Chesapeake Energy Corp (CHK) 2012 Q4 法說會逐字稿

Welcome to the Chesapeake Energy Corporation 2012 Q4 and full-year earnings conference call.

Today's conference is being recorded.

At this time, I'd like to turn the conference over to Mr Jeff Mobley.

Please go ahead, sir.

Good morning.

Thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2012 fourth quarter and full-year.

Hopefully, you've had a chance to review our press release and updated Investor presentation that we have posted to our website.

During the course of this call, our commentary will include forward-looking statements regarding our beliefs, goals, expectations, objectives, forecasts, projections and future performance and the assumptions underlying such statements.

Please note, there are a number of factors that could cause our actual results to differ materially from such forward-looking statements.

Additional information concerning these factors is available on our earnings release and the Company's SEC filings.

Additionally, we may refer to certain non-GAAP financial measures, so we encourage you to read the full disclosure and GAAP reconciliations located on our website and in this morning's press release.

I would next like to introduce the other members of our Management team, who are with me on the call today -- Steve Dixon, our Chief Operating Officer; Nick Dell'Osso, our Chief Financial Officer; and Gary Clark, our Vice President of Investor Relations and Research.

Before I turn the call over to Steve; however, I would like to share with you a few comments on leadership change at Chesapeake.

As you know, Aubrey McClendon, the Company's co-Founder and CEO will retire from the Company on April 1, 2013.

After leading the Company during our first 80 conference calls, he is now stepping aside for Steve and Nick to lead this call.

In addition, a search is currently underway for a new CEO.

The Board plans to complete this search by that time.

Aubrey has had a remarkable career founding and leading Chesapeake and has created one of the most valuable and innovative Companies in the global energy industry.

Two of Aubrey's most important accomplishment are the tremendous asset base that has been amassed by the Company and the talented and dedicated organization he built to develop these assets.

The culture and capabilities of the Company Aubrey created and the standards of excellence he championed have been distinctive and inspiring, resulting in a Company with extraordinary potential.

But his legacy will ultimately be the realization of that potential through the success and value that we all help deliver after his tenure as CEO concludes.

With those thoughts in mind and on behalf of nearly 12,000 employees at Chesapeake, we want to sincerely thank Aubrey for his visionary leadership and for his 24 years of tireless service to the Company, to shareholders, to employees and to the industry.

With that, I'm going to turn the call over to Steve Dixon, who is working with Nick Dell'Osso to guide the Company through this period.

I thank them and all of my Chesapeake colleagues for their continued dedication and focus as we work collectively to develop Chesapeake's world-class assets for our shareholders.

Steve?

Thanks, Jeff.

I'm pleased to report substantial progress at Chesapeake this quarter on three key objectives; improving our production mix towards more liquids, reducing per unit production cost and achieving our targeted capital budget reductions.

Nick will talk more in depth about both the capital budget achievements and our cost discipline in a few minutes.

But suffice to say, I'm proud of what our operational teams have achieved and the path that we are on.

Clearly, we have amassed an enviable collection of assets across 10 of the top 15 key onshore plays in the US.

Now, the task at hand is to convert a decade of industry-leading new play investments into improved shareholder returns.

We are well-positioned to do this, even more efficiently and effectively than ever before.

Over the past three quarters, Chesapeake has demonstrated that we have the people, properties and processes in place to drive liquids production higher, while also containing per unit expenses.

Furthermore, I'm energized by the opportunity to greatly improve our capital efficiency in the quarters ahead.

To this end, during the past year, all of our asset teams have been re-tasked and incentivized to shift their focus from acreage capture mode to meeting budgets and delivering higher returns on capital.

Focusing our operations on the core of the core enables our drilling program to increasingly target the best parts of each play, which should translate into better well results and very impactful capital efficiency improvements.

Through focused pad drilling, our equipment mobilization times will compress, water handling logistics will be simplified, road and pack construction costs will decline, pipeline connection times will shorten and many other economies of scales will be realized.

We are targeting capital efficiency improvements of at least 15% to 20% as we transition to pad drilling.

Before I get to the operations, I'd like to take a minute to discuss our reserve changes during this past year.

2012 was a noisy year for reserve bookings, as low gas prices resulted in the removal of nearly 5.4 Tcf of reserves, primarily in the Barnett and Haynesville Shales.

We look forward to the return of these reserves when gas prices recover.

Additionally, we removed 1.4 Tcfe of reserves for non-price related factors.

This is primarily as a result of the SEC five-year rule, given our change in rig allocations and the high grading of PUD locations due to our shift from natural gas to liquids.

Importantly, production revisions to our proved reserves were positive, 331 Bcfe, as our individual well performance in aggregate exceeded our prior estimates.

With regard to the commodity mix, at year-end 2011, our proved reserves were approximately 17% liquids and 83% natural gas.

At year-end 2012, this mix improved to 30% liquids and 70% natural gas.

Turning now to our asset base, I will highlight two plays that best illustrate the operational excellence being achieved at Chesapeake.

First, the Eagle Ford Shale, which was once again the growth engine for our liquids production.

Fourth quarter liquids production averaged 50,800 barrels per day.

That's up 38,500 barrels per day or 314% year-over-year and up 8,000 barrels per day or 19% sequentially versus the third quarter.

This was in spite of outages at Regency's Tilden processing plant and barge delays for pipeline loading in Corpus Christi that impacted fourth quarter production by approximately 2,500 barrels per day.

As a reminder, approximately 82% of our liquids mix in this play is oil and only 18% NGLs.

Looking forward, we have budgeted our outlook, a year-end exit rate of approximately 70,000 barrels of liquids per day from the Eagle Ford.

Achieving this near 40% growth target is subject to several factors, most notably the operational performance of certain midstream processing plants and the addition of natural gas gathering and compression systems which have restrained our growth in each of the last two quarters.

That said, we are highly confident in the productive capacity of our Eagle Ford play and believe that intermittent midstream issues would only impact the timing, not the ultimate delivery of our production targets.

During the 2012 fourth quarter, we connected 98 wells in the Eagle Ford.

Looking ahead, our goal is to connect approximately 400 wells in 2013, which is roughly the same quantity as we did in 2012, this is while running 14 fewer rigs than last year.

We are able to achieve this by connecting wells currently in inventory as infrastructure catches up and also by benefiting from reduced spud-to-spud cycle times.

We continue to make very meaningful progress in driving cycle times and well costs lower.

Our average spud-to-spud time during the fourth quarter was 18 days.

That's down more than 30% from 26 days in the 2011 fourth quarter.

Over the same time period, average per well drilling and completion costs also fell roughly 30%.

Cycle times have continued further to decrease in 2013.

Notably, we just recently drilled our fastest Eagle Ford Shale well to date in just under eight days.

The asset team has done an outstanding job in this region.

I look forward to accelerating capital efficiency gains in 2014, when the percentage of our wells drilled on existing well pads is expected to increase over threefold from this year.

Moving on to the Utica Shale, we continue to focus our drilling efforts in the wet gas window of the play, inside our joint venture with Total, where we hold more than 450,000 net acres.

I'm pleased to announce that within this area, we are projecting average EURs per well to range from 5 to 10 Bcf depending on the area and the phase of the play targeted.

To date, we have drilled 184 wells in the Utica, 45 of which are currently producing.

Production in the Utica was fairly minimal in the year-end 2012 due to infrastructure constraints.

But we are anticipating a significant ramp-up during 2013, perhaps reaching 55,000 BOE per day by the end of the year.

Helping us to achieve this goal will be gas processing infrastructure editions at Dominion's Natrium processing plant in Marshall County, West Virginia, which is scheduled to go online in April, followed by the first of three processing trains at Momentum's Kensington plant in Colombiana County, Ohio, which is scheduled to go online mid-year 2013, with the second train operational before year-end.

Like the Eagle Ford, Chesapeake is generating significant efficiency gains in the Utica.

Spud-to-spud cycle times have decreased 37% year-over-year from 35 days down to just 22 days.

Average per well drilling and completion costs have followed a similar path and were down 27% year-over-year.

In terms of drilling results, I would particularly like to highlight a well we recently drilled in Carroll County, it's the Coe 34-12-4 1H.

This well experienced a peak 24-hour IP of over 2,200 BOE per day with a liquids cut of approximately 33% assuming full ethane recovery.

We believe we've captured the industry's largest position in the Utica and look forward to solid results in this play for years to come.

Additionally, I'd like to summarize our results in the Anadarko Basin, where we are focusing on five plays -- the Mississippi Lime; the Cleveland; Tonkawa; the Granite Wash; and Hogshooter.

These plays continue to provide steady liquids production growth.

At December 31, we had 29 rigs running in these plays.

Combined fourth quarter net production averaged 104,500 BOE per day, which is up 7,500 BOE per day in the third quarter, or 8% sequentially.

The production mix from these five plays combined, continues to get oilier with 39% coming from oil in the fourth quarter as compared to 36% in the third quarter.

To characterize the year ahead Company-wide, the shift to liquids is progressing in line with expectations and we continue to anticipate 27% liquids growth in 2013.

As planned, our natural gas production is now in decline.

Our current guidance implies a 7% year-over-year decrease in reported natural gas production.

When adjusted for voluntary curtailments and the impact of our 2012 and projected 2013 asset sales, we believe the organic decline in our natural gas production will be closer to 9% year-over-year, assuming midpoint of our current guidance.

As we look at the balance of 2013, there are two major objectives we plan to accomplish.

First, is to continue to execute and build on the strong liquids production growth and cost discipline trends that are already firmly in place.

Second, is to complete the two-year asset divestiture program that we have previously laid out, to fund our capital investment program, reduce our financial leverage and focus our operational efforts on our best plays to enhance returns on capital.

Along these lines, my operational teams have been fully engaged in the asset sales program since the outset and I'm confident they will not miss a beat in executing the program that has been set before them.

Lastly, I would like to thank all the employees of Chesapeake for their hard work, loyalty and determination as we move through this challenging period of low gas prices and a leadership transition.

Our employees have always been and will remain our best asset.

I look forward to sharing their success in many years to come.

I'll now turn the call over to Nick.

Good morning.

Thanks, Steve.

We are pleased with our 2012 fourth quarter results and the substantial headway we made in terms of growing oil production, refining our focus and reducing costs.

Adjusted earnings per share of $0.26 exceeded consensus estimates of $0.14 per share and our production in EBITDA topped consensus estimates by a substantial margin as well.

Our strong performance was driven primarily by oil production volumes, improved oil price differentials and solid execution on the cost side of our business.

We've produced 8.9 million barrels of oil in the quarter.

Only 0.3 million barrels or about 3% of which was attributable to the stop of production from the portion of the Permian sale that closed in October.

Quarter-over-quarter our significant growth areas were in the Eagle Ford and Mid-Continent regions, where we continue to generate high-quality oil growth which is reflected in our strong oil price realizations.

During the fourth quarter, our Company-wide differential to WTI was a positive $0.26 per barrel which is greatly improved from our third quarter differential of WTI minus $4.15 per barrel.

Our outstanding marketing team warrants recognition for helping us achieve these favorable prices, through securing access to premium pricing markets via pipeline, opportunistic entry into oil trucking in certain areas and favorable blending arrangements.

Importantly, less than 10% of our oil production is considered condensate as defined by an API gravity of 50 degrees and above.

Condensate oversupply concerns have been raised in the marketplace recently and I believe Chesapeake has a good plan in place to successfully navigate this issue.

It's also worth noting that, our total liquids stream by volume for the quarter consisted of 66% oil, 34% NGLs.

A favorable mix that further strengthened realized revenue.

We achieved this mix in spite of the sale of our Permian assets, which contained a much higher percentage of oil than NGLs.

On the cost front, the fourth quarter was the first full quarter of the year where our decline in activity began to show up materially in our reported results, with our drilling and completion costs down approximately 30% year-over-year.

We averaged 88 operated rigs for the quarter and spent $1.596 billion on drilling and completion costs compared to 122 operated rigs and $2.275 billion in the third quarter of 2012.

By December, our monthly drilling and completion CapEx run rate was down to approximately $500 million.

We expect our drilling and completion spend to remain roughly in line with this rate throughout 2013.

Further, we came in on budget for January 2013 as well.

This puts us on track to spend approximately $6 billion for the full-year 2013 net of drilling and completion carries from joint venture partners as compared to $8.8 billion in 2012.

I'm also pleased to note that, production expenses came in at $0.83 per Mcfe, down $0.01 per Mcfe from the prior quarter and down $0.05 per Mcfe year-over-year.

G&A came in at $0.23 per Mcfe down $0.10 per Mcfe from the prior quarter and down $0.12 per Mcfe year-over-year.

This decline included the impact of billing a portion of our additional overhead to the full cost pool, due to changes in the COPAS rules so while we do not expect G&A to remain at these very little low levels going forward, our cost structure initiatives are clearly starting to bear fruit as demonstrated by the significant reduction we've made to forecasted G&A as well as other cost items in our outlook on Schedule A of the earnings release.

I'd now like to quickly review some of the significant events of 2012, a year that was heavily impacted by continuing low natural gas prices.

Chesapeake entered the year focused on continued rapid growth of our oil and NGL production, to provide a more balanced source of cash flow generation going forward.

We were running a total of 164 rigs in January of 2012, when the extremely warm winter and resulting rapid and severe drop in first quarter natural gas prices prompted us to further reduce our activity levels.

As a result, we ramped down our drilling program to just 85 rigs by the end of 2012.

Fortunately, we were able to rely on our liquids rich portfolio to buffer the significant impact of 2012 cash flows created by the natural gas price decline and were also able to close on the sale of nearly $12 billion of asset sales during the year.

At the end of year, we were still able to achieve an 84% increase in oil production and a 54% increase in total liquids growth, setting us up for a more balanced 2013 and beyond production profile and importantly holding production on some very valuable oil leases in the process.

To recap the year, our biggest asset sales consisted of exits from the midstream business and the Permian Basin.

Our midstream exit enabled us to redirect the Company's strategic focus and capital resources into our upstream oil and gas operations.

As a reminder, we originally entered the midstream business at a time when the midstream industry's knowledge and appetite for capital growth and unconventional assets was limited.

Entering midstream proved to be profitable and strategically important; however, given the changing dynamics of the MLP space and the increasing maturity of our operations in unconventional resource plays, we concluded that it made strategic sense to exit this business in 2012.

I'm pleased to report that, we recorded a total pre-tax gain on our midstream sales including our gain on the sale of our equity interest in CHKM or ACMP earlier this year of approximately $1.3 billion.

The Permian sales also represented a significant basin exit for us, but one, that again, helped to strategically and financially refine our focus.

While the Permian is a liquids rich basin, it was not going to be allocated as a significant enough amount of capital within our broader portfolio in the coming years relative to our other assets.

With respect to 2013, I'm pleased to report that we are in a completely different position from a liquidity and funding perspective than one year ago.

We began 2013 with an undrawn revolver with $4 billion of availability, which if necessary, could cover our approximate $4 billion funding gap in 2013 which is derived from our updated outlook in this morning's press release.

We look forward to soon announcing progress on our Mississippi Lime transaction, which will further reduce the funding gap previously mentioned and have closed on or have under PSA more than $200 million in aggregated other asset sales so far this year.

Importantly, the Company and the Board of Directors remains committed to reducing Chesapeake's financial leverage.

Let me now walk you through some highlights from our outlook on Schedule A of our press release.

First, we are reiterating our liquids production growth for 2013 and are very pleased with our results to date.

For 2013, we forecast our oil production and differentials to remain strong.

We now project that our oil production will account for more than 51% of our 2013 oil and gas revenue.

Turning to NGLs, I would like to note that we are not forecasting any ethane rejection in our production numbers this year, but certainly acknowledge that some could occur.

Additionally, our NGL growth will be highly contingent on the timing of processing infrastructure in the Utica; therefore, our line of sight on NGL production is less clear than that of our oil production.

That's said, NGLs are projected to account for less than 10% of our oil and gas revenue stream in 2013; therefore, our exposure to soft NGL markets and potential processing delays is not particularly material.

Next, I would like to address something that our organization is very proud of, given the work put into it.

We are lowering our cost per unit expectations across the board -- production expenses, production taxes and G&A.

We remain focused on these metrics and believe that our increased operational emphasis and diligence in this area will help us deliver further reductions ahead.

These cost changes combined with unchanged production from previous guidance has allowed us to increase the bottom end of our range of cash flow expectations despite a reduction in expected average 2013 natural gas prices.

In our revised outlook, we are reiterating our $6 billion drilling and completion and our $400 million leasehold budgets for 2013.

Last quarter, we removed our guidance around oil field service and other CapEx spending following the sale of our midstream operations.

However, to provide a little color there, we expect oil field services CapEx to be lower in 2013 than in 2012 and we are not looking to add any new capacity to that business beyond order for equipment placed earlier last year.

Finally, I'll address our hedge position for 2013.

You've no doubt noticed that we put on a significant amount of gas hedges for 2013 and feel good about being 50% hedged on the gas side for 2013 at an average price of $3.62 per Mcfe.

We are almost fully hedged on the oil side at $95.45 per barrel for 85% of our 2013 production and have also added a material amount of oil hedges in 2014 at an average price of $93.67 per barrel.

We believe these incremental hedges go a long way toward de-risking our 2013 and 2014 cash flow expectations, despite the fact that we are somewhat bullish on gas markets from this point forward.

With that, operator, we'll now open up the call for questions.

(Operator Instructions)

Doug Leggate, Bank of America Merrill Lynch.

I've got a couple of questions.

I guess I'll start off with Nick or whoever wants to take this one on the asset sales.

Nick, it sounds like you're pretty close to the Mississippi Lime disposal.

Could you share with us any color in terms of whether this is solely an acreage deal or the format in terms of joint venture or whatever?

Or particularly if there's any production associated with your likely transaction?

I've got a couple follow-ups, please.

Sure.

Doug, I'm going to hold back on giving you any specifics on the transaction, given we're in the throes of working on it.

But I would say that there is some production associated with it.

We have included the impact of that in our outlook.

Okay.

Maybe a follow, unrelated then, one of the biggest criticisms perhaps, Nick, of the Company is still the out-spend or the overspend.

You highlighted the liquidity position at the beginning of the year, at least the end of last year.

However, if you don't achieve the $5 billion to $7 billion of asset sales, it doesn't really help you.

So can you help provide any kind of color as to how the Board is influencing the spending decision versus the potential ultimate scale of disposals?

Any comfort you can give us on the line of sight as to how you get to such a big number as $5 billion to $7 billion this year?

Then, I've got one final one, please?

Okay.

We and the Board are very focused on our budget for the year, which as you noted has multiple elements.

It has our spend and it also has asset sales and other costs associated with it.

We're focused on the endgame of where we will come out.

We're focused on deleveraging.

All of those things have to work together.

We are also focused on the fact that through this year we continue to hold by production some very valuable liquids acreage.

With every well that we drill, with every acre that we hold, we become more flexible in our drilling program.

That's a great thing in the short-term.

We are happy and would consider using that flexibility if needed.

Now, that being said, we have great confidence in our asset sale program.

We have good line of sight into what we plan to accomplish.

We think the outlook that is in front of you all today with the $6 billion drilling program and completing of asset sales in 2013 is something that is achievable and that we believe we will achieve this year.

Okay.

Last one is for Steve.

Hopefully -- Steve, you have not changed your liquids guidance now for quite a while but it seems that the oil piece of the liquids growth is running at least ahead of what you were expecting.

Can you just help us understand, what is drilling the core to the core mean in terms of type curves, because you really haven't updated us there since 2010.

If you could just speak to how you see the risks to your liquids, in particular, your oil growth as we move through the next 12 months?

I'll leave it there, thanks.

Thanks, Doug.

We are focusing our capital program on liquids and drilling our very best locations.

That's starting to generate those results.

Probably the Eagle Ford is certainly the biggest driver, where most of our capital is and where we've had the great success.

It continues to impress and improve.

Hopefully, we'll get some more results quarter-over-quarter going forward.

No change to the type curve?

In the Eagle Ford, in particular?

We haven't provided a type curve since 2010, so --

That's what I mean.

It seems to be pretty out of date.

Yes.

So our results, we think, show great growth there and great performance.

All right.

I'll take it off-line.

Thanks, guys.

We'll continue to deliver to you guys out of the Eagle Ford and out of all of our liquids plays.

Arun Jayaram, Credit Suisse.

Nick, I wanted to ask you -- obviously, you have a $4 billion outspend this year.

I wanted to see how the Marcellus could tie-in to the deleveraging of your balance sheet.

Obviously, you have a big acreage position here.

I'd argue it's probably the highest multiple business in US E&P.

The Company obviously focused on liquids.

Why not think about monetizing a piece of the Marcellus?

Arun, we are looking at a number of alternatives on the A&D front for this year.

We have a pretty good plan in front of us.

We have had a couple of non-core acreage packages in the Marcellus out of the market that we had said we were going to do in our third quarter Q. We continue to do that across the board.

Look for the places within our portfolio where we are going to be the most efficient given the footprint that we have and where we have the best results and know that we have acreage that would be more valuable to someone else.

Very good acreage that can be drilled for a great return but within our portfolio as we're going to allocate capital can be delivered to someone else for better return in up front cash to Chesapeake.

So we're doing that in the Marcellus.

We're doing that across all of our plays.

Okay.

In terms of what we have line of sight on today, it's the Mississippi Lime and an acreage package in the Eagle Ford, in terms of upstream assets sales.

Is that fair?

Those are the two biggest that we've talked about publicly.

That's correct, Arun.

Okay.

Switching gears a little bit, you guys recently talked about a 10-year agreement on the methanol front.

I just wanted to get some details on that.

Perhaps are you seeing more industrial customers looking to do similar kinds of things?

We are seeing a lot of interest from industrial customers.

There's been a really big increase over the last couple of years.

But recently, it's been an even probably more concerted effort by industrial customers to talk to us about some creative ideas.

We found the methanol transaction to be very attractive for us.

It links our ultimate delivery to a price of a commodity that's closer tied to crude.

So we can take some gas exposure and tie it in a way that correlates it more to a crude price.

It's something that brings additional demand onto the US market for natural gas.

So we think that we have a great price structure locked in there.

One that achieves a very favorable price for Chesapeake and still provides us with enough exposure to upside to make it interesting, beyond the price at the outset of the deal.

Okay.

One quick one for Steve - where is your Haynesville production today versus at the peak?

I know it was down pretty hard quarter-over-quarter.

Steve, I have that for you here.

Just one second.

Gross, we're down to 1.3 from 2 Bcf a day.

Down by about one-third?

Okay.

That's helpful.

Thank you, guys.

Brian Singer, Goldman Sachs.

A couple questions.

First, on oil mix, can you just talk about how, if at all, you expect your oil mix to evolve and change in three areas -- the Mississippi Lime, the Eagle Ford and Utica?

I noticed that the Mississippi Lime, that oil mix -- oil as a percentage of the total ticked up during the quarter.

In the Eagle Ford, it ticked down a little bit.

Just also wondering when you talk about 5 to 10 Bcfe EURs in the Utica, what percent oil versus NGLs versus gas you would expect?

I'll start with the Utica.

That is still pretty early and results change pretty quickly across the play.

Yields have a pretty wide range.

So, that's why we gave a wide range.

So I don't really have a number to give you on that.

The Miss Lime and the Eagle Ford, we don't really expect the mix to change there over time.

We have pretty good insight now, with those Basins having a pretty material amount of production.

So we feel good about that production mix being reasonably constant over time.

There will be fluctuations, of course, as you bring on different packages of wells.

But we don't expect any material differences.

No.

Those in those places like the Mississippi Lime would be consistent with the 40% to 45% that you saw in the third and fourth quarters?

Or do you expect some kind of degradation over time as well decline?

No, we had 46% gas in the fourth quarter in the Miss Lime, So then, 45% oil and the rest being NGLs.

Again, we don't anticipate any trend difference there over time.

Great.

Thanks.

That's helpful.

Then, just strategically, to the degree that gas prices surprised to the downside, could we expect that Chesapeake would sell more assets than it would be presently expected?

Or reduce capital?

Or borrow against the revolver?

I'm sorry, can you repeat the question, Brian?

Yes.

If gas prices surprise on the downside, should we expect that Chesapeake would reduce CapEx from current guidance, sell more assets than expected or just utilize the revolver and increase an increased debt?

The first answer there is that 72% of our revenue is hedged for 2013 so short-term impacts to commodity prices won't have the impact that it did have on us last year.

The second answer is that, again, we're very focused on deleveraging over time.

So I'll just probably leave it at that.

We have a lot of levers we can pull to get there.

We'll continue to be focused on delivering on asset sales, be focused on staying within our budget and reducing our leverage.

Charles Meade, Johnson Rice.

I was hoping that you could maybe -- I recognize you guys are still in process on a Mississippian sale, but could you give maybe some parameters of a deal that you're looking for both in terms of scope whether it's over your whole 2 million acres or timing?

Charles, I just would really like to not take questions on a pending transaction this morning.

That's certainly understandable.

The other thing I wanted to ask you guys about, maybe this is better for Steve.

I really liked the slides you guys put together on the take-away in the Marcellus and Utica.

I wanted to ask, I think you've mentioned that the Marcellus take-away is going to be limited through up until year-end 2013 where there's going to be incremental to capacity come online.

But, do you view this as more of the last significant hump to get over as far as take-away?

Or do you view this as the first of many hurdles that the industry is going to have in the coming years as far as take-away?

Charles, there are a number of projects as you're well aware.

Some of those projects are more focused on getting us premium market access versus just capacity.

Then some, of course, do provide important capacity relief.

Today, there is planned a total of additional 3 Bcf of capacity additions, as we've noted in that slide.

Some of them have just come on pretty recently.

There will be periods of time where capacity will get ahead of the deliverability in the Basin.

Then there will be periods of time where industry catches up with it.

It's going to be an evolving or a push and pull that will continue over time.

I think pretty quickly here, particularly with gas prices where they are, rig count where it is, you would get to a point where you wouldn't have long-term capacity constraints before too terribly long in the Basin.

Neal Dingmann, SunTrust.

Say, good color all around.

Just wondering on the Utica that you mentioned -- Steve, either for you or Jeff, just wondering, looking at that 5 to 10 Bcf that you gave, can you give a little bit on what type of type curve you're expecting there?

Or I guess what I'm looking at more specifically is, what kind of first-year depletion?

Or if you can give us any depletion levels around those 45 wells that are producing?

Neal, we are constrained there and really haven't been able to produce these wells as we would like.

So that's why we gave a big range in Bcfe.

So I'm afraid it's just too early to tell.

Okay.

Again, I think you said, Steve, was it the 55,000?

Is that just for later this year, once, assuming that you have most of this midstream tied-in?

Or can you maybe walk us through a little bit as far as what you're expecting, as you're the person that commented just on the take-away there.

How to see that progress in the Utica?

Yes.

To reach that, we need all three of those plants up and running before year-end, Neal, which they are on target and expect that to happen.

Okay.

Then just lastly, you mentioned how good your Eagle Ford results certainly have been.

Just wondering, is it just the result of still trying to contain the cash flow outspend as far as why cut those rigs there?

To go obviously, from 34 to 17 rigs on such a great area -- I just wanted your comment about, if that looks like the expectation would be to run around that kind of going forward?

Fortunately, Neal, most of that is in efficiency gains.

We are still able to produce the same amount of net wells.

It's also not to out run our infrastructure.

So this is just the right well count to both hold our acreage and to be more efficient with our capital.

Dave Kistler, Simmons & Company.

Real quickly, just looking at your 2013 CapEx.

Can you break out what percent of that is dedicated to maybe forward drilling commitments?

Or asked differently, what percent is kind of fixed obligations, HBP drilling, et cetera?

What percentage is flexible?

We don't generally provide that break-out, Dave.

Suffice it to say, we are focused on Holding By Production our Eagle Ford and other liquids plays and we still have some work to do there.

Those also happen to be our highest return plays.

So that's really why we don't focus on looking at it that way.

We're really more focused on what Steve describe a few minutes ago, which is allocating our rigs to make sure that we are focused on returns both near-term and longer-term returns.

We don't want to get in front of infrastructure.

We want to focus on the efficiencies that we are creating.

We want to try to drill the best wells.

So, yes, there are a couple of places where we're going to go hold some leases and take care of some commitments.

But that's really not what's driving our rig allocation this year as much as it is trying to be most effective and efficient at growing our liquids production and focusing on returns.

Okay.

Appreciate that.

You mentioned in your comments that you've achieved about $12 billion in divestitures in 2012.

When I'm looking at the cash flow statement, it's highlighting about $10 billion.

Can you walk me through the disconnect or what's rolling over into 2013 just based on announcement dates and closure dates, et cetera?

Just so we can get a sense of how that feeds into your guidance of $4 billion to $7 billion for 2013?

Yes.

Just to reconcile the 2012 number, remember that one of the things we included in that 2012 is the sale of the preferred interest in our Cleveland Tonkawa asset, which shows up in the Financing Section.

So there's no rollover into 2013 of that $12 billion and the 2013 number is focused on new projects that we'll be talking to you guys about.

Great.

Thank you.

One last one, just if you could give us an update in terms of maybe drilled, uncompleted wells or drilled and completed but not tied-in, in the Marcellus and the Rockies as two potential large growth areas for this next year, that would be great.

In the North Marcellus, there is still a couple hundred wells to be turned on, that we want to get in line this year.

One of the things I would point you to, Dave, is on Page 14 of our release.

We break out our well costs.

We have broken out last year, the well costs on unproved properties, which would be basically, dollars that we had spent on wells that were not yet put into the pool because they were not yet proven.

That becomes effectively a balance over time.

So you've seen the last two quarters, that's a negative number.

So net net, we are decreasing the number of inventory wells in the Company at this point.

We've done that in the Marcellus.

We'll continue to do that across the Company with a few instances where we are adding to it in newer plays.

But net net, we're in a decrease mode.

Great.

Thanks so much for those clarifications, guys.

Appreciate it.

David Tameron, Wells Fargo.

In the Marcellus, can you talk a little bit about the pipeline?

Is that an issue with the specs for the BTU content?

Or can you talk a little bit about that bottleneck there?

Then when do you guys expect ATEX to come on?

ATEX?

Yes.

Yes.

We can reject a certain amount of ethane.

Then at some point, we do need that pipeline to alleviate our take-away from the Basin.

But at this point, that's really about capacity as much as it is anything.

So we do think that ATEX will come on in the beginning of 2014?

2014.

Late 2013, beginning of 2014.

Okay.

Are you guys confident right now -- we've just heard from other operators and other industry people that ethane's going to be a big bottleneck getting out of the Marcellus over the next couple years, even with additional pipeline capacity.

What's your snapshot of the current situation up there?

Well, we have taken out a pretty good bit of capacity on ATEX.

So we're feeling good about our ability to move it out of the Basin to the Gulf Coast which should get us to the best market available for ethane in the US.

We do also have a small amount of FT going up to Sarnia as well.

Okay.

Jumping over to the Utica.

I apologize if you may have answered this already, but the EURs you put in the press release, that 5 to 10 Bcf, can you just talk about what production mix is assumed in that number?

Then, how variable it is across acreage position?

Just maybe an update overall on the Utica?

Dave, this is Steve again.

It is pretty early and very limited well set, so that's why we gave such a big range.

It does vary across the play.

So that's all the guidance we can really provide at this time.

All right.

Last question, Nick, you commented on the condensate oversupply.

Can you just expand out a little bit on that and what you're alluding to there?

Just pointing to the fact that we are always focused on getting premium pricing for our products and paying attention to what our product mix is and what the supply/demand dynamics are for the sub products, if you will, in the marketplace.

Given the questions that were raised this week by a number of analysts around condensate pricing, we just wanted to comment on it, in particular, in the Eagle Ford, our average gravity in the Basin is about 45 degrees.

Then I just wanted to give the color that condensate is less than 10% of our total mix of oil across the Company.

So we just thought that was helpful color to provide.

Biju Perincheril, Jefferies.

A couple of questions.

First, on your production guidance, are you assuming less asset sales in the new 2013 guidance?

Or is it the same amount of asset sales as previously assumed?

It's approximately the same, Biju.

The mix has changed a little bit here and there but we always attempt to show our expectations of asset sales in our guidance unless we tell you otherwise.

We had that the last time and we have it again this time.

So we show you at the top of that page, the expected production impact of what we assumed to be sold in 2013.

Got it.

So the difference in the footnote then, I assume, is the asset sales estimated completed, especially the Permian?

Right.

The last time we gave an outlook, it would have been inclusive of production for the end of 2012 as well as 2013.

Got it.

Then, your gas production decline in the fourth quarter, was there anything special in those numbers or is that an organic decline rate that we saw in the fourth quarter?

Well we did have our Permian sale in the fourth quarter which was significant.

There was a lot of gas produced out of the Permian.

We did manage some FT commitments in the Barnett as well, which had a minor impact, but that was something that was not organic.

Scott Hanold, RBC.

A little bit on the Utica again.

I'll try to skin the cat in a different way.

When you step back and look at the Utica today versus what you all thought a couple years back, it seems like it's a little bit more gassy and the core's a little bit smaller.

Is that a fair statement?

Well, the gassy part may not be bad.

Those are higher IPs and can be higher rates of return.

We're very pleased with the results that we're getting.

So nothing bad to say.

No shrink in the core.

It's just early and the results are so variable on the product mix that they're difficult to give.

We did give a couple of specific well results in our release today.

So you guys can look at that and probably draw some conclusions from there.

There's a lot to learn about this Basin still.

Our number of penetrations relative to the number of wells that we will ultimately drill is very small.

We don't yet have the processing capacity to flow things at full rate yet.

There's just a lot to learn.

So that's the reason we're being a little bit less informative here, just because we feel like we need to learn more before we can say more.

But so far, we're very, very pleased with the play.

No, that's fair enough.

What if this does turn out to be a little bit gassier?

Do you see the economics of Utica being a little bit better than Marcellus?

Would there be a lot of excess gas coming out of Basin?

You did, previously, Nick, in your comments, indicated that you all are pretty bullish on gas prices.

Certainly, when you step back and look at you guys locking in a lot of your hedging in your production 2013, it kind of sends a different message.

Can you square the circle around that one?

Sure.

I'd be happy to.

When I say we're bullish on gas prices from here, I'm thinking not just about the next couple of months, just 2013, but really thinking further out on the curve as well.

There's very little contango in the curve.

We don't think that accurately reflects the amount of development being put into natural gas today.

Nor does it reflect the potential increases in demand that are becoming less potential and more real around exports and around other industrial uses.

Our 50% hedging program for 2013 is really about de-risking our plans.

We saw some prices that were respectable within our 2013 plan, know that we have a plan that exceeds cash flow and want to make sure that we protect as much of that cash flow as we can.

So I don't think they're inconsistent, just to be short-term protective while still being long-term bullish, I think makes sense.

As far as the volumes for the Utica, Steve will probably have more color there.

But it's a good Basin.

When markets tell the industry to produce gas, there will be some gas that we can look to the Utica to deliver.

So, then I would assume your bullishness more on the forward-looking on gas prices are a more demand driven than a supply driven story?

Because certainly, there's ample opportunities to ramp up gas pretty quickly in several areas.

We certainly have the ability to ramp up gas when we desire.

I think ramping down and ramping up always takes a little bit longer than the financial markets would like.

But we have a lot of wells you could go drill in the Haynesville that are on existing pads.

You have a lot of wells you could go drill in the Marcellus on existing pads, then certainly, in the Barnett as well.

So -there are many in the industry have the same dynamic so the industry can respond to demand here for a long period of time.

We've got a lot of capacity to do that.

The Utica will be another leg to that stool.

But the industry also is doing a pretty good job of giving itself the flexibility of how to respond and when and to respond to that demand by holding its acreage by production.

Okay.

Fair enough.

I appreciate the color.

Joe Magner, Macquarie Capital.

Just maybe one more attempt at the Miss Lime.

I realize you don't want to discuss some of the details.

But there have been some different structures talked about in the past.

There was a plan to pursue a lump sum JV.

Then that changed to maybe breaking it down into smaller packages.

Any direction on where you're headed with the overall concept there?

I think I'm just going to say again, we don't really want to discuss a pending transaction.

But we hope to be able to discuss it in great detail with you guys soon.

Okay.

Then, in terms of your overall position there, can you provide any breakdown between Kansas and Oklahoma on the acreage side as well as on the number of wells that have been drilled and the production split between the two states in the Miss Lime?

Yes.

There's a map in our slide deck, so you can see the breakout at least visually by acreage in the play.

But you can also see that all of our rigs are in Oklahoma at the moment as we continue to learn more about the Kansas part.

It's Page 28 of our Investor deck.

Okay.

I missed that.

I'll take a look at that.

Then, any anticipated charges or impacts related to firm midstream transportation and processing agreements that are in place given the sale of your midstream interests?

We reiterated our guidance around gas differentials and that takes into account the revised structure of those contracts.

Those contracts are basically similar to what we did internally.

It's basically a cost of service approach.

So we can work with Access to direct and tell them the capacity we need.

There's a cost of capital approach to setting the fees over time.

So we were doing that internally.

That's really how our contract has been codified with them to do it externally.

So based on those fees, we reiterated our guidance.

We had planned for that when we set this guidance up initially.

It's still the same.

Okay.

Thanks.

Just one last one, any insight into the search process, level of interest or any expectations on timing of when a candidate might be identified?

No.

I think I'll have to let the previous comments by the Company and the Board stand there for now.

Bob Brackett, Bernstein Research.

I had a question on asset sales.

What are you assuming for the timing of these dispositions in your production guidance?

Bob, they're layered in throughout the year, as we expect the sales to occur.

So they're all timed as we think that the sales will occur and the impacts will hit our financials.

So you're assuming half of them are done by the middle of the year?

I really don't want to get that specific this morning, Bob.

But again, we've lined them out with the processes that we're running, some of which are underway now, some of which will be underway soon.

That's just how we have it layered in.

The Miss Lime is, of course, the nearest term.

It is forecasted into outlook to be a nearest term impact.

Of the $200 million that you've either closed or have PSAs for, what are those?

Can you give us Basins or packages that those might be?

Mostly acreage.

There's not a lot of production in that.

It's just packages and non-core acreage.

Any color on which packages?

There was a little bit of DJ Basin in there and a little bit of Marcellus and a few other things.

Okay.

It's a gathering of a few different ones.

On the working capital, I noticed it ticked up a bit.

What's your long-term plan for that working capital going forward?

Working capital tick up was driven by the fact that we used a current tax asset attribute to offset some gains from our midstream sale.

That was in excess of $600 million in the quarter.

One thing I would point you to is that, our payables were down pretty materially.

Our working capital is a microcosm of our Company, as I've noted before.

As activity levels come down, our payables will come down.

As commodity prices go up, our receivables will go up.

We do, of course, have partners in a lot of our wells.

So you have offsetting effects of, as commodity prices go up, we have greater revenue payable.

As our activity levels come down, we have less receivables from partners on operated CapEx.

But overall, it's really actually trending in the right direction when you consider the movements for taxes, et cetera.

The Utica 5 to 10 Bcf equivalent, what's the well cost and lateral length stages on that sort of well?

Well costs have come down significantly this last year.

We're down to low to mid $7 million per well.

The lateral links are, I want to say over 5,000.

I don't have that average with me, Bob, but they are long laterals.

Matt Portillo, Tudor, Pickering, Holt.

Just a few quick questions for me.

I was curious if you could provide us with your current rig count?

Specifically, how we should think about your rig averages in the PRB, Haynesville and Barnett for 2013?

We detail our current rig count on Page 8 of our slide deck.

So you can see that we have about 82 operated rigs.

That's adjusted for Permian.

So from there, you asked about which Basins again?

Just the PRB, Barnett and Haynesville.

I'm looking on Slide 15, you guys have that at as about 16% of your drilling and completion CapEx.

I think the PRB was accelerating as of Q3.

So I'm curious where the rig count is there.

Then I'm just curious on your Haynesville and Barnett rig count, I know you guys were at two rigs.

Is that going to pick up in the back half of this year?

No.

We've got both the Barnett and the Haynesville flat at two rigs.

The Powder River is at 10.

Great.

Then, just a couple other quick questions for me.

In terms of the Eagle Ford, could you give us an update on the uncompleted well count?

We don't have that number with us this morning.

It's a very dynamic count, as we are running a number of rigs there, bringing on a lot of infrastructure every day.

But we'll continue to have a decent number of wells in inventory in the Eagle Ford making lumpy but good progress all year.

There will be times where we bring on a piece of infrastructure that allows us to connect a bunch of wells at once.

So again, it's pretty lumpy.

But it will be a challenge throughout this year.

One of which, we think we have forecasted appropriately in our plan.

Great.

My final question, just on the spending side.

Could you give us any color on a specific number for your spending on OFS, midstream and other for 2013?

It is down a good bit from last year.

The only growth on oilfield services that we have in this year is a couple of rigs that we had ordered early last year that are being delivered.

These are really high-value rigs that are going to be used primarily in the East that are very efficient and great assets for us.

Then we have our last two frac spreads that have I think both already now delivered.

So the vast majority of our COS spending is down.

It's significantly lower than last year.

Is there any color on the magnitude of that reduction?

Is it 50%?

Is it 75%?

Is it 25%?

Just trying to get an idea of the magnitude.

More than 50%.

Michael Hall, Baird.

I just wanted to dive in a little deeper on the Eagle Ford.

Just first, on the efficiency gain and cycle time improvements you've been seeing.

Just curious how much further you think you can take that?

Then, what percentage of activities currently on pads versus directed towards leasehold capture in 2013 versus 2012?

In 2013, we are not able to do a lot of pad drilling because we're still in HBP mode.

That will be completed really in the second half of the year.

So that will change throughout the year, so we may be as little as 15% now to by the end of the year once we are complete, it will basically be at 100%.

So we do anticipate for 2014 to have pretty significant additional improvements in our efficiency.

Okay.

That's helpful.

Then, on the proposed acreage sales in the Eagle Ford, are there any leasehold expiration issues that might be considered in evaluating that deal?

No.

The core part of it can all be easily Held by Production.

Marshall Carver, Capital One Southcoast.

Yes.

On the Utica, you talked about the 5 to 10 Bfc per well.

Across what percentage of your 1 million net acres do you think you can get those recoveries?

How much has been de-risked at this point?

Marshall, we were referring to the Total JV box, which was about 450 net.

We think there is a lot of gas, but mostly dry in the remainder of it.

So there have been very few tests in it, but our geologists think there's a significant amount of gas in place.

But again, no tests there but it would be probably on the high side of that on a Bcf basis.

Okay.

That makes sense.

Thank you.

One other question.

I think I'm going to ask the same question that other people have asked, but I'm slicing it a little differently.

Maybe you give an answer.

On the production mix in the Utica, could you at least give us the production mix for the year-end target that you mentioned?

Is that a gross or a net number that you mentioned?

That is a net number, Marshall.

But it -is a function of wells that we get hooked up on, because there's such a variable on the mix.

But you can look at the wells in our press release and get an idea from those IPs, what we're seeing.

Okay.

We are attempting to drill as close to infrastructure through the year as we can.

So I'd like to think that the wells that we showed you there are going to be representative at least a good bit of the wells that we drill this year.

They won't be all like that, but they're will be a lot.

Do you have the expected number of wells to be put on production over the year?

Net?

No, don't have that with us this morning.

Joe Allman, JPMorgan.

A question on the funding gap, Nick.

If you just look at your total spending, not just the items you give guidance for, but total spending and you compare that to your expected cash flow, what's your estimate of the funding gap for 2013?

About $4 billion.

Okay.

So then -- on the low-end of what you're going to sell, you'll hit your CapEx.

On the high-end, you would hit your CapEx plus you would pay down debt?

That's correct.

Okay.

Is it still the Company's goal to get long-term debt down to $9.5 billion?

Yes.

I think we're absolutely focused on getting the Company deleveraged financially.

We are very intent on getting to investment grade metrics, getting to a much stronger balance sheet.

We picked $9.5 billion a couple years ago.

That's still a pretty good number when you look at it from an investment grade metrics standpoint.

But we're two years more now from when we set that goal.

We'll always probably look at it on a pretty fluid basis.

It could ultimately go lower than that.

Could be a bit different, but in general, significant deleveraging is absolutely the plan and won't change.

Okay.

Got you.

So the two big assets that you've got out there, that you've identified are the Mississippian, which you are close to, it sounds like and then the Eagle Ford Shale North.

Will those two get you pretty darn close to the $4 billion?

I'm going to let those deals speak for themselves as they happen.

But we have a number of things that we'll do this year, Joe.

Okay.

Is it your goal -- even though you haven't disclosed it -- to sell other significant assets of the size of, say, the Mississippian or Eagle Ford Shale North, that you just haven't had them disclosed, to enable you to cover your CapEx plus pay down a significant portion of debt?

I think it's fair to say that some of the things we plan to sell are bigger than others.

Again, a number of projects that will get us to that ultimate number.

Got you.

Is the goal to sell as much non-cash flow generating stuff?

Can you get there or do you need to really get into some cash flow generating assets to raise the money you want to raise?

It's a balance.

But of course, from a strategic perspective, you always like the idea of selling assets that are not producing cash flow today and are going to be more valuable to someone else than they are to which us, which by definition would mean that they have less cash associated with them.

Got you.

What's the status of the Eagle Ford Shale North sale?

Again, we'll be speaking to you guys about that when the time comes.

I just don't really want to discuss pending transactions today.

Okay.

Then, just last one, when I look at your 2013 production guidance -- in the note you have underneath towards the top of the guidance -- you're including about 35 Bcfe of asset sales in your current guidance.

Previously, it was at 140 Bcfe.

You kept your guidance the same.

So does that mean that the non-for sale production is actually lower than what you previously thought?

If so, why would that be?

Joe, this is Jeff.

I'll handle that one.

The prior guidance really reflected the asset sales that we're expecting to complete in the last half of 2012 and reflect the production that those assets would have in 2013, specifically, the Permian Basin sales.

Our current guidance really just reflects the incremental transaction that we have for 2013.

Okay.

I'm not sure if I fully understand.

Is there a reduction in your non-for sale assets?

There's no change, Joe.

It's just reflecting that we've already closed certain transactions that were part of the production associated with our guidance.

There's no change.

Okay.

So I guess, then, Jeff, you're referring to the Permian for the most part?

Yes.

That was in your prior guidance, the fact that the Permian was going to be gone was already in your prior guidance, right?

Schedule B?

That's correct.

Okay.

So that difference between the 140 Bcfe and 35, you're saying that's Permian?

Primarily.

All right.

Well, I think that's about all the time we have.

We've gone past the top of the hour.

We appreciate everyone attending our call today.

If you have follow-up questions please contact myself, Jeff Mobley or Gary Clark.

Have a good day.

That does conclude today's conference.

We thank you for your participation.