Chesapeake Energy Corp (CHK) 2013 Q1 法說會逐字稿

Good day, everyone.

Welcome to the Chesapeake Energy Corporation Q1 2013 earnings conference.

Today's call is being recorded.

At this time for opening remarks, I would like to turn things over to Mr. Jeff Mobley.

Please go ahead, sir.

Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2013 first quarter.

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

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

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

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

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

I would next like to introduce the members of management who are on the call with me today, Steve Dixon, our acting Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Jeff Fisher, our Executive Vice President of Production; and Gary Clark, our Vice President of Investor Relations and Research.

We will begin with prepared commentary from Steve, Nick, Jeff, and then we will move to Q&A.

Steve?

Thanks, Jeff.

Good morning, everyone.

Thanks for attending this conference call.

I am pleased to report that Chesapeake is off to a strong start in 2013.

We are beginning to see the benefits of our operational strategy shift from identifying and capturing new assets, to developing our extensive existing assets as we enter a new era of shareholder value realization.

Our operational focus on the core of the core is enabling our drilling program to increasingly target the best reservoir rock in each of our key plays.

We are capitalizing on pad drilling efficiencies where possible, and leveraging our substantial investment in roads, well pads, gathering lines and in compression and processing facilities.

As a result, we are generating more efficient production growth, stronger cash flow and better returns on capital.

We continue to make substantial progress delivering on four key initiatives, developing our existing assets, heightening our operational excellence, increasing capital efficiency, and focusing on financial discipline.

Nick Dell'Osso and Jeff Fisher will provide additional details on these important initiatives.

But first I would like to highlight several significant accomplishments.

Our adjusted net income per share of $0.30, rose 67% from the year ago first quarter.

Our total first quarter net production grew 9% year over year and 1% sequentially to 4 Bcfe per day.

Our liquids production mix increased to 24% of our total production of just 19% a year ago.

Our combined production and G&A costs decreased 26% year over year to $1.11 per Mcfe.

Our first quarter upstream CapEx was at or below budget.

We have signed or closed on $2 billion of asset sales towards our $4 billion to $7 billion target.

We have a number of other E&P and midstream divestitures in advanced stages of negotiation, which we will share with you once definitive agreements are reached in the next few weeks or months.

At quarter-end, our liquidity was more than $3.2 billion through cash and our available revolver capacity.

Our safety program recently achieved an industry standard of excellence with our E&P segments surpassing more than 1.5 million man hours without a recordable injury.

And we have implemented substantial corporate governance and executive compensation measures to further strengthen the Company by enhancing oversight and accountability.

We have received favorable court determinations dismissing multiple shareholder lawsuits, including the dismissal of class action concerning a July 2008 note offering, and the dismissal of a reported class action concerning issues that were the subject of considerable press coverage in late spring and summer 2012.

And lastly, but importantly, natural gas markets have improved materially in the last few months, and signs of long-term demand growth are beginning to materialize across multiple market segments.

We believe this does two important things for Chesapeake, it improves our profitability, and it makes gassy assets in our portfolio more valuable and more attractive to buyers in the A&D market.

In summary, we are solidly on track and gaining strength as we look ahead to the second quarter, and the back half of this year.

I would next like to discuss the progress of our leadership transition and Chesapeake's strategic plans for 2013 and beyond.

As disclosed on April 1, Chesapeake established a new three person Office of the Chairman.

That office consists of myself; Archie Dunham, our independent non-executive Chairman; and Nick Dell'Osso, our CFO.

The leadership transition process has been smooth and effective.

As acting CEO, I greatly appreciate Archie's and Nick's support, as well as the support and assistance of our senior management team and our 12,000 employees.

Our management team and the Board of Directors are excited about the Company's business strategy and objectives that we have outlined.

The path forward for Chesapeake and its shareholders will be very different from our past.

This is a very important development for our Company.

Recognize though, that this strategy transition is a natural evolution designed to capitalize on the durable competitive advantages created by Chesapeake during the unconventional resource revolution of the past decade.

We believe the results of this strategy shift have begun to be reflected in our operational results over the past three quarters, and we expect them to continue to bear fruit for many years to come.

Our asset teams are focused on operational excellence, which for us means a sharp focus on safety, regulatory compliance, environmental stewardship, process improvement, cycle time reduction and leveraging the economies of scale.

I am confident our execution of this strategy, quarter after quarter will deliver material improvements to shareholder returns.

Turning briefly to our financial strategy, we are optimizing our portfolio, and allocating approximately 85% of our drilling completion capital to liquids plays in 2013.

And we are largely deferring drilling on dry gas plays until natural gas prices recover enough to generate competitive returns with our liquids plays.

We are diligently working to reduce and eventually eliminate our funding gap, which we now estimate will be approximately $3.5 billion in 2013.

Achieving the low end of our asset sales target of $4 billion will enable us to fully fund our 2013 investments, and maintain long-term debt at or below year-end 2012 levels.

Asset sales above $4 billion will enable us to achieve some or possibly all of our long-term debt reduction objectives.

We are committed to maintaining financial discipline, while reducing financial risk and complexity.

In conclusion, I would like to remind you that we own extraordinary assets in the top resource plays in America.

We own integrated oilfield service assets that help us sustain the most active drilling program in the nation, and help drive safety and efficiencies throughout our operations, while also insulating against future oil-field service cost inflation.

And lastly and most importantly, we have an exceptional talented and dedicated workforce that has collectively drilled more horizontal wells than any Company in the industry.

In my 22 years with Chesapeake, I have never been more excited and energized about our future.

The era of shareholder value realization at Chesapeake is now underway.

I look forward to leading this new era.

Thank you again for joining us on this call.

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

Good morning, and thanks, Steve.

Steve mentioned our strong first quarter results demonstrated the successful execution of our ongoing strategic initiatives.

Adjusted earnings per share in the first quarter were $0.30, which was up from $0.26 in the fourth quarter and $0.18 per share in the 2012 first quarter.

Adjusted EBITDA also saw an uptick in the quarter to $1.13 billion, up from $1.09 billion in the fourth quarter, and $838 million in the 2012 first quarter.

I am pleased to report that our first quarter oil production of 103,100 barrels per day was once again ahead of plan, and was up 6% sequentially and 56% year over year.

This growth was primarily driven by strong contributions from the Eagle Ford and the Greater Anadarko Basin plays, which Jeff Fisher will discuss in more detail.

NGL production came in at approximately 54,300 barrels per day, up 8% sequentially, and 14% year over year.

As a result of better than expected performance in our Eagle Ford and Greater Anadarko Basin plays, we are increasing our overall 2013 oil production guidance by 1 million barrels to a new range of 37 million to 39 million barrels.

Conversely, as we noted on our last conference call, our line of site is lower for NGL production this year, and we are reducing our 2013 NGL production guidance by 1 million barrels to between 23 million and 25 million barrels.

This is primarily due to natural gas processing infrastructure delays in the Utica and Niobrara, as well as liquid rigs allocation changes to more oily plays in the Anadarko Basin.

We are also raising our 2013 natural gas production guidance to a range of 1.06 Tcf to 1.09 Tcf, which is an increase of 2% versus the prior range.

This is primarily due to stronger than expected natural gas production from our Marcellus play.

These guidance changes are detailed on page 16 of our press release under Schedule A.

Turning now to capital expenditures.

We operated an average of 83 rigs in the quarter, and invested approximately $1.5 billion in drilling and completions, which is a run rate consistent with the $6 billion midpoint of our 2013 guidance.

Net leasehold expenditures on unproved properties were $45 million, putting us on track to be in line or below $400 million budget for the year.

Other CapEx was approximately $345 million, which included $62 million for CapEx spent on the two remaining midstream systems that we are divesting.

We anticipate recovering this CapEx as these assets are sold.

Other CapEx also included $69 million for final delivery of two pressure pumping spreads, and three rigs that were ordered in early 2012.

There are three additional rigs to be received during this quarter, after which we have no additional plans for material growth of our oilfield services assets.

Consequently, other CapEx for 2013 is heavily front-end loaded and will decline substantially in the second, third and fourth quarters.

I will further note that as a result of an expected decline in leasehold, midstream oilfield services and other CapEx versus last year and further decreases going forward, 80% of our total CapEx will be spent on drilling and completion activities in 2013, versus an average of just 50% over the last three years.

We believe this capital allocation trend will be even more pronounced in 2014, when we plan to dedicate nearly 90% of our total CapEx to drilling and completion activities.

We are now clearly seeing the benefits of our past investments in leasehold, oilfield services and other assets which no longer require significant capital investment.

Production costs during the quarter averaged $0.86 per Mcfe, which is down 18% from $1.05 per Mcfe in the year ago quarter.

We continue to make good progress on lowering G&A expenses as well, which averaged $0.25 per Mcfe during the first quarter, down 29% from $0.35 per Mcfe in the year ago quarter.

Per unit production costs and G&A were both up slightly versus fourth quarter of 2012, which as we noted on our last call contained several one-time items.

I am pleased to announce a reduction in our 2013 per unit production cost and G&A guidance ranges for the second quarter in a row.

We now project that production costs will range from $0.85 to $0.90 per Mcfe for the year, down $0.05 per Mcfe versus prior guidance.

We project that G&A expenses will range from $0.30 to $0.035 per Mcfe, down $0.04 per Mcfe per prior guidance.

These decreases in expense guidance amount to an approximate $100 million expected improvement to our 2013 operating cash flow.

I would now like to address progress with regard to asset sales.

We have signed or closed $2 billion of asset sales year to date, segmented as follows.

In the first quarter we received $366 million cash proceeds on sales, including $45 million of hold-backs received from last year's Permian sale.

In Q2 thus far, we have received cash proceeds of $262 million on sales, including $40 million of hold-backs from last year's Permian sale.

And lastly, we have signed purchase and sale agreements on $1.4 billion of asset sales that are not yet closed.

The largest portion of this is our Mississippi Lime transaction with Sinopec, which we anticipate closing before the end of the second quarter, and also includes sale of midstream assets in the Mississippi Lime play to SemGroup which was announced by the buyer this morning.

In addition, we anticipate signing agreements to sell our Northern Eagle Ford and remaining midstream assets during the second quarter.

Turning to the balance sheet.

On March 31, we had a total debt balance of $13.4 billion, including $832 drawn on our corporate revolver.

On April 1, we completed $2.3 billion senior note offering at the lowest interest rate in the Company history.

As a reminder, the use of proceeds for this offering is solely for refinancing, and will not be used for general corporate purposes.

Accordingly on April 15, we used a portion of the proceeds to complete tender offers for approximately $594 million of debt, which represents portions of our outstanding 2013 and 2018 nets.

As an aside, I would like to point out that our credit default swaps were quoted yesterday at 310 basis points, which we believe is the lowest level since August of 2011.

We also paid off the balance of our corporate revolver subsequent to March 31.

Next I would like to address our hedge position for 2013 and 2014.

In 2013, we have put in place downside protection on approximately 78% of our projected natural gas production at an average price of $3.72 per Mcf.

On the oil side, we have downside protection on roughly 88% of our expected volumes at an average price of $95.43 per barrel.

For 2014, we used recent strength in natural gas prices to hedge approximately 13% of our projected gas production at $4.33 per Mcf.

We have also put in place 2014 oil hedges that protect our downside on approximately 40% of our projected production at an average price of $93.63 per barrel which is well above the current NYMEX strip.

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

Thanks, Nick.

We are continuing to see tangible efficiency gains across our key plays from increased pad drilling, reduced cycle times, and targeting the best reservoirs in the core of the core of our acreage.

Before I get to the discussion of our specific play performance, let me describe a number of operational initiatives that highlight our commitment to project execution, capital efficiency and safety.

To augment our more focused development programs, we are leveraging automation systems and enhanced work processes to improve operational efficiencies and drive down costs.

As an example, we have developed a high tech drilling operation center in Oklahoma City, where technicians monitor and manage drilling performance and the steering of horizontal wells, real-time 24/7.

In addition to better managing our staff resources, we are realizing better drilling performance, improved logistics and lower costs.

This center is being expanded to incorporate real-time monitoring of pressure pumping and production operations, where we expect to see similar benefits.

Our teams have also been applying lean manufacturing concepts to improve project execution in the field.

As an example, these practices have led to a revamp of our rig move processes, in which we have been able to reduce cycle times by up to 45%.

We are expanding these practices to enhance many other aspects of our operations, and we look forward to continuing improvement.

And importantly, these programs also improve safety performance.

And as Steve noted, we are very pleased with our progress on that front.

In addition to improving capital efficiency going forward, these initiatives are also contributing to the lower production cost performance that Nick discussed.

I would now like to discuss our operations in four key plays, the Eagle Ford, the Utica, the Greater Anadarko Basin and the Marcellus.

As Nick noted in his remarks, we are increasing our overall 2013 oil production guidance by 1 million barrels.

This is largely attributable to outstanding results in the Eagle Ford where we are drilling longer laterals, achieving better than expected well performance, and benefiting from increased gathering system and processing capacity.

During the first quarter, we drilled 91 new wells, while bringing online 111 wells at average peak rates of 950 Boe per day.

As infrastructure continues to develop, we remain on plan to reduce excess well inventory by drilling a total of 300 wells, while bringing online approximately 400 wells to sales by year end.

First quarter liquids production in the Eagle Ford averaged 61,600 barrels per day.

This was an increase of 44,100 barrels per day or 251% year over year, and an increase of 10,800 barrels per day or 21% sequentially from the fourth quarter.

To remind everybody, we are targeting a year-end 2013 exit rate of approximately 71,000 barrels of liquids per day, and a total production exit rate of 92,000 Boe per day net from the Eagle Ford.

On average, Eagle Ford's spud-to-spud cycle time during the first quarter was 18 days, down 28% year over year.

We executed 30% more frac stages versus the prior quarter, and we continue to make progress in our completion practices.

Longer-term, we are targeting an average spud-to-spud cycle time of approximately 13 days in full pad development mode, and an average completed well cost of $6.5 million for a 6,300-foot lateral.

In the second half of 2013, we anticipate that 50% of our Eagle Ford wells will be drilled on multi-well pads, versus only 15% during the first half of 2013.

Looking ahead to 2014, we believe more than 75% of our wells in this play will be drilled on multi-well pads.

Based on an assessment of more than 600 wells drilled and brought online to date in our core Eagle Ford, we conservatively estimate that our average type well across the core will yield an EUR of 570,000 Boe.

Assuming an average well cost of $6.5 million, we expect to generate pretax rates of return ranging from 30% to 80%.

Pro forma for the sale of our Northern Eagle Ford assets, we conservatively estimate a drilling inventory of more than 3,500 high quality development locations, representing an inventory of more than 10 years based on current activity levels.

In the Utica play, we have drilled 249 wells, of which 66 are completed and flowing to sales as of first quarter.

Production is relatively flat versus our operations update call one month ago, as the new processing of the structure that we spoke of has not yet come online.

We now expect the next step change in our Utica production will occur closer to mid year, but are maintaining our year end exit rate target of 330 million cubic feet equivalent per day net.

In that April 1 update call, we discussed the impressive results we have seen in our Scott Unit in Carrol County.

Today I would like to highlight our co-unit, also in Carrol County, which is delivering strong production rates, and has yielded some excellent pad drilling capital efficiency gains.

We drilled 6 wells from a common pad with an average 24 hour restricted flow rate of 1,170 Boe per day, consisting of 75 barrels of oil, 280 barrels of NGL -- at reduced I think recovery, and 4.9 million cubic feet of natural gas per day with flowing tubing pressures exceeding 2,400 PSI.

The cost of the first well on this pad including related infrastructure was nearly $8.5 million.

The next 5 wells on the pad were drilled and completed at an average cost of only $5.9 million for a 30% decrease.

Turning now to the Greater Anadarko Basin where we are principally targeting five plays, the Mississippi Lime, Cleveland, Tonkawa, Granite Wash, and Hogshooter which has been expanded recently to include some additional Missourian age targets.

At March 31, we had 28 rigs running in this basin, and had combined first quarter net production of 114,000 Boe per day, which is up 9,500 Boe per day from the fourth quarter or 9% sequentially.

This was in spite of some fairly substantial winter weather-related down time during quarter that impacted our production by nearly 5,000 Boe per day.

Now let me give you a few specific play highlights from the Greater Anadarko.

In the Mississippi Lime, we have substantially completed our water disposal infrastructure projects across the majority of our core development areas.

We believe this will result in improved efficiencies for turning wells to sales, and will reduce construction and water disposal costs going forward.

Our measured pace and science-based approach to this play is also generating improved well performance and returns on capital.

We turned 32 Miss Lime wells to sales in the first quarter at average peak rates of 540 Boe per day, with 5 of those wells in excess of 1,000 Boe per day.

We are actively shooting 3D across our core development areas to assist with the geomodeling and mapping techniques we are employing to further refine prospect identification.

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

Our Hogshooter play also continues to generate outstanding results.

We turned 14 wells to sales in the first quarter at average peak rates of 2,380 Boe per day.

Our best well, the Roark Trust 1H, tested at a peak flow rate of more than 4,570 Boe per day, outstanding results.

Our teams have identified more than 50 remaining Hogshooter locations, and have been successful in further extending the play to the east of our original development area.

Indeed, we believe the Greater Anadarko holds a treasure chest of opportunity, and we have the teams and the acreage to maximize the value for our shareholders.

And finally, I would like to note that in our Marcellus region, where we are the industry's largest natural gas producer we recently achieved a gross operated natural gas production milestone of more than 2 Bcf equivalent per day.

As gas prices have recovered nicely from year ago levels, we are benefiting greatly from strong growth and returns in both the northern dry and the southern wet gas portions of the play.

Natural gas production in the first quarter was up an impressive 58% year over year, and 9% sequentially versus the fourth quarter.

You will note from our press release that we are bringing online outstanding wells in our Marcellus position, but our recent results in the southern portion of our Marcellus north dry gas play really stand out.

Extending from our position in Susquehanna County, westward into northern Wyoming and southern Bradford counties lies the most prolific portion of our acreage position that is yielding amazing performance.

We have brought online a number of recent wells in this area that are flowing at restricted rates in excess of 12 million cubic feet per day.

Based on results of over 150 producing wells in this area, we are currently estimating per well recoveries of over 10 Bcf.

We own approximately 100,000 net acres, and have over 1,000 remaining development locations to drill in this core of the core.

And let me close by saying that I am pleased with our liquids production growth, capital efficiency gains, safety performance, and per unit cost performance to date, and believe that there is much more to come.

I very much look forward to the second half of 2013, when we will see a fairly substantial acceleration of pad drilling in a number of our key plays, and we expect to realize production growth in the Utica as gas processing capacity is completed.

I will now turn the call over to Steve.

Thank you, Nick and Jeff.

We will now turn it over to the operator for questions.

Thank you.

(Operator Instructions)

We will go first to Dave Kistler.

Good morning.

Morning, Dave.

Real quickly, kind of all things being equal, if we think about the timing of the divestitures that you have planned and that have occurred year-to-date, how does that impact the uptick we are seeing in production guidance?

Or should I be thinking about it as those actual timing of divestitures really had no impact to your forward plan, and uptick in production is specifically related to just asset performance?

Yes, Dave, it is predominantly asset performance.

It would be very, very little from sliding on the asset sales.

Okay.

Appreciate that.

And then, previously you talked about that the divestitures would be broken into kind of two different components, a few large ones, and then a number of smaller divestitures.

As you think about smaller divestitures, are those going to be equally taxing on the staff to get those completed, and obviously that increases the number of divestitures.

Does that create any concern with respect to meeting the guidance of $4 billion to $7 billion?

Yes, no concerns, whatsoever.

We have identified those packages, and they have actually been in process for a number of months now, Dave, so while that hard work is already been done by our staff.

So things are proceeding as planned, and don't see any changes.

Okay, appreciate that.

And then one last one, just kind of relative to the Marcellus sale that was announced earlier.

It looks like that was non-op interest.

Was that previously baked into capital spending rates?

And was there any concern that, that might move aggressively forward in '13, and why it was targeted as something that you wanted to unload in the Marcellus, or is it just purely it is not core of the core?

Yes, Dave, it is mostly we had outlined where we want to focus our activities and our capital spend, and it was outside of that.

And so, it was a targeted divestiture for us because of that.

Okay.

Appreciate that color.

Thank you.

We will hear next from Arun Jayaram with Credit Suisse.

Good morning.

I just wanted to clarify on the guidance.

The updated guidance assumes that you would reach the bottom end of your sales target at $4 billion.

Nick, is that consistent with what you had outlined previously in terms of guidance based on the low end of the $4 billion to $7 billion target, sales target?

Yes, that is right, Arun.

Our revised production guidance assumes the same set of transactions as previous.

And so, for the low end of the range within that production guidance, and still have confidence that we will be well into the range.

So should our production guidance need to be adjusted in the future, we will do so.

When we do so, we will also update you on how we would plan to apply those proceeds to debt reduction.

Okay.

Thanks for clarifying that.

Just a general question.

You had some impressive growth looking at the Eagle Ford, Anadarko and Marcellus, all in a period where your rig counts have come in a lot.

I am just wondering if you could maybe comment on what you are doing on the completion side?

You have talked about completing more wells than you are drilling.

I was just wondering, how long does this -- call it a tail wind last for -- where you have more completion activity relative to wells you are drilling?

Go ahead, Jeff, I will let you answer that.

Sure.

So we are catching up on inventory in several of our plays, specifically in Eagle Ford.

And as I commented, I think in that particular play, we should be kind of caught up with what we would call an abnormal inventory or backlog by the end of the year.

A lot of it is still related to midstream infrastructure and just timing of bringing wells on.

Most of that we are working through with our midstream partners, and have line of sight to deliver those mostly by this year, and maybe a little bit into the first quarter of next year.

But the fact does remain, that even with our reduced rig count, we are completing more wells than we are drilling company-wide right now.

And that is really by design to help us get caught up, and improve our capital efficiency.

And just a very quick follow up on the Utica.

What midstream project should we be watching as you try to get to that 330 Mcfe target by year end?

Which pipeline project should we be watching?

Actually, more processing.

Natrium will be the first one on, which should be in May, so this month.

Then Momentum is a big one mid-year.

So processing is really the hold up, and those two are the largest projects.

In our slide presentation, on page 17 we talk about those various projects.

Thank you very much.

And Bob Morris with Citigroup has our next question.

Thank you.

Steve, your comments with regard to the high end and low end of range, and paying down $4 billion to $7 billion of debt seemed to imply that paying down debt to $9.5 billion by year end is not as hard of a target as it was before, that may slip out further into 2014.

Is that correct?

And what is driving that?

Is that just a slower pace of getting the asset sales done, or just what underscores that push out I guess of the $9.5 billion target?

Well, we are focused on getting asset sales done, at a minimum of $4 billion.

If we get to $7 billion, we can actually achieve that.

Nick -- do you have anything else to add to that?

Yes, Bob, I would just say from a goal perspective, the goal hasn't changed, which is an absolute reduction in our debt.

We are noticeably as you have said being a little bit less specific about the precise timing of that because we want to preserve the option to get the right deals done, on the right time, for the right assets.

There is no change in our strategy.

We are refining our assets that we hold in our portfolio to be as efficient as possible.

That leads to an opportunity to sell assets.

And we will use those proceeds from asset sales to reduce debt, and we will absolutely get to that lower debt number.

But we want to be a little bit cautious about exactly when we say it, because we want to make sure and hit the expectations.

Sure.

Now in that regard, Steve, you made a comment that the stronger gas price environment has made some of your gas assets more attractive to buyers.

So what gas assets might move up in the queue to be sold, and in that regard, what are you looking at or is there something there that may move up in the queue, given the strong gas price environment per your comment?

Bob, we are not talking about any specific assets.

But clearly, with the movement in the market, it has been a buying signal for buyers out there, and we are getting a lot of interest from a large set of buyers.

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

Yes.

At the right price, we certainly would.

Okay.

Great.

Thank you.

We will move onto Brian Singer with Goldman Sachs.

Thank you.

Good morning.

You talked about the 100,000 acres that are core of core in the Marcellus.

And that in the slide that you go through, you also highlight the larger circle that encompasses the core.

Can you talk about your acreage position, and what you would call the core in northeast Pennsylvania, and how you are thinking about developing those acres versus selling those acres?

We, Brian, this is Steve.

We don't plan on selling any of that core acreage.

As we have our position HBP'd now, we can allocate our capital to our highest returns.

And certainly having 1,000 locations left in that core of the core area, that is where most of our drilling activity is going to be in the near future.

Thanks.

And I guess, of the 1.5 million acres that you have in the northern dry gas Marcellus I guess, what would be in core, plus core of core -- 100,000 in core of core?

What is the position that you would classify in the core?

I don't have that with me here, Brian, but it would be multiples of that core of the core.

.

Thanks.

And then going to the Eagle Ford, you talked about your 570 MBOE type curve.

And I think on one of your slides, you mentioned that the average so far has been a little bit less than that.

Has it been the recent results and recent completions that has kind of been starting to average that up?

And can you talk about of the inventory you highlighted, what percent of your Eagle Ford acreage position that applies to, in terms of core of core?

Brian, I am throwing that to Jeff.

Yes, so it is based on improving results.

I mean, our results are improving in this play continuously.

And that is why we say, we think we are being conservative in our estimates because we are still on the uptick.

So it is swayed by recent improvements, but it does include most all of the wells that we have drilled to date.

We took out a few wells that were science wells, and where we were doing experimentation.

So it is a very solid reserve number, and it applies to essentially everything that we will end up retaining in the Eagle Ford.

As you know we have looked at selling kind of a non-core position in our northern Eagle Ford asset there, and the type curves and the economics that we are presenting really apply to everything else that we will have remaining, which is quite substantial.

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

I think it is about 300,000.

No, it is 250,000.

Okay.

250,000 net acres.

Great.

Thank you very much.

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

Thanks.

Good morning, everybody.

I have got a couple questions also.

Can I start off with the disposals also there, the $2 billion you have got line of sight now.

But I am guessing the commentary sounds like you've got fairly good line of sight in what comes next.

So I realize we are all focused on the $4 billion to $7 billion range.

But just in terms of how to qualify how you see progress towards meeting bottom end of that range.

Can you just give us some feel as to what your line of sight looks like for the bottom of this year?

And then I have got a couple of operating questions, please.

Doug, we have a number of additional asset sales that are in various stages, but many where we have basically terms agreed to, and we are just trading the paperwork and exhibits.

So it has given us great confidence to be ahead of our projections on asset sales for the year.

When you say ahead, you mean, what is the target for the year?

The range is pretty wide.

So when you say you are ahead, do you mean you are going to beat the bottom end of the range, or can you be a little bit more specific?

We will meet the bottom end of the range, certainly.

Based on what you have got line of sight on right now?

Yes, sir.

Okay.

Great.

Thank you.

My operating questions are really -- if I could try two maybe -- and then I will leave it there.

One on the Utica, you are still sticking with this 330 million target for the end of the year, but can you help us a little bit with what the nexus is going to look like as we progress through the year?

Because, obviously it is -- you haven't really given us any detail as to how the focus is going to be in terms of targeting of more of the liquids rich areas of the play?

We have given examples of our well results, and that mix is where most of our drilling rigs are running in our activity.

And so I think it would be similar to those results.

Okay.

So about 40% liquid roughly it looks like?

Jeff, do you know that number?

Yes, roughly.

Okay.

And finally, on the Anadarko Basin, the 28 rigs that you are running, can you just give us break down as to where they are being focused?

Because obviously, the implication is there will be more rigs in the Hogshooter versus other areas is -- could be significant.

So I will leave it at that.

Thank you.

Thanks, Doug.

Roughly, we have three in the Tonkawa, six in the Cleveland, four in the Colony Wash, three in the Texas Panhandle Wash, and two to four running in the Hogshooter play, and Mississippian at eight.

It adds up to 28, but this is approximately where everyone is running.

All right, great.

Thanks, fellows.

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

Good morning.

Just a few quick questions for me.

I am just trying to understand a little bit better how you think about your rig count as you exit this year?

So just wanted to see if there are any other moving parts.

I know you mentioned the deceleration in the Eagle Ford.

But curious if there is any other areas we should think about acceleration of rigs, or are most of the other plays going to be relatively flat?

And then I have a few quick follow ups.

Matt, we are really not changing our planned net wells, drilled and turned in line.

The reduction in rig count in the Eagle Ford throughout this year has just been because of our cycle times and improved efficiencies.

So our capital spend and activity level are still the same.

We have no big plans to change throughout this year.

Our focus is financial discipline and meeting our budget targets.

Great.

And then just within the Eagle Ford, trying to understand a little bit better.

As you bring down the rig count there, I think you mentioned 18 days of cycle time, and we kind of roughly calculate 250 to 275 wells drilled under that cycle time.

Is that roughly how we should think about the run rate well count for you going forward?

Or if there is any color you can provide, just on kind of '14 run rate from a well count perspective?

Well for '13, Matt, it is right at 300 wells spud and 400 wells turned in line, as we burn off some of that inventory.

We have not provided guidance yet for '14, but our cycle times continue to improve.

And we will be doing more and more pad drilling in the second half of this year, and certainly much more in '14.

That will continue to improve our cycle times and capital efficiency.

Thank you.

And then just my last question.

As we think about your Marcellus position, obviously in the core of the core.

At $4.50 gas I would assume your returns on 10 Bcf wells are extremely strong.

I wanted to get a little bit more color on how you think about your gas returns at $4.50 in the Marcellus versus some of your more marginal acreage on the liquids plays?

And if you would consider any acceleration as the gas price improves, or at what price would you look at accelerating your gas rig count?

Matt, a big part of that Northern Marcellus is constraints on gathering and take away out of the basin.

And so that will improve towards the end of this year, and we do hope then to be able to add rigs back and grow our Marcellus production.

Thank you very much.

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

Morning, Steve, either for you or Jeff.

Just wanted to focus on the Utica here for a second.

I know you mention that guess production is expected to be about the same, despite having a few more wells behind pipe that are waiting to be tied in.

Are you assuming that, that '14 rig count will still be able to stay rather constant, or you will have to ramp that a little bit through the remainder of the year to still hit that number?

We actually might be able to reduce rigs there, because our cycle times are improving so much.

So just like the Eagle Ford, not reduction in number of net wells to turn on, but just our efficiencies are improving.

But with the pace that we are on, we will be able to meet those objectives, and significantly grow production here in the last half of this year.

And in your slides, you mention on that co-unit how you are able to cut costs.

What on these pads, what is kind of an average these days as far as what you are doing as far as lateral length and kind of frac stages?

Is that staying pretty constant or you are you reducing that as you are able to bring costs down?

Yes, those cost reductions really aren't achieved by downsizing the well, so to speak.

So we are typically going 6,000 feet in the Utica, anywhere from 13 to 18 stages.

We are doing some experimentation on our completions and delineating the field.

But the main cost savings really come from utilization of the pad, of the infrastructure that we have to spend money on up front.

And then, just the drilling efficiencies that we see by learning from subsequent wells.

So it is very, very exciting, very repeatable, and we are not degrading performance in any way with our designs.

In fact, these are just very, very strong wells.

So our well performance continues to improve in the field, and we will do some more experimenting on completions and optimization.

There is a lot of talk about that.

We have got some great folks that do that work and are well in tune with the latest technologies.

And I know you mentioned about trying to sell still some of the non-core in that play.

Just optimally what ideal you would end up maybe with at the end of the year, or is it maybe not really -- specifically broken that out yet.

Yes, no specifics on that yet, Neal.

Okay.

Then just lastly in order to hit some of these goals, a lot of the guys have talked about a lot of the asset sales, et cetera.

Maybe for Nick or one of the guys just your thoughts, and would you still consider putting some of these more mature assets in like a royalty trust structure?

Or VPPs that you have done in the past, or is it just pure asset sales we are looking at?

Yes, at this point, we are really focused on straight asset sales.

We see pretty good value there today, and it certainly allows us to achieve less financial complexity.

Okay.

Thank you all.

Great quarter.

Thank you.

And we will go next to David Tameron with Wells Fargo.

Hi.

Good morning.

A couple questions.

Ethane rejection, can you talk about what assumptions you have built into your four year guidance?

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

All right.

Eagle Ford.

I think Jeff mentioned well cost, your target is $6.5 million at that 570,000 EUR.

What are your current well costs in the Eagle Ford?

Current well costs are in the $7 million range.

I think we discussed that at the operational update a month ago.

Again, steady improvement, down from $9 million early in the play, I think $8 million a year ago.

And we have got very high confidence in our $6.5 million projection.

Keep in mind, we are drilling a little bit longer laterals than some in the play at 6,300 feet.

We may even push that a little bit more.

But that is where we're at.

Okay.

Fair enough.

And condensate, what is your condensate and oil cut in the basin?

You are talking about Eagle Ford?

Eagle Ford, I am sorry, yes.

Yes, I think we are at roughly 60% oil, 20% NGL, and 20% gas.

We will check those numbers.

But most of our liquids production there, at least on the oil side is 45 degree gravity oil.

We have got some condensate down in the wet gas window, but think of our mix as 45 degree spot on premium oil.

Okay.

Good.

And then last question.

Anadarko Basin gets about a 30 year CapEx, but can you give us more clarity?

I was going to say kind of get the short shift, but can you give us more clarity exactly, outside Mississippi line, which is obviously well-documented, can you talk about Granite Wash, Cleveland, Tonkawa, Hogshooter -- can you rank those for us, or just tell us where the focuses are -- I know you said you had three or four rigs in different plays.

But can you just give us some color on overall what you are doing out there?

Sure, Dave.

We are in western Oklahoma for the most part.

Some of that overlaps into the Texas Panhandle.

So it is in Chesapeake's kind of core Anadarko Basin position.

And our asset teams are just targeting the highest potential wells and focused on drilling our very best well next.

And there are a variety of pays in Anadarko Basin, and we are allocating depending on what those prospects look like.

You got anything to add on that Jeff.

Yes.

I would just add that we group the Anadarko Basin in our conversation today, just because we look at it as a very broad prolific basin with multi pays, and it is stacked pays, it is stratigraphic trends throughout the basin.

And we just have a huge core acreage position there that we are exploiting.

I think as far as some advancements in our Hogshooter, Cleveland, and Tonkawa plays, our teams are doing a great job of breaking down the science on these.

Most of our plays in the Anadarko are not statistical resource type plays.

They are geoscience-driven plays that require a different approach, and we've just got the critical mass and economies of scale to commit to that.

Our teams are continuing to improve our well results.

So we are very excited.

And we will talk about those five plays today.

But in three to five years, it will be another three or four plays probably as this continues to develop.

Okay.

I am taking a shot at this.

Would you go Hogshooter, Cleveland, Tonkawa and then Granite Wash as far as rank order today of prospectively or am I forcing that?

I mean it depends on product prices, because they do shift some for complete oil to much higher gas, and then some have higher IP, so that helps rates of return.

We are pleased with all of them, and we allocate our resources into our best prospects.

Okay.

Fair enough.

All right.

Yes, I hear you.

Thanks for all the questions, all the Q&A.

Appreciate it.

Thank you.

And we will hear now from Jeffrey Robertson with Barclays.

Thanks.

Yes, Steve, to follow up on the Anadarko Basin, can you rank order in terms of returns at current commodity prices and the results you are getting, returns in various plays that you outlined?

Jeff, certainly don't have that here with me.

And those we listed, the top five plays, there is actually -- I think we drilled horizontal laterals in 12 different zones stacked in the Anadarko Basin.

So it is just a great legacy asset for Chesapeake that we have, we already own all the land there, that is HBP'd.

And so as Jeff mentioned these are not resource plays, these are prospect specific.

And so we are just drilling our best prospects next.

Can you talk about what well costs are up there?

Again, a variety, Jeff.

They range from fairly deep Granite Wash wells to very, very cheap shallow Mississippian wells.

So it is a wide range from $8 million-plus to under $4 million so.

Okay.

Then next question on, just as you all look at the types of assets that you hope to sell over the course of 2013, will that have any impact on amount of interest that Chesapeake capitalizes?

No, I don't really anticipate a significant change in our capitalized interest rate for this year.

We will keep looking at that as we go forward there, Jeff.

Okay.

Thank you.

And Charles Meade with Johnson Rice has our next question.

Good morning, gentlemen.

Thanks for taking the question here at the end of the hour.

First going back to the Eagle Ford.

I think you mentioned a little bit earlier that you are drilling longer laterals there, 6,300 feet on average.

But for that for that good well that you put in your press release, the Sultenfuss, can you talk about the configuration of that well, the lateral length, and how many stages?

How are you evolving overall in the play as far as lateral length and stages?

Charles, I don't have any specifics on that well, and how it was completed or lateral length.

As Jeff mentioned that is an average.

And so depending on how the leases lay out, some are shorter.

Some are longer than that.

We are not really trying to extend that much further.

That is pretty long lateral for an average program.

Again, it will have 7,500 foot wells, laterals in there some, but for an average program that is pretty long.

So I don't anticipate that changing dramatically.

Okay.

Thank you.

And then going back to your prepared comments, I think I believe I heard that in the Anadarko Basin there was a weather impact of 5,000 Boe a day for the first quarter.

And I was curious, two things.

One, is that gross or net?

And then, two, is that the total weather impact, or is that really the weather impact versus your baseline expectation for weather in the first quarter of the year?

Go ahead, Jeff.

The 5,000 Boe per day is net.

And it really resulted from a significant number of snowstorms, believe it or not, that we had in northwest Oklahoma.

And I wasn't sure I followed the rest of your question.

It was really, presumably you have some amount of down time baked in every first quarter for snowstorms.

But I was just curious, was that the total impact or was that really the impact beyond what you normally expect?

Sure.

Now I understand.

That would be incremental to what we would consider normal down time.

Great.

Thank you.

And Biju Perincheril with Jefferies & Company has our next question.

Hi, good morning.

Steve, looking at the guidance, I think you have mentioned in there, about 42 Bcfe that are removing for asset sales.

It sounds like there is some incremental above and beyond the Miss Lime and Eagle Ford.

Can you talk about, is that various pieces, or are there some major components there?

Well, there are a variety of packages, lots of little packages out.

And some have small production like the Marcellus one that was announced with just 2 million a day.

Some have slightly more.

So it is just a variety from the packages that we identified the production associated with those.

Okay.

So as far as major producing assets, it is fair to say it is Miss Lime and Eagle Ford?

Certainly those would be bigger ones.

Okay.

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

Yes, the first well would have included the location cost, the roads in, moving the rig in, those kind of big dollar amounts.

And so all those are saved on the subsequent wells.

But definitely there would be a piece of that, with what would be the knowledge base for both how fast we drill, but also how we target the well, so we can drill those subsequent wells faster than the original well normally.

And typically, how much are those location costs running?

Pretty expensive in the east.

I don't have an average number.

But $500,000 pretty -- can easily be that high.

Got it.

Okay, thank you.

Very good.

We have reached the top of the hour.

I would like to thank you for joining our call today and your interest in Chesapeake.

If you have additional questions, please follow up with Jeff or Gary later today.

Thank you all.

And that will conclude today's conference.

Thank you all for joining us.