Chesapeake Energy Corp (CHK) 2015 Q2 法說會逐字稿

Good day and welcome to the Chesapeake Energy Corporation Q2 2015 conference call.

Today's conference is being recorded.

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

Please go ahead.

Good morning, everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2015 second quarter.

Hopefully you've had a chance to review our press release and the updated investor presentation that we posted to our website this morning.

During this morning's call we will be making forward-looking comments, which consist of statements that cannot be confirmed by reference to existing information, including 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 will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and in other SEC documents.

Please recognize that except as required by applicable law we undertake no duty to update any forward-looking statements, and you should not place any undue reliance on such statements.

With me on the call today are Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Chris Doyle, our Executive Vice President of the Northern Division; Jason Pigott, our Executive Vice President of the Southern Division; and Frank Patterson, our Executive Vice President of Exploration.

Doug will begin the call and then turn the call over to Chris and Jason for a review of our operations, then Nick will wrap up the prepared remarks before we turn the teleconference over for Q&A.

We also have some new slides that we will be referencing, and these can be found in the Investors section on our website at www.chk.com.

So with that, thank you; and now I will turn the conference over to Doug.

Thank you, Brad; and good morning.

I trust you have had the opportunity to review our press release, and for your reference we have the slides that Brad noted that will accompany this teleconference.

To begin, we successfully executed our program as planned in the second quarter and continue to make significant improvements as a Company.

During this challenging period of low commodity prices, Chesapeake is leading with our strengths, which include low-cost operations, capital efficiency, a diverse portfolio of high-quality assets, and talented employees.

These strengths provide the Company flexibility and huge optionality today and in the future.

I am confident in our ability to be competitive, and we are focused on driving value for our shareholders, regardless of commodity prices.

Moving to our quarterly performance as shown on slide 3, our daily production averaged 703,000 barrels of oil equivalent per day for the second quarter, which is a 13% increase year-over-year adjusted for asset sales.

As a result of our strong production, we are increasing our 2015 production guidance range to 667,000 to 770,000 barrels of oil equivalent per day, or by 4% compared to our previous guidance.

The strong production performance in the first six months of the year positions the Company to enter 2016 at a higher rate than previously forecasted.

We currently expect our 2015 exit rate to be around 660,000 barrels of oil equivalent per day, which is outstanding when you consider our ramp-down in activity across our portfolio and our present voluntary curtailment of approximately 50,000 barrels of oil equivalent per day on a net basis.

We have a track record of improving capital efficiency, and our cost structure has improved as we demonstrate our low-cost leadership.

Second-quarter LOE and G&A costs were $5.40 per barrel of oil equivalent, down approximately 8% year-over-year.

In addition, our 2015 second-quarter drilling and completion capital expenditures came in as planned, and we expect to stay within our full-year CapEx guidance of $3.5 billion to $4 billion.

We understand that our debt structure and gathering commitments add to the challenges of the commodity price environment, and there are several questions out there in the market, such as: can Chesapeake generate sufficient cash flow to weather this storm?

And can the portfolio and operational strengths overcome these significant obstacles?

The answer is definitively, yes.

We have tremendous flexibility and optionality given the breadth and diversity of our portfolio.

I came to Chesapeake two years ago because I considered it to be the biggest challenge, and thus the biggest opportunity, in the industry.

We've made significant improvements in our capital efficiency, cost structure, and balance sheet, and I am as determined and confident today as then that we will become a top-performing E&P company.

Our portfolio offers several strategic options to enhance our cash flow and liquidity through potential asset sales, joint venture agreements, and/or participation agreements, some of which we expect to execute in 2015.

Discussions have already begun with several parties, and we are confident in our ability to maximize the value of our resources both in the short term and for the long term.

The success we've had in improving our productivity and capital efficiency over the past two years has created the opportunity to bring additional value forward.

Under any or all of these potential agreements, Chesapeake would be able to accelerate its drilling activity and production beginning in 2016, or use any potential proceeds to enhance our capital structure.

A quick note on our gas differentials.

We are projecting these differentials, which include both basis and non-basis costs, to be relatively flat over the next 18 months.

However, we have several initiatives underway to improve these costs.

Positive discussions with Williams, our primary gas gathering provider, are continuing, and we are confident in finding mutually agreeable solutions that will benefit both companies.

We will provide additional details regarding differentials later on this call.

We look forward to reporting more details to you as they come available.

But in the meantime we are leading with our strengths, attacking our liabilities, and driving for greater shareholder value.

I'm excited to see what the leadership and talented employees of Chesapeake Energy are going to achieve in the remainder of 2015 and beyond.

I will now pass the call to Jason and Chris for an operational update, then to Nick for a review of our pricing liquidity, and then we will open the call for questions.

Thank you, Doug.

Good morning; this is Chris Doyle.

Let me start by highlighting some of the cool things going on in the Northeast.

We'll start on slide 4. Like many of our assets, the Marcellus and Utica teams just turned in the best operational quarter in their history.

In the Marcellus during the first quarter of 2015, drilling team averaged 12 days spud to rig release; that was a 35% improvement over 2014.

We entered the second quarter never having drilled a sub-10-day well.

Not only did the team do that right out of the gate, they averaged 10 days spud to rig release for the entire quarter.

The third quarter is off to a strong start as well.

They released off their first pad just recently.

It's a four-well pad averaging 9 days a well; and they just set a new record of 7.9 days spud to rig release.

Unbelievable performance.

Now, the drilling progress in the Utica region: same way.

We're drilling longer laterals in fewer days.

As we said in the past, those efficiency gains are being reinvested not only in those longer laterals but also in optimizing completions.

Improvement in our capital deployment, along with the really stable base, has allowed the Utica to grow 13% sequentially while only running four rigs.

Despite the asset's strong operational performance and the team's execution, beginning in July we began curtailing in the Utica due to weak in-basin pricing.

Currently curtailing 275 million a day gross; that's up from about 100 million a day last month.

That effectively eliminates our in-basin sales.

The current differential that we see between in-basin and out-of-basin is about $1.30 or representing about half of the gas price.

We've got OPEN coming on, progressing very well, and we have a planned startup in early November; but we made the appropriate decision to curtail -- but only for a few months.

We are not going to growth for growth's sake, as we've proven in the past.

With OPEN, once OPEN is online, about 85% of our Utica gas will receive Gulf Coast pricing.

We believe this is a differentiator for Chesapeake.

While we love our takeaway position, slide 6, we may find ourselves a bit asset long when you consider the emerging dry gas portion of the Utica.

As we said in the past we have about 300,000 net acres in the dry gas window; a little more than half of that position is outside of our JV area with Total, but also within the dry gas plan development fairway.

The position is well delineated.

We've drilled 18 wells.

We have a number of successful tests; industry has a number of successful tests.

Importantly, the position is concentrated.

That means we can drill longer laterals.

It's also secured.

77% of our leases have options for five-year extensions.

It's become yet another strong Northeast gas asset in our portfolio, one whose development could be accelerated.

Now turning to the Powder River Basin, as we said in the past we have a highly concentrated acreage position here as well.

We have multiple stack plays, and the end result is a massive resource potential.

We have quoted 2 billion barrels of resource available to us.

Powder provides both stratigraphic and product diversity.

That acreage position in the Powder is also the deepest and hottest part of the basin, highest energy.

As the map indicates in the upper right, much of our position has two, three, or even four targets out there to be developed.

We continue to learn about each of these targets, and they continue to expand.

Recently we've been surprised with even some of our Nio results, pushing out what could be a near-term development plan.

Current plans are focused on the Sussex, as you know.

We've drilled 20 wells now and continue to see really a strong operational result.

From the first-half 2014 to the first-half 2015, team reduced cycle times by 40% and reduced costs by over 25%.

Couple those operational efficiencies with the demonstrated well results that we note on the map, and we continue to be really excited about what the Powder is going to deliver.

This is yet another asset that could be accelerated in our portfolio.

Let me now turn the call over to Jason to share highlights from the Southern Division.

Thanks, Chris.

Overall, the Southern Division had a very solid quarter as well.

All areas continue to improve with respect to operational efficiency gains, as we continue to push technological limits and test new formations which will drive value for Chesapeake for a long time to come.

This morning I would like to briefly cover a few operational highlights of each of the major operating areas.

Starting with the Eagle Ford, the team continues to improve.

Year-to-date well costs are down 12% from our 2014 average to $5.2 million per well.

This is particularly impressive as we continue to drill longer laterals.

When measured on a per foot of completed lateral basis, our costs are down 20% from just over $1,000 per foot to $800 per foot.

Key drivers behind this are improvements in cycle time, which have improved 8% from 2014 despite drilling 7% longer laterals.

Volumes were down quarter-over-quarter by 7% to 105,000 barrels of oil equivalent per day.

In large part this was due to a third-party treating facility which was down for 60 days, equating to an average of 14,000 barrels per day over that time period.

This was unfortunate, as otherwise we would have realized a net gain in production for the quarter.

We now have an alternate plan in place to prevent volume disruption should this happen again.

The facility is now up and running and we actually experienced our all-time Eagle Ford production high of 127,000 BOE per day in July.

We currently have a rate of approximately 116,000 barrels of oil equivalent per day.

On slide 10 of our investor deck we have updated the production from our spacing test which we highlighted on the last call.

All three areas continue to perform well with little to no degradation in our performance curves.

This is very promising and supports the incremental development of 600 to 700 Eagle Ford locations that we highlighted last call.

We will continue to test spacing limits this year with additional spacing tests designed for 250 feet between wells.

The team has also identified Upper Eagle Ford potential that we believe will be very competitive in our portfolio and plan to spud the first well test in the third quarter.

Finally in the Eagle Ford, we continue to push forward with prioritizing longer laterals as part of the development program.

The first two 10,000-foot wells are on flowback and cleaning up from the stimulation work.

We are also in the process of drilling our first 13,000-foot well.

The team is pushing the technological limits of the field, and the results are showing.

Very similar to the Eagle Ford, the Haynesville team continues to execute on the strategy to drill longer laterals with enhanced completion designs.

The fruit of their work is shown by our production growth of 9% for the quarter, as we rose to 669 million cubic feet a day net.

On slide 12 of our published deck we have an updated performance on our 7,500-foot extended laterals that also used our enhanced stimulation techniques.

These wells continue to perform at a rate 10 million cubic feet a day higher than the offsets while maintaining a much shallower pressure decline.

The team continues to optimize development in the field using these enhanced techniques, with plans to drill the first 10,000-foot laterals in the fourth quarter.

We remain very positive on the base enhancing potential of the Haynesville re-frac program as well.

We were able to participate in eight wells via our non-operated positions.

The average well increased 2.7 million cubic feet a day, and these tests have provided further verification that we have tremendous upside potential in the asset area.

Over the last quarter the teams have worked to optimize our candidate selection and will begin implementation of our operated Haynesville re-frac program this quarter.

Now I would like to move on to the Mid-Continent.

On slide 13 we show an expanded view of the STACK, also note as the Sooner Trend, Anadarko Basin, Canadian and Kingfisher counties.

What is unique to Chesapeake is the fact that we have a position in nearly all of the objectives, not just one or two.

In the past we were taking advantage of our non-operated position to participate in many of these plays and gather information.

This year we have started to bring our first test online in some of these plays.

First off I would like to highlight the Oswego formation, where we have drilled three wells.

The first two wells were geologic successes; however, the completion technique we utilized caused the wells to produce sand, which initially damaged our submersible pumps.

We continue to work these wells and test alternative lift techniques.

We changed our completion technique on the third well, which proved to be highly successful as the well came on at a peak oil rate of 1,955 barrels per day.

We also brought online our first two wells in the Hoxbar formation.

One produced at 1,515 barrels of oil per day and the other at 750 barrels of oil per day.

These wells are just the first step in a development trend we believe will help change the production profile of the Company.

We have also been working to quantify our development potential and update type curves with the various plays in the STACK.

On slide 14 you'll see how meaningful this area is to Chesapeake's portfolio.

By converting our acreage position from surface acres to developable acres we have over 1.8 million net acres of running room.

We currently estimate that there are almost 4,500 net locations that could be developed in this area, with a resource that could be as large as 2.1 billion barrels on a net basis.

While current production from the area is gas-weighted, many of the new plays are weighted more towards oil and will help shift our product mix over time.

We have a lot of confidence in the development of the Mid-Continent and want to do so prudently.

We'll be moving our first full-time rig into the area in September to begin development of the Meramec.

We believe this is the first rig of many as we come to anticipate the same sort of success here as we have experienced in our other business areas.

It's a really exciting time for us as a Company operationally speaking.

Lower prices are pushing us faster than ever to pioneer new technology, and I believe Chesapeake is a leader in driving down development costs.

We are also testing new formations in many areas that will improve upon our already world-class portfolio.

I would like to now turn the call over to Mr. Nick Dell'Osso.

Thank you, Jason; and good morning, everyone.

As Doug mentioned, we're doing very well in the areas within our control.

Our production during the second quarter was extremely strong, driven by Utica and Haynesville productivity gains and base optimization across the portfolio.

We also saw our production costs and G&A continue to move lower compared to a year ago.

As a result, we've improved all three of these guidance ranges.

As we've been noting since the beginning of the year, our CapEx was front-end loaded, and we completed Q2 in line with our plan for the quarter and are reiterating our CapEx guidance range of $3.5 billion to $4 billion.

We are very pleased to be outperforming on production, outperforming on operating expenses, and on track with our reduced capital plan for the year.

Moving to our product prices, the decline in oil and natural gas compared to this time last year has been dramatic.

At our second-quarter earnings call last year, oil was trading around $97 a barrel and natural gas was over $3.90 an MCF.

Today they are about 50% and 30% lower, respectively.

As shown on slide 16, our realized gas price in the second quarter was lower compared to a year ago not only due to lower NYMEX prices but also quarter-over-quarter due to the seasonal increase in Northeast basis differentials, a trend that we've seen every summer now for the third year in a row.

While still seasonally low, our regional basis dips were improved compared to last year -- compared -- sorry, with our second-quarter 2015 basis of $0.49 compared to our second-quarter 2014 basis of $0.61.

However, we do expect low Northeast in-basin prices to continue through the third quarter and until heating demand returns.

Further, we are continuing to forecast production curtailment from our Pennsylvania Marcellus assets in recognition of this weak pricing environment through the end of 2015.

We do expect a nice uplift in our realized Utica pricing due to an increase of 350 million gross cubic feet of gas per day being marketed on the Gulf Coast when the Spectra OPEN pipeline is placed in service in November.

As for our non-basis costs, which include our gathering, treating, transportation, compression and fuel charges, and marketing fees, these costs have been fairly flat over the past few quarters and are actually improved when compared to last year.

Due to continued success and strong production we are seeing in our Haynesville area and the outstanding work our Barnett Shale team has done to maintain the strong base production, we have also reduced our 2015 estimate for our MVC payment by around $20 million, thus reducing our overall commitment to be accrued in the fourth quarter.

When we take a preliminary look toward 2016, we see our total differentials -- inclusive of MVC obligations -- being flat to 2015.

With the strong results from our Haynesville area and the majority of our Utica gas receiving better Gulf Coast pricing, we anticipate our basis differentials will improve in 2016 and offset a forecasted increase in MVC payments and transport associated with the OPEN project.

As for our realized NGL prices, we have seen much lower propane and butane pricing since the end of March due to very high storage levels.

On top of that, approximately 40% of our NGL production is from the Utica, where there is a natural seasonality between summer and winter pricing due to heating demand.

As a result we do not see improvements in the present of ethane, propane, or butane until the fourth quarter.

So we expect our third-quarter NGL pricing to be below even these levels.

Switching to our balance sheet, we had over $2 billion in cash and an undrawn credit facility with capacity of $4 billion at June 30.

While our cash flow in the second quarter exceeded Street projections and our D&C capital spending was in line with our quarterly guidance, we continue to see negative changes in our working capital due to decreasing capital spending levels.

The impact was significantly less in Q2 compared to Q1, and we do see this slowing down over the next two quarters as we reach the low point of our expected decline in activity.

We are driving to see even further improvements to our liquidity, and we are making progress on a number of fronts to enhance our position.

As Doug previously mentioned, due to capital efficiencies and the depth of our portfolio we have the potential through asset sales, joint ventures, and participation agreements to further enhance our liquidity.

Proceeds from any capital inflow will be directed to the most value-accretive option to our shareholders, including an accelerated drilling program in 2016 or 2017 and/or capital structure improvements.

To wrap up, as we look to 2016 we are confident and encouraged.

We have the people and portfolio to continue improving our cost structure, generate additional cash flow, and improve our financial position in this tough commodity price environment.

I am looking forward to sharing our progress in all of these areas as the year unfolds.

That concludes my comment, so I will turn the call over to the operator for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Good morning, guys.

Great details Doug, you mentioned about potentially already starting to do some conversations.

Anything about which areas you consider non-core?

Or when you consider strategic asset sales or JVs or any farm-outs, is there a particular area that you could highlight or anything else you could say on that?

Sure, Neal.

Thank you for the question.

At this point in time we have not provided which exact assets, although I will tell you we are working multiple options across the portfolio.

We don't see any one solution necessarily; we see several that are possible for us.

I also think it's important to drive your attention to a few things.

The strength of the portfolio and current commodity prices and our current ability to reinvest in the portfolio points us towards evaluating: where is the lower EBITDA assets at present; what is the forecasted funding level that we see with this prolonged period of depressed prices; and is the asset idle or can we accelerate some activity there which would accelerate value?

I personally am a fan of the JV structure if it's properly handled.

And we would do exactly that.

It builds underlying cash flow and accelerates value into the current term.

But we also know that some of the assets, it may be better to completely exit the asset just because we're not going to be investing there for some time.

When we have stated that we would do these things in the past that's exactly how we performed, and I expect that we will be sharing more in the coming months on how we plan to advance these initiatives.

And we will be providing more color as the opportunities mature, Neal.

Okay.

Then Doug, maybe for you or Nick.

Just any further comments you can say?

You mentioned that conversations have started with Williams.

Anything, Nick, you could say about potential timing of something like this?

Or when you guys are having these conversations, does this factor in that forecasted funding level that, Doug, you just alluded to as well?

Sure.

When we look at the opportunities to improve liquidity, Neal, that not only includes the JV or asset sale type of structure or participation agreement, but it also includes minimizing our liabilities.

Nick has detailed a little bit on our differentials.

But it's important to note that we see our differentials as flat to improving before any transaction or any deal with Williams that we could potentially reach.

The important thing is we are continuing to work with Williams.

We are pleased with the progress, and we anticipate coming to some resolution there as we work across the portfolio very soon.

So Nick may want to add a little more color to it, but we are encouraged there and you'll be hearing more about that.

Yes.

All I'll add there, Neal, is just to underscore what Doug said, which is that we have not baked any improvement like that into our projections or into any of our commentary around what our differentials look like.

We feel good about where we're headed for my differential perspective from all the things that we can control on our own.

And we continue to have discussions with Williams.

But anything that changes on that front, like we talked about all along, we are aiming for solutions that would be positive to Williams, positive to us.

And none of that is baked into our forecast at this point in time, so it would represent future upside.

Great.

Thanks for the details, guys.

Charles Meade, Johnson Rice.

Doug, I wonder if I could get you to talk a little bit more about what the quarterly production progression looks like.

I want to make sure I'm making the right inferences as we look at really a weaker guidance this morning, an exit rate -- and really a Q4 rate -- significantly higher than what I and the rest of the Street is expecting.

I see that you are going to have maybe an incremental net 35 MBOE a day roughly from the Utica online with that Spectra line.

But that 660,000 a day, does that reflect that?

And then going into Q1 2016, are we going to see a bump up from those Marcellus volumes as -- if you expect the basis to tighten up there in that, the depth of the winter?

First Charles, just let me note that the productivity capacity of this Company is amazing.

And I continue to be impressed by the operational efficiencies and base optimization and things that are taking place, the focus on delivering more for less.

Specifically to your question is that productivity and our confidence in raising the guidance at a year-end include many things, one of which does include the OPEN line there in the Utica.

That is in our forecast.

As we look forward to 2016 we definitely, as those basin differentials tighten up, have that potential for additional volumes from the Marcellus.

Chris and Jason may want to provide just a little more color on any specific assets that you guys see appropriate.

Yes, I would just reiterate -- Charles, this is Chris Doyle -- in the Utica we are planning to fill up the OPEN capacity as quickly as we can.

That will be differentially a positive for us, and that's baked into the forecast.

Very confident of the timing of that project.

They're doing a really good job.

The Marcellus team has done a great job responding to daily market movements up or down.

This is a daily conversation that we have, and we have one of the best operating groups out there, ready to respond at a moment's notice.

And as you point out, that is likely going to be late this year, early next year.

And we have right now 500 million a day behind choke that we can get on very quickly and respond to.

So really pleased with the operating teams, their ability to react quickly.

I will say, in the Marcellus none of that 500 million behind choke is in the forecast.

Got it.

Thank you, Chris.

That's good detail there.

Then perhaps this question would be for Jason.

I like the slide that you put in your presentation showing the response in the Haynesville from the re-frac program.

I gather that most of that has been non-op to date.

But can you talk about what you have seen, I know it's been a surprise of some degree, but how big of a surprise it's been for you, and what your appetite is for that on an operated basis going forward?

Yes, let me also finish on the volumes.

We do have our Barnett VPP rolling off too, so that's a good jump for our production in the fourth quarter.

Haynesville is doing really strong, as you can see from the profile we put out there, our increase.

We will see a slight dip in Haynesville third quarter just because of timing of completions, but expect it to rise again in the fourth quarter, just to cover the volume comments.

Re-fracs, again there's two ways to think about this.

We have participated via non-op; seen very positive results there.

I think a lot of the players in the Haynesville have just all around the board seen good, positive results.

We highlighted on our last call that when we drilled our initial well in a unit we would come back and drill the second well in the unit maybe a couple years later, and 100% of the time we have seen that original well or parent well increase in production due to those wells.

So we've seen the results on our own where we've enhanced the rock quality around the old wells.

So very positive.

We have, we calculated, 529 Haynesville wells that were drilled prior to 2012 with over 60 different completion types.

So those are our inventory of candidates for the Haynesville.

If you look at their productivity per foot those wells averaged 1 million cubic foot per foot of lateral.

The wells we complete today average almost 2 million cubic feet per foot of lateral that we drill.

So that's really the upside that we see: just wells that were understimulated.

Those wells drilled before 2012.

So our potential out here is very large.

Then the productivity gains you ask about on the 7,500-foot laterals, what's exciting there is it's just a combination of all the technology we've applied.

One of the great things that Chris and I are able to do is share what we're learning in these different fields; so that gets us up the learning curve very quickly.

So both the completion techniques and the longer laterals have just been positive, especially because they were in these tests (technical difficulty) lower-quality rock area where people had written it off.

Applying this technique has really doubled the area that we can drill in the Haynesville.

Chesapeake also has a very large acreage position, so we think we're preferentially advantaged to be a company that can drill the longer laterals of the 7,500-foot and 10,000-foot variety.

So again Haynesville is a really exciting play for us and you've seen it in the production results that we highlighted today.

That's great, Jason.

So we're going to see you guys getting after re-fracs on the operated side, then, in (multiple speakers)

Our time is coming, yes.

We've done -- you saw I highlighted in the Mid-Continent as well as we've got large non-op positions that are associated with our operated areas, we take that data that we get in, we analyze it.

Our teams are very proactive at looking at our competitors out there.

But that prevents us from having to waste money, always being the tip of the sword on some of these technologies.

But it's there, and we'll be moving after it.

The teams are just working through a rig program.

I've got them thinking about how many of these re-fracs could we do that would equate to a rig line running?

So a tremendous amount of potential up there, and the teams are all over it.

This is Chris Doyle again.

I think the other thing to point out is that it's not just Haynesville.

We have two years' track record showing that we can optimize these completions.

We've done exactly that.

So going back to pre-2012 wells and re-fracking them, it's a massive lever for us and one that we'll get all over here pretty quick.

Yes.

And of course Barnett, we have the same program going on the Barnett as well, tremendous potential to help in the Barnett and produce some of these MVCs, etc., over time as well via that program.

Great.

Thanks for that commentary.

Bob Brackett, Sanford Bernstein.

Quick follow-up.

What are the CapEx costs for those re-fracs?

We're going through that now.

What we're doing is looking at the different vendors out there.

They've all got their secret sauce that they use.

So we're looking at not necessarily how much one costs, but who gets the most deliverability per dollar that you spend.

They're typically in that $1 million range.

We've tried two techniques.

One is just using diverter technology; that's a little bit easier and cheaper job.

The other one that we do is we can put a liner in place; that gives you pretty much a new wellbore to start with.

It's incrementally more expensive, but we've seen better production results there.

So those are some of the things that we're looking at as we launch the re-frac program.

Thanks.

The other quick question was on your marketing profit, that $209 million.

You've reiterated your full-year guidance on marketing, gathering, compression net margin.

Where did that come from?

And it reverses out for the rest of the year; is that right?

I'm sorry, Bob, I don't -- your question is --?

The $209 million positive on market, gathering, and compression.

Yes, yes; sorry about that.

That is basically a mark-to-market of a marketing contract we have which gets treated like a derivative because it's being priced on something other than the gas we're selling under the contract.

So basically that contract began its operation this quarter, and so we take a fair value measurement of the future contract just like you would a hedge on the books.

And it's in a significant gain position today.

There is a recognized portion of that gain that flows through our recurring earnings.

The rest of it we adjust out as nonrecurring.

And if it stays in place that will flow through the income statement in the future.

And if the gain increases or decreases then the mark-to-market will change on that as well.

It's just like a hedge.

Great.

That's clear.

Thanks a lot.

Brian Singer, Goldman Sachs.

Doug, in the commodity environment we're in it at least today, the notion of selling assets and accelerated drilling is not always universally cheered.

So I wanted to follow-up on your hope to use asset sales proceeds to either accelerate drilling next year or to enhance the corporate structure.

If we assume this is used to accelerate drilling, what are the key metrics that you and the Board are going to look to, to measure the efficacy of this use of proceeds at the corporate and/or the well level?

And then to the degree it's used for enhancing the corporate structure, can you talk about some of the options that you are considering?

Yes, that's a great question, Brian.

Thank you.

To the first point around asset sales in this commodity price environment, one of the things that I firmly believe is that the value and quality of Chesapeake's assets are not recognized in the market.

If you go back five, six, seven years ago when the whole shale revolution got started, you heard things like shale.com and manufacturing process and come into the energy industry and all that kind of stuff.

And in a high price environment that's relatively true.

When you get in a stresses commodity price environment, it's all about the rock.

And this rock in this Company is of the highest quality in most of our operating areas.

So our confidence that those asset sales, they could be very strategic to another company.

To try to forecast what the strategic needs of another corporation may be regarding their drilling program or their holes in their program for longer-term growth is difficult, and so we won't try to do that.

But we are going to test the market.

Obviously there will be price decks used that are significantly deflated that can impact the value.

But to offset that we also know what we can do with our operating teams, and that's why we're talking about JVs or participation agreements, because we'll knock it out of the park, as demonstrated in improvement in all the different assets.

If we fund it at a different level, there are other entities beside operators that are interested in deploying cash into the energy industry, and they want to deploy it with an efficient, high-quality operator.

And that's Chesapeake.

So I'm encouraged by that.

That said, it definitely is market dependent and I look forward to sharing that progress in the future with you.

Regarding the key metrics around what we would do with the proceeds, it's very important to note that we have several options there.

The strength and quality of the assets, the high-quality returns that we see in areas like Powder River Basin, the improvements in the Haynesville and the competitiveness there, and also the quality in the Utica: these are assets that, based on current pricing levels, current strip levels, attract capital.

So deploying proceeds back into our program is very attractive.

We would not do that if it were not economic and if prices were depressed sufficiently that we wouldn't be making the returns that we would anticipate.

We're not going to do anything dilutive to shareholder value.

So then you start thinking, well, if the prices persist and we bring liquidity in, we will look at other capital structure opportunities.

That's whatever is the most accretive to the Corporation and adds the most value.

It's really a question of in this commodity price environment and with some of our challenges with respect to debt and the commitments using our rock, our rock quality, using our operations, and making sure that we have a comprehensive strategy to add the most value to the shareholders in the near term and the long term.

So from a corporate objective we will be evaluating all the conventional metrics, but also looking at what's most accretive for the long term for the Company.

I guess, to press you a little further on the specifics then, if we have this conversation or look out one, two years from now and look back on the decision on potential use of proceeds from the asset sales, is there a corporate returns metric that you're targeting or looking for?

Is there a net debt to EBITDA metric where you want to keep your balance sheet?

Or is it just at the well level you've got an inventory, the rates of return make sense at the well level in the current commodity price environment, go ahead and spend the capital?

Right.

Well we absolutely look at well level, but we also look at the corporate level performance.

So return on capital is very important.

Obviously for all the companies that's significantly impacted with the top line being affected the way it has been.

But whether it's return on capital, the financial efficiency metrics, capital efficiency metrics, those are all things that will weigh in in our discussions with the Board.

So I hesitate to say it's one particular thing that we're trying to achieve.

As Chris noted when he was talking, where not going to grow production for production's sake.

But we will be focused on all of those metrics, which include operating metrics, efficiency metrics, and financial metrics.

Great.

One other quick one.

You're highlighting the STACK area a lot more.

Obviously that's an up-and-coming play.

Is this an area you want to develop and operate, find a partner, or sell entirely?

That's a good question.

The key there is that we have a huge position in the STACK.

We've got some of the best areas, we believe, and we've got some of the best people to work on it.

So I'd point it back to that we're not necessarily looking to sell anything; we're looking to capture the greatest value.

So the options that are in front of us are open, and we are just focused on driving the greatest value.

So -- however we can do that.

What's great about this Company is we've got a ton of options, a ton of options.

So whether it's oil, whether it's gas, the rock quality and the operational improvements give us tremendous flexibility.

That is what makes me excited in this depressed commodity price environment and given our debt load.

Thank you very much.

Jason Wangler, Wunderlich.

Was curious; you gave us some good color about the Utica and the plans of turning back that gas as you get your pipeline up and running.

What are the thoughts on the Marcellus?

Is it simply a price issue?

Is there something that you're waiting for?

Or is it just watching the differentials and getting a return?

Jason, this is Chris Doyle.

Like I said, we watch it daily.

What we're keying in on -- we have very, very low operating costs out there.

But it becomes and has become a -- we don't want to get this gas away for free.

I would love to sit here and say that we will be able to hold 2 BCF a day flat with one rig for the rest of eternity.

But that's not the case.

We have the opportunity and what we've done is ratchet back activity all the way back, so that any activity that we're doing is either there to protect the best acreage position in the play or to bring on incremental gas.

And what we've seen to date is just really weak in-basin pricing given the gas picture up in the Northeast.

That changes, I believe, maybe not next month but over the next 12 months.

And we'll be prepared, and again we'll unlock just a fantastic asset for Chesapeake.

That's really helpful.

Then maybe just down in the South with the Eagle Ford, are you guys still building inventory down there?

And just what's the plan around the completion schedules and things as we look forward in the Eagle Ford?

This is Jason.

Over the course of the year we're actually drawing down our inventory.

At the beginning of the year we had a balance of 151 wells.

By year-end expect to be about 96 wells.

Great.

Thank you.

I'll turn it back.

Dan McSpirit, BMO Capital Markets.

Thank you and good morning.

Where could or does the STACK rank among assets in the portfolio in terms of returns or economic limits?

Just asking in an effort to get a better sense of how capital may shift to this operation over time.

This is Jason.

The returns, again, for some of the plays, Meramec, etc., are just stellar.

They compete very favorably to anything in our portfolio and there are some indications that they could preferentially start to draw capital.

So again the reason we're moving a rig out there is to start developing that vast resource potential we've got out there.

Again, in my mind this is something that could be as big as the Eagle Ford out there.

It's just a huge amount of potential with wells that have huge IPs on those wells.

Okay, great.

Then as a follow-up, do any of the options to create value and/or replenish liquidity include a VPP?

This is Nick.

No, we're not looking at VPPs at this time.

I think we're a little more focused on getting our portfolio right.

So when I think about getting our portfolio right, that to me says we want to own the assets that are going to be the most productive in the environment that we sit in and with the capital we have to invest.

So we have some areas that we're not investing capital.

We have some areas that we could be investing capital quicker.

And we could either sell the areas we're not investing or find partners to invest more quickly in some other areas.

So VPPs, where we're selling out of current cash flow and retaining some of the cost structure, doesn't really fit us as well today.

And particularly at what I would consider a pretty low forward price deck, not a great time to sell VPP.

Great, got it.

Maybe one last question here, just on housekeeping maybe on the Utica itself.

What is the transportation cost on the pipeline to take production out of the Appalachian Basin?

I guess that's a Spectra pipeline.

Yes.

Spectra is going to get us the vast majority of our Utica to the Gulf Coast.

We are looking for -- there's other pipeline projects coming online next year out of Pennsylvania.

Our cost out of the Utica, blended, is about $0.38 an M; and so we feel really good about that transportation cost to get us to the Gulf Coast.

Out of Pennsylvania we have some outstanding FT.

We have quite a bit of volumes that we choose not to sell in-basin today and leave curtailed.

As more transportation comes out of that basin over the next one to two years we look for that in-basin pricing to improve relative to the Hub.

But overall we're looking to continue our transportation portfolio around projects that give us the right value.

So out of the Marcellus our historic average transportation cost is about $0.55.

Some of the newer projects that have been discussed lately are priced at a point that we haven't seen as attractive, and so we've stayed away from those.

But we are looking to see those benefit the overall market there.

So as things come on that are priced competitively to a market that gets us a beneficial price like OPEN is doing, then we're all over it.

Much appreciated.

Have a great day.

Thank you.

Matt Portillo, Tudor Pickering Holt.

Just a quick follow-up question.

You mentioned your working capital burden would lessen in the back half of the year.

Is there any color that you can help provide, just roughly, on how we should think about the cash balance as you look at year-end, where you hope to have your cash balance assuming your spending plans and strip pricing on a go-forward perspective?

Sure, Matt.

As we think about our cash balance going through the rest of the year we had forecasted earlier this year to be at $2 billion.

That was before we saw some of the fall-away in working capital in the first quarter and before we saw some fall-away in pricing.

If you think about where we were at the time and you look at the flow that occurred during the second quarter, we actually hit that spot on.

So with the challenges of pricing and with the challenges of other things that come into play there, we're pretty pleased with what that flow during the second quarter looked like.

As for the end of the year, it's dependent on a lot of things.

It's dependent on prices; it's dependent on a number of other pieces that we have moving now.

So at current prices it would be a little less than $2 billion.

And as to where exactly it ends up, we're going to continue to work on the things that improve that answer.

So it's a lot of variables there, but we feel good about how we look at our flow for the second quarter, where it's positioned us for Q3 and Q4 with our reduced activity levels in this current pricing environment.

Great.

Thanks for the color.

Then just a second follow-up question, just looking at your activity versus previous guidance.

One of the areas where it looks like you're stepping up versus the year-end expectations is the Haynesville, going to seven rigs versus I think what was previously a two to three rig count program you were expecting to exit at.

Could you talk about the decision process there and maybe how you're thinking about economics as they stand today, either break evens or returns?

Just trying to get a better sense of how the plays progress with all the innovations that you've put forth in completions.

Sure.

Let me give you a little bit of color on that and then I'll have Jason add some more.

In the Haynesville we've seen just a tremendous performance out of that team in the first half of this year, and it's given us some flexibility to do a better job of meeting our commitments there.

That's important, as we think about the question Doug got earlier around how we direct capital and whether it's to well-level economics or corporate-level returns.

This is a decision where we think about both.

And it absolutely, positively impacts our corporate-level returns when we can meet our commitments with well-level economics that are very strong.

That's what the Haynesville team has been able to deliver for us this year.

So I'll let Jason talk a little bit more about that, but we've been really pleased to be adding activity there and do it within what our budgeted capital for the year is, knowing that that's been beneficial to our overall corporate performance.

Yes, Nick hit most of the points there.

The Haynesville team just continues to impress.

We highlighted the performance improvements, productivity increases, but costs have also been just coming down.

The team as far as drilling went used to drill wells for $4 million, just the drilling side, and wells that were 35 days.

This last few weeks they've TD'd five wells under $3 million, with the one they TD'd this week at $2.7 million, and they've done it in 23 days.

So they've shaved almost 10 days off the time to drill a well out there.

So just fantastic improvement there.

Again, as you drive these costs down, productivity up, economics just look favorable even in a $3 gas world.

Great.

Just I guess is there any kind of rough number we can think about on the return profile there?

As you guys think about either breakeven economics on your leading-edge wells or the return profile, just trying to get a sense of how you guys are thinking about that.

Yes, as we push the longer laterals again they get 30% returns when you consider all-in cost, just everything, up to 60% if these 10,000-foot wells are successful.

Because we still have the MVCs we consider those differentials sunk in the short term; internally they're 100% rate of return wells.

So again that drives some of our activity there.

But again all-in they're still very competitive wells and just getting better every single month.

Thank you very much.

David Tameron, Wells Fargo.

Doug, how are you thinking about 2016 today as it stands as far as level of spend, stay within cash flow, your thoughts around that?

And then if you care to, can we get a maintenance CapEx number for 2016 that would -- I know there's a lot of moving pieces with the Marcellus -- but some type of number as far as CapEx goes that would allow production to stay flat?

Looking at 2016, Dave, we are not anticipating any significant recovery in pricing.

As you look forward the curve is pretty tough.

So the complete evaluation of how we invest scarce cash flow is really, really important.

So our focus, the discussions with our Board, with our capital allocation plan, considering the operational improvements that we have across the portfolio, what we know is that because of the strength of the assets and the operations we've got a lot of really good places to invest.

So saying to you specifically that we're going to be investing at cash flow or we're going to be overspending, we just haven't provided that guidance at this time.

We will continue to evaluate and look at our options.

Because as you know, what we get six months down the road, a year down the road, it will be different.

And it could be plus, it could be minus.

So I'm hesitant to be too specific about exactly what we're going to do.

We just have great options, Dave.

That's the simple fact.

We've got great options because of a great portfolio and great operating teams.

And then you had a second question.

I'm sorry, what was the second part of it?

No, just the maintenance CapEx.

Oh, maintenance CapEx.

With this, where we sit today we're ranging probably in the $2 billion range in maintenance CapEx.

We can update that a little bit more specifically here in coming months, but it's going to be in that range somewhere.

The only thing I would add is we took a look at maintenance capital in the Marcellus last year at Analyst Day and we said four to five rigs.

And as Doug mentioned, that has completely changed.

Sprinkle in 30 million a day wells that are drilled in 7.9 days, and all of a sudden -- hey, let's keep 2 BCF flat with two rigs.

And I know it's going to be better a year from now.

Yes.

I think that that comment that Chris made, Dave, it's kind of key.

I just want to emphasize I think from an unconventional gas and oil company perspective here in the United States, that it's going to start focusing on the rock quality.

We're going to see across the industry more and more focus on the rock quality and the quality of the operations applied to that rock.

That is something that we still consider to have a competitive advantage, and whether it's improvements of the Marcellus, improvements in the Haynesville, you can count on Chesapeake continuing to lead that curve on the operations and the quality of the rock that we've got.

That concludes today's question-and-answer session.

I'd like to turn the conference back to our speakers for any closing remarks.

Okay, thank you.

I appreciate everyone dialing in today.

Just would like to reiterate what I said at the beginning of the call.

Chesapeake is leading with our strengths.

We are attacking our liabilities and we are driving for greater shareholder value.

Our portfolio offers several strategic options that provide opportunities to strengthen our cash flow and liquidity, and I'm looking forward to sharing the progress with you in the coming months.

Please feel free to reach out to Brad with any other questions that you may have.

I thank you -- thanks to everyone for joining us today on the call; and that concludes the teleconference.

Thank you.

Thank you, everyone.

That does conclude today's conference.

We thank you for your participation.