually, we've calculated all that in.

Steve, you might just hit us with some percentages.

I think in 2013 our budget is 30% Eagle Ford, is that right?

Yes.

Well, it's actually greater, that's almost 40% --

30% in 2012, about 40% in 2013.

39%.

So glancing at our schedule for 2013, we're going to average, 11 rigs on the gas side.

And then just in place plays like the Mississippi, we are at 22, the Utica, all-in, around 22 and then if I add up the -- back up to around 33 in the Eagle Ford.

And then if I add up the Anadarko basin, you are at around 23 to 25 or so.

Basically when you look at that Company in 2013 -- Eagle Ford, Anadarko basin, Utica, will be the prime drivers so, again, the focus on almost all oil.

And based on what oil prices do, based on what gas prices do, we'll modulate around that.

But the goal is to be at 2013 and have our CapEx be right in line with where our cash flow is.

I'm sorry, that is 2014.

Sorry, 2014.

Right, so I guess going a $10 billion number to a $7 billion number, is there anything specific, beyond potential rig count reductions, that people might not be focusing on as one-off aspects of the 2013 budget?

The major thing, Brian, is just rig count.

In the fourth quarter, we were running 172 rigs.

In the third quarter this year, we'll be running 125.

That's almost a one-third decline.

So I think it should be pretty obvious where it's coming from on rig counts.

And then, we do think we'll see lower costs in the first quarter, took the brunt of third and fourth quarter 2011 per unit costs.

And Steve, you know, frac costs and all that are down sometimes 25%, 30% or more.

Oh yes, per unit costs are way down.

Efficiencies are going up, because we've done some ramp-up but like in Eagle Ford, we're just getting better every week.

And as you said on costs, we did have some overhang.

We had 20 frac crews running in gas plays at the end of the year, and we have six today.

So that spend is just way down.

Got it.

Okay, and separately, as you move into development mode, and as your lease acquisitions are reduced, do you anticipate needing any meaningful human capital shifts away from those focused on land acquisition?

Or are there meaningful land- and title-related issues that remained?

Do you see any G&A savings?

Those numbers will continue to go down, as they have.

We probably, at our peak, had over 5000 people in the field.

Obviously most leasing, but a lot doing work getting wells ready.

That's why you make them contract employees -- not employees, but why they are contractors.

We're continuing to shed in the field, and will going forward.

Because we'll be down in maintenance CapEx levels of, I think, not more than $500 million a year in 2013 and beyond.

You'll still need people in the field to make final deals with holdouts and to get damages settled, and get abstracts built for title opinions and so forth but in terms of having the massive army -- it's not needed anymore.

Because, from my perspective -- and I think the rest of the management team shares this -- is we embarked on a journey seven years ago to participate in the remaking of the industry.

I think after this year, it will have been remade.

If you stayed with conventional assets you completely lost out.

If you started late to unconventional assets you're probably now forced to go buy them in the form of a Company or in the form of an asset collection.

I think, going forward, companies like us will be incredibly favored, as we have these number-one and number-two positions in 11 plays; and all we do is focus on driving returns higher from our existing assets.

95% of the people who have ever heard of us, who have ever followed us, have never known us in that kind of a mode.

It's going to be a big surprise for people.

But it's going to be the absolute inevitable transition from this participating in a seven-year unconventional resource revolution.

We're excited to turn the page.

This has obviously been stressful.

It's hard work.

It's not easy.

But the prize that we're after is to have the best asset base in the industry.

And I think we've achieved that.

And now, from that best asset base in the industry, our goal is to achieve the best returns in the industry.

If we can do that, I think that we are likely to be a company that will be a great performer for investors going forward.

Thanks.

One last very quick one -- did the increase in your 2013 liquids differential reflect a more cautious view on NGL prices or a greater percentage of NGLs in your mix?

Mix stays the same; just all about the problem with ethane prices that we're going to encounter from time to time.

Thank you.

Matt Portillo, Tudor, Pickering, Holt.

Just two quick questions for me.

In terms of the infrastructure side of the question, can you first provide some color on the possible volumetric commitments for take-away from your dry gas plays and does your current guidance for 2012 and 2013 ensure that you'll meet those commitments?

And then the second question, just along the lines of the VPP and the Eagle Ford -- could you divide any detail on how much production you may actually put into that VPP?

No, we're not ready to provide exact guidance on a VPP that hasn't yet closed.

So I'll just hold off on that until we have a completed transaction to talk about.

But I will just reiterate that it is baked in to our guidance that we've provided today.

On the commitments related to minimum volumes, et cetera, those are detailed in our filings.

And we take all of that into account when we set our drilling schedule and expectations around how much we want to spend at wells that we want to bring online.

So, at the end of the day it can all be a part of a financial analysis.

We think that we will potentially have some payments to some of our Midstream partners under those agreements.

But, at this point, to we do our best to minimize them.

And timing will affect some of that.

And we'll continue to try and optimize that analysis as much as possible.

Very little in 2012; it would not come into effect really until our gas starts dropping in 2013.

And we'll do our best to keep those as close to zero as possible.

And is that included in your LOE guidance, just from a modeling perspective, we can take that into account?

It would come in in our differentials.

Great.

Thank you.

Charles Meade, Johnson Rice.

I know that this has been a long Q&A session.

But two things, I think just maybe this first one for Nick -- the nuts and bolts of the guidance on liquids for 2012 is, as far as I appreciate it, the liquid being guided down versus what we had for February 21, that's new in that Eagle Ford VPP, am I correct?

We had a VPP in there, but we had it later in the year.

One of the big changes is the timing.

And it was smaller.

So we brought a lot of wells online there this year, and so we've expanded the size of it as well.

Is the composition of the Permian transaction the same, in both of those books?

We did not have the Permian transaction baked in to our forecast in our previous outlook.

So that is new in this outlook.

And it's a big driver in the change downward; as the Mississippi Lime was not baked into our outlook the last time either.

Plus, the Texoma sale of Exxon was not in it, as well.

Right.

So there's really a lot more monetizations in there this time.

At the last time we provided outlook, we tried to be clear about what was not in there, even though it was announced intentions -- they were relatively early in their process.

And we did not yet have enough feel for exactly how those transactions would come together.

So we provided guidance without them, and just tried to indicate how we thought you might think about framing those transactions in your analysis.

Got it.

All right, great.

That's exactly what I was after.

And the second piece, looking at the presentation you guys put out today.

There's a lot of really good, new, interesting detail on a lot of your plays, but particularly on the Eagle Ford.

I was wondering if you guys could talk a little bit about what you are seeing across your pretty wide acreage spread there.

If there's any parts of it that you're more excited about, or parts that you are still evened up, still left to be figured out.

And what you're seeing in well cost there?

This is Steve.

We are very excited about results, really, across the whole play.

Our science and engineering teams have done a good job on picking our acreage.

You know, we got into the play kind of late, so we had a little bit better understanding when we bought our leasehold.

Really it's working across our whole play.

So we're very excited about it and we've had excellent results.

Now when we run on 60 wells this quarter, so certainly our knowledgebase and history is growing, and it's all looking good.

Now that we've kind of leveled off on rig count, not ramping up, our teams are really performing well.

As I mentioned, our cycle times or drilling times are down about 20% already.

We've had some excellent service cost reductions, like our stimulation pumping services.

Latest bids there are down almost 25%.

Really good things are happening in the Eagle Ford.

And that's where we're putting our money.

Like I said, next year it's almost 40% of our capital.

It's performing quite well, and we are very excited about it.

Got it.

And I guess what I was after there was that this is shallower than a lot of the other Eagle Ford.

And I know that, for example, in your Dimmit County acreage that's -- Anadarko's had some really great success there.

Not so much with the eye-popping IPs, but more just because it's shallower and lower well cost or drilling compete costs.

But I guess you guys don't want to disclose that at this point.

No, and this is in Texas, and on some big ranches.

And so we're drilling a lot of 6000, 7000 foot laterals there also.

Big wells, but not necessarily super cheap, because they are long laterals with lots of frac stages.

Okay, great, thank you.

Michael Hall, Robert W.

Baird.

We'll take your call, Michael, and we'd like to wrap up the call with yours.

For all I know, there's probably several other questions left, but please call John or myself later today.

But we'll go ahead and take your call, Michael; or your question.

I appreciate that.

Just one for me.

Given the increased dependency on NGLs, consistent with the lighter differential there, my understanding is, there is a less robust hedging market around the NGLs.

Are you seeing any developments in that market?

Or does that fact increase the risk profile of your growth plan in your perspective?

Well, first of all, there's not a good way to hedge natural gas liquids.

I agree with you there.

There's not much you can do except just go with the market.

But we do spend a lot of time talking to fractionators and frackers, and we believe that those folks are making the requisite investments that are needed to keep up with the supply growth.

And remember those are things that can be, for the most part, exported, either in a liquid form or in a solid form.

We're pretty confident that NGL values, at the end of the day in the US, will be supported by what's happening around the world.

People need to recognize that, for example, in Conway, Kansas, NGLs, ethane prices are only 20% of what they are at Bellevue.

But that's going to get fixed.

And just like WTI to Brent is going to get fixed, with the Seaway pipeline and additional pipelines you're going see the Conway to Bellevue discount get fixed as well.

That'll happen in time.

And the US has the lowest feed stocks for the petrochemical industry in the world.

And, as a consequence of that, you'll see plenty of demand pick up over time as well.

It'd be delightful if there was a forward liquid market that we could hedge NGLs into.

But we can't, so we'll continue to look at hedging opportunities for oil and natural gas when the time is right.

Okay, appreciate your color.

Jeff, back to you.

Yes, I think we'll go ahead and wrap up the call.

And if you have any questions, please contact myself, Jeff Mobley, or John Kilgallon and our contact information is at the bottom of yesterday's earnings release.

Appreciate your attendance on the call, and we'll talk to you at the next queerly conference call.

And, again, ladies and gentlemen, this does conclude today's conference.

We thank you for your participation.

You may now disconnect.