Chesapeake Energy Corp (CHK) 2014 Q2 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation second-quarter 2014 conference call.

Today's conference is being recorded.

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

Please go ahead.

Thank you, Doug.

Good morning and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2014 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 statements which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecast, 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 on page 86 of our August 6, 2014 10-Q, and in the Company's other SEC filings.

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

I would next like to introduce the members of Management who are on the call with me today -- Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Chris Doyle, our Senior Vice President of Operations Northern Division; and Jason Pigott, our Senior Vice President of Operations Southern Division.

We will next turn to prepared commentary from Doug and Nick and then we will move to Q&A.

Doug?

Thank you, Gary.

And good morning.

As Gary noted, I hope you've had an opportunity to review our 2014 second-quarter results that were issued earlier this morning.

Chesapeake had another strong quarter of production growth and operating performance.

We continue to make foundational progress on our strategies of financial discipline and profitable and efficient growth from our high-quality assets.

I'm very pleased with our continued improvements in operating efficiencies, measured by cycle time improvements, capital spending reductions, and cash cost leadership.

Production for the second quarter averaged 695,000 barrels of oil equivalent per day.

This represents an increase of 13% year-over-year after adjusting for asset sales.

Our crude oil production was up 12%, NGL production was up 72%, and natural gas production was up 7%, all adjusted for asset sales.

Once again we delivered this strong production growth while employing a very efficient capital expenditure program that was nearly 30% less than the year ago quarter.

I'm pleased to highlight that we are increasing the midpoint of our 2014 production growth outlook by 10,000 barrels of oil equivalent per day, or about 1.5%.

The production increase is a result of our focus on base production, a 35% increase in planned well connections during the second half of the year, as well as anticipated transaction timing of some of our previously announced A&D activity.

Looking ahead, based on current performance and anticipated completion of new infrastructure, we are confident that our year-end 2014 daily production exit rate will exceed 730,000 barrels of oil equivalent.

Turning to capital expenditures, total spending during the second quarter was $1.3 billion before capitalized interest, of which approximately $1.1 billion was for drilling and completion activities, approximately $50 million was for leasehold acquisition, and approximately $130 million was for other capital expenditures.

Importantly, we spent only 42% of our projected 2014 capital budget during the first half of the year.

And as I noted before, we expect a significant increase in well connections during the second half of 2014.

Consequently, we are on track to stay well within our previously stated full-year 2014 CapEx range of $5 billion to $5.4 billion before capitalized interest.

I'd like to conclude with a few remarks about our two recently announced strategic transactions.

First, the repurchase of all outstanding preferred shares from third-party holders of our Chesapeake Utica LLC subsidiary.

And, second, the acreage swap with RKI in the Powder River Basin.

The purchase of the Utica preferred shares is another important step in our strategy to simplify the Company's balance sheet while reducing high cost leverage instruments.

Importantly, we were able to fund the $1.26 billion repurchase price of these securities entirely through unrestricted cash on hand as of June 30.

I'm very excited about the Powder River Basin acquisition.

When this transaction closes it will effectively double our average working interest in the Powder River Basin to approximately 79%, concentrating our acreage in the southern part of the play where we currently operate.

We see tremendous future stacked oil potential on this acreage in addition to our core Niobrara development.

This acquisition efficiently leverages our overhead and geologic expertise in the Powder River Basin.

And we expect it to substantially increase our oil gross rate, our margins, and our oil mix as a percentage of total Company production.

This transaction is an excellent example of the calculated strategic steps we are taking to reduce our leverage to near-term natural gas prices by deploying our capital into areas with higher-margin oil.

This concludes my prepared remarks and I'll now turn it over to Nick.

Thanks, Doug.

And good morning.

We are very proud of our operational and financial performance year to date, as well as the significant progress we have made towards our strategic objective of leverage reduction and balance sheet implication.

As a reminder, we are reducing debt and commitments by over $6 billion in two years, and recently further simplified our capital structure with the repurchase of the CHK Utica preferred.

During the second quarter the rating agencies raised our credit rating by 2 notches, such that we are now positioned just below investment grade.

Turning to second-quarter results, production growth was strong, up 4% sequentially on an absolute basis versus the first quarter; while production expenses plus G&A expenses were down sequentially coming in at $5.89 per boe in Q2 compared to $6.03 per boe for Q1.

Chesapeake reported adjusted earnings of $0.36 per share in the second quarter with adjusted EBITDA of approximately $1.3 billion.

The primary driver of our sequential decreases in quarterly earnings and EBITDA was lower commodity price realizations, specifically for natural gas, which we previously discussed in our press release dated July 29.

I would like to take a few minutes to talk about our natural gas price realizations during the quarter and our expectations for the remainder of the year.

I will also discuss some other changes to our 2014 outlook.

As previously announced, on a Company-wide basis, our natural gas price differential increased to $1.91 per mcf during the second quarter, which was up from $1.08 per mcf in the first quarter.

Chesapeake's differentials consist of two key components -- basis, which is the discount to Henry Hub pricing that reflects various physical sales point at which Chesapeake sells its gas; and non-basis, which includes gathering, transportation, processing, and other marketing costs.

I would note that many of our peers report the non-basis component as a separate expense line item on their income statement; whereas Chesapeake reports non-basis as a deduct to its realized pricing.

This can make it more difficult to direct comparisons with our peers.

During the second quarter Chesapeake's non-basis gas price differential was $1.30 per mcf, a moderate increase from our first-quarter non-basis differential of $1.19 per mcf due to the mix shift towards some higher cost production areas.

The basis component of our differential was the key delta between the two quarters, and primarily reflects a large seasonal demand and pricing swing from a very cold winter to a very mild spring and early summer.

For example, in the first quarter Chesapeake's corporate quarter basis differential was a positive $0.11 per mcf to Henry Hub.

In the second quarter basis widened to a negative $0.61 per mcf.

As noted in our press release last week, the Marcellus region, where there is an oversupply of gas and insufficient demand in the non-winter months, accounted for the majority of the basis widening during the second quarter.

The basis differentials in the Marcellus have generally deteriorated during the month of July.

Looking ahead, we expect them to remain weak for the remainder of the third quarter before improving in the fourth quarter as seasonal weather demand should begin to take hold.

As a result, we've increased our Company-wide natural gas price differential outlook to $2.10 per mcf implied midpoint for the second half of 2014.

Of which an estimated $0.20 per mcf can be attributed to our expected minimum volume commitment shortfall payment during the fourth quarter, which is consistent with our previous guidance on this expected expense.

When averaged with first-half actuals, this increase yields our new full year 2014 gas differential outlook of $1.75 to $1.85 per mcf, which is up $0.15 per mcf from our prior outlook.

Looking forward to 2015, we expect basis, particularly in the Northeast, to remain challenged, but we expect our non-basis, which, again, is primarily gathering, transportation and processing costs, to improve as our less mature plays see increased gas production, particularly the Eagle Ford and Utica.

Please also note that we are increasing our projected 2014 full-year oil price differential range by $1.75 per barrel, which reflects the compression in the LLS/WTI spread, along with lower realized pricing for our Utica and Southern Marcellus condensate.

We are currently working on stabilization and alternate customer solutions for our Utica and Southern Marcellus condensate, which may create an opportunity to improve our differentials over time.

For NGLs we are increasing our projected 2014 price differential to NYMEX by $4.50 per barrel, which primarily reflects the weaker overall NGL prices we experienced during the second quarter, driven by weakness in ethane prices and lower seasonal demand for propane and butane.

Overall, ethane also represented a higher percentage of our NGL barrel in certain key regions, like the Utica and Southern Marcellus, which pressured our average price realization per barrel.

One final point on our outlook, please note that we are no longer providing forward guidance for oilfield service net margin, given that the spinoff of this business into a publicly-traded entity, Seventy Seven Energy, became effective June 30.

I'd like to conclude by addressing our funding plans for the RKI acreage swap and the Utica preferred share repurchase that we announced last week.

The cost to fund these transactions totals $1.7 billion.

As of June 30 we had approximately $1.46 billion of unrestricted cash on hand, and pro forma for expected non-core asset sale proceeds of approximately $700 million during the second half of 2014.

Our cash balance is expected to exceed $450 million after funding the RKI acreage swap and the Chesapeake Utica preferred share repurchase.

I'm very pleased that we have the ability using our existing capital resources to pursue this type of accretive high-value transaction that will materially improve our net asset value.

Please see a reconciliation of our pro forma cash movements on slide 6 of the presentation we published on CHK.com this morning in conjunction with the earnings release.

That concludes my remarks and now I will turn it back over to Doug before we begin the Q&A.

Thanks, Nick.

I'd just like to iterate that Chesapeake is standing strong on four pillars today.

We are growing production at a double-digit annual rate.

We are demonstrating excellent capital efficiency and cost leadership.

We are reducing our financial complexity.

And we are laser focused on creating shareholder value through a variety of strategic initiatives.

Chesapeake is a growth company.

We have the strategy, high-quality assets and talented employees to deliver growth quarter after quarter.

We are still targeting non-core divestitures is in 2014 and also evaluating other value-creation opportunities within our portfolio.

We will continue to look for these value-creation opportunities, such as the Powder River basin acquisition, where we can focus our expertise and talent on further growth for our shareholders.

And we'll now open the call up for questions.

Operator?

(Operator Instructions)

David Tameron, Wells Fargo.

Good morning, Doug.

Let me jump into details.

Utica -- with the Kensington plant coming on, you have -- I think the number you put out was 210 wells that are waiting on completion.

Can you just talk about the infrastructure out there?

Obviously the Kensington plant helps but how quickly can you get down that backlog?

How should we think about that over the next six months?

Yes, sure, David.

Chris Doyle will have some additional comments on it.

But as we look towards the year end we expect that inventory to continue to reduce as we build into the capacity we have available.

Chris, do you want to provide any other color?

Sure.

Hey, David, this is Chris Doyle.

As you mentioned, Kensington 3 did come online as scheduled, actually a couple weeks ahead.

It allowed us to ramp at the beginning of July and into this month.

We've got one additional, as we laid out, actually a couple of additional projects coming online in the fourth quarter -- an expansion of the Cardinal system with compression, and then additional processing capacity at UEO Leesville.

And that will get us to that target of about 100,000 net barrels of production by the end of the year, as we laid out at Analyst Day.

As you correctly said, our beginning inventory this year is about 200 wells.

By the end, we see that around 150 to 160.

The additional capacity will obviously allow us to bring those wells on throughout the remainder of this year.

And I also point out we probably have about 50 million a day of gas behind choke currently.

That's down a little bit from what we've talked about previously.

And Kensington 3 is a big part of getting that gas online.

Okay.

That's helpful.

And then just one more before I let somebody else jump on.

If I just think about the Utica -- and I know you guys covered this at Analyst Day -- but you are drilling a couple tests.

At Wetzel County you're drilling that dry gas test and then you're messing around with the oil window.

Doug, can you remind me, what's your snapshot -- or whoever, or Chris -- can you remind me of where you think this play heads over the next six months?

Obviously the dry gas is attractive but can you just give me your snapshot?

Yes.

Let me start with the oil test, the oil window.

We brought online the well that we mentioned at Analyst Day, is called the Parker well.

Brought it online this quarter -- or last quarter, I should say.

It's been on production for a couple of months.

We continue to be encouraged with what we are seeing.

It's the highest IP that we've seen to date.

We saw an area that we were expecting about a zero or very marginal return on our investment, is now in the mid 20%s and pushing higher.

Plan is we will continue to delineate that area, which I'd characterize to be about 80,000 to 100,000 net acres to Chesapeake.

Continue to delineate that over the next six months with probably two to four wells, some of those in moderate-risk areas, and continue to push out into what we currently characterize as higher risk as we continue to derisk this part of the play.

The idea that we can take a forgotten part of the Utica and drive value for this Company is really exciting for me.

I'll reiterate what I said at the Analyst Day.

The only company that can do that has to have cost leadership has to demonstrate cost leadership, and I stand behind what I think is the strongest operation seen in the basin.

Really excited about what we're seeing there.

Generally, that will be a little bit slower build just because of the infrastructure, but continue to like what we see.

On the dry gas Utica test, that's the Messenger well in Wetzel County, West Virginia.

It will be completed later this month.

It's about a 6,000-foot lateral.

Honestly, Dave, we pushed the timing of that well back a couple weeks to give us additional capacity to flow at higher rates than we initially planned.

The reason for that is what we saw in the pilot hole, what we saw in the logs, and what we experienced during drilling.

We are very excited to get this well online and continue to be very encouraged that the dry gas play does not stop at the river.

Okay.

And just to clarify, you mentioned the oil test.

Is that the well you're referencing when you said 20% rates of return and headed higher?

Yes.

And there is, as we've done and continue to do throughout the Company, is we're going to push laterals longer, we are going to optimize completions and drive returns higher.

Okay.

Sounds good.

Thanks.

Mike Kelly, Global Hunter Securities.

Hey, guys.

Good morning.

Got two questions for you.

One on the PRB and one on Southwest Marcellus.

In the PRB, just hoping you could give a little bit more color on the stack pay potential here.

And, really, if you could define the opportunity set there and compare the potential IRR prospects there versus the 40% you've laid out for the Niobrara to date.

Mike, thanks for the question.

This transaction up there really, to me, is an example of the whole Company, of all of our assets of the exciting things going on and the rate of return opportunities where we're just driving additional value, seeing lower cycle times, seeing reductions in our costs, and better returns for our shareholders.

It's a really exciting incremental opportunity for us.

I'm going to ask Chris to just run through a little bit more of that detail for you.

Yes, Mike.

As you know, we've been very open about how excited we have been about the Powder River Basin asset we have, especially on the subsurface.

But honestly we had work to do.

The first issue that we had to address was one of materiality.

The transaction we laid out last week doubles our exposure to what Doug characterized as multiple stack pays.

What I'll tell you is it's the single largest concentration of stack pay potential that we see in the basin.

What we saw is a little over 1 billion barrels of potentially recoverable resources now over 2 billion.

And that's really being driven by a number of things.

One is the continued successful delineation of Sussex.

As we laid out in those materials we have a play that stretches about 20 miles north to south that we've fully delineated north to south with the most recent Sussex test.

We are going back to work drilling longer laterals, currently drilling a 9,000-foot lateral in the Sussex and driving returns there.

That Sussex 1 well is at hoss, the 9,000-foot lateral, 9,200-foot lateral is adjacent to it.

So we're really excited about the Sussex.

We continue to be excited about the Parkman.

And what I'll point you to is what we look at, what John Kapchinske and his team is pushing towards the end of the year for additional Parkman test, Teapot test and Shannon test.

I think the true story here, though, is, excited as we get on the Upper Cretaceous and some of the other potential out there, is what has happened with that Niobrara.

In the course of a year, a team saw their rig count drop from 10 rigs to 3, had to essentially rethink absolutely everything they we were doing.

And all they've done in the first half is out-execute any expectation I had of them.

They have delivered what was a 40-day spud rig release well, now in the Niobrara is 26, and added 1,000 foot of lateral length.

That's a 35% reduction in cycle time and a 17% increase in lateral length.

And that's allowed us, as a team, to reestablish this asset as a really important part of our portfolio going forward.

I couldn't be more excited about what they've done, and excited to see what they do in the next six months.

Great.

Thanks, Chris.

And maybe I'll ask you, as well.

Just over to the Southwest Marcellus, can you refresh me on the takeaway capacity there to get gas out of that portion of the basin?

And then what the prices -- what do you expect in terms of realizations up there?

And then, really for you, Doug, just being blunt here, why or why not spin this asset out eventually?

Yes.

We talked about our takeaway in that area.

One thing that we look at is not only just our gas takeaway but also our ATEX commitment and ethane takeaway.

We feel good of what we have established and our ability to execute on that asset as we continue to expand capacity.

When we think about spinning this asset out, and talk about it internally, what we see is an asset that has really strong returns but, honestly, does not quite yet compete with our portfolio.

Which is more a testament of the strength of the remainder of our portfolio than it is the underlying asset.

It's an asset that we look at every quarter and continually outperforms our expectations, both in terms of reserves and well delivery.

And it's just a phenomenal asset.

I get excited when thinking about putting that asset out on its own, being able to fund its own growth, especially as capacity increases, or what it could do.

And putting that team in competition with some of the other players in the area.

All right.

Thanks guys.

David Heikkinen, Heikkinen Energy.

Good morning.

Just a quick follow-up on the Powder River.

You all talked about well costs of $8.9 million at the Analyst Day, and roughly 30%, 40% rates of return, and had these improvements.

With the longer laterals and the shorter days where do you see those returns, more specifically?

What we laid out in the materials last week, and I think again today, is very clearly where we see our 2014 program averaging about 5,800-foot lateral going into the year.

That's that $8.9 million.

Cycle time improvements get those returns back up over 20%.

Extending our lateral length where we see in the second half of this year about 6,800-foot laterals will increase capital a little bit, but drive returns over 30%.

And then as we've done in multiple plays reinvesting those capital savings into enhanced completions, will drive our returns to 40%.

And we see we get there fairly quickly.

Okay.

And then just on the overall corporate cash flow guidance, with the higher differentials, you brought that cash flow for 2014 down.

And, Nick, you talked about 2015.

As you think about the CapEx of $5 million to $5.4 million, does that include the acquisitions?

I just want to be clear on that.

No.

$5 million to $5.4 million would not include the amount we plan to use to complete the RKI exchange.

Nor is it offset by asset sales either.

Right.

So, on an apples-to-apples basis, you bought about 4,500 barrels a day and you're now growing 5,500 barrels equivalent a day more than what you expected previously.

Is that a fair number?

Yes.

It's fair.

The 4,500 barrels a day I think was only for the last couple months of the year.

It's not even for the full second half.

And then as you go through cash flow and CapEx balance looking at the next three-year plan, how does that flow given what you just talked about from a differentials headwind?

We go through a pretty competitive capital allocation process every year, and we're in the middle of that right now for 2015, looking at where the best investments can be made to maximize return for shareholders.

And, so, we take into account all those things.

And as Chris noted in his Analyst Day presentation, an asset like the Marcellus North, which has the ability to produce incredible returns, might stay flat for a period of time and be a free cash flow generator, given the pricing dynamics we expect we will face coming into next year.

Now, that being said, we look at opportunities all the time to try and improve those things.

And each team feels the pressure of wanting to have more capital and fights to find ways to increase their expected returns.

So, it's a constantly evolving analysis as we think about that.

But we feel very confident in our ability to continue to invest at this level and continue to achieve these growth rates.

One of the things that Doug talked about at the beginning just before Q&A are the things on which this Company is focused.

And pricing differentials in the short term around a cool summer and waiting some long-haul takeaway in the Northeast, don't impact the way we think about those targets and our ability to achieve them.

I think just adding to that, the idea of the competitive nature of capital allocation.

When you think about it a year ago, we probably couldn't run away out of there fast enough.

These are wells that we were excited about but generally weren't making money.

And now, when we look ahead to next year, we probably can't put enough capital there.

So, this is a process that drives competition among teams, and is very healthy for the Company and for our shareholders.

Yes, I think that the oil acquisition makes a lot of sense.

How many more of those type of, and that size of acquisitions do you think you can do as you look at the next couple years?

We'll be very focused on it, David.

As I noted in the prepared comments, we are presently evaluating a number of strategic initiatives, some of which we've discussed, and some we're working on that are in early stages.

The key for us going forward is that we execute on this financial discipline and look for differential ways to add value to our shareholders.

So, I think it's important to note that while we are not providing any color on any specifics of any other transaction today, that the Company is looking at other opportunities, and will continue to look for other opportunities where we can enhance those returns and get away from some of those high differentials volatility we see around the gas market, and continue to grow the Company.

And, Dave, I'll just jump back in here and, at the risk of restating the obvious, the financial position the Company finds itself in today where we can effectively stroke a check for that acquisition gets us pretty excited about looking at other opportunities.

We certainly are in a place now where we can think about our portfolio in the right way.

There's other things in our portfolio that need to be managed, and we've talked about some of those things.

We haven't highlighted all of them but there's a lot of portfolio optimization to do.

And in doing that, it's left us very flexible to go out and seek new opportunities.

So, we feel really good about where we stand in our ability to go out and execute on opportunities that we seek or that present themselves to us.

Yes, increase nets anywhere you can, guys.

That's a good deal.

All right, thanks, guys.

We agree.

Neal Dingmann, SunTrust.

Good morning, guys.

Doug, my first question, really, just to stay on differentials a little bit, I'm just wondering if you and Nick can either operationally or financially, are you trying to manage this around obviously the current weak NGL and natural gas prices in near term, maybe through perhaps some new rig locations.

Or if Nick's looking at hedges.

Or is this just something that you think is temporary, we just have the ebb and flow of the seasons, and return as we normally do in the winter?

Sure.

Great question, Neal.

I think it's really good to highlight, based on your question, the fact that we've built considerable flexibility into our program.

Reacting to current market conditions and providing competitive metrics versus our peers is what our focus is all about.

And as we've said a number of times, how we highlight or how we grow value for our shareholders based on that flexibility we've built into our capital program.

So, when you look at the present dynamic that's taken place, we anticipate that we'll see an improved realization as we go into the winter.

But the key for us really, Neal, is we are not running the Company based on any particular forecast on gas or oil prices.

We're going to run this Company on good, prudent operations and sound financial discipline.

That nuts-and-bolts approach with the quality of our assets and the talent of our employees will pay off for our shareholders as we pursue this low-cost leadership and greater capital efficiency.

So, yes, we will look at opportunities for hedging to protect our cash flows, not on a speculative basis but on capital preservation or ensure our capital program can be executed upon to provide that growth in competitive metrics.

But we have to be competitive regardless of what the gas prices are, and that's exactly what we're going to do.

Makes a lot of sense.

And then building on that, just looking at obviously your slides, it's pretty clear that you guys have some of the dominant acreage positions if I look in the Eagle Ford and around some of the Utica.

So, my question around this is, are you continuing to do some trades blocking this up?

You certainly have cut, obviously, just what you're spending in leases overall but is there still a bunch of this going on?

Or how do you look at that on the acreage side?

I think there's significant opportunities for coring up in our high-quality assets in the areas that we see future growth from.

And when I say coring up, that may be increasing our net interest.

It might be bolt-on acquisitions.

It might be infill acreage in the areas that we see to have the greatest potential and opportunities.

So, I think you can expect to see a continued focus on that for the Company.

Okay.

And then just last one.

Just looking at dialing into the Utica -- probably a question for Chris -- just looking at slides 20 and 21.

And I know, as you all mentioned at the Analyst Day talking about being the most efficient.

And you guys do a good job of showing what you're spending per lateral foot.

But maybe just walk me through on slide 20.

I know you have brought out now on this slide a number of and some of your newer dry gas wells.

And obviously the headlines we hear are from some of the peers a little bit further south, some of these big numbers.

So, Chris, what I'm looking at is just maybe how you're looking at that, how much lower?

Like some of those in the South, I think, are costing $10 million or $12 million per well.

So I'm just trying to get a sense of how much yours are costing.

If they're obviously coming in a little bit less how much less is the cost behind those.

Right.

That's a good question, Neal.

I wouldn't say that we have a large enough sample set when we look at our position in the dry gas Utica and West Virginia to give you an affirmative answer.

All I can tell you is that, while we have established ourselves as cost leaders in the rest of the Utica play, I'm very confident that we'll continue to do that in West Virginia.

Obviously, these wells are going to be more expensive, they're a little bit deeper.

Some may require an additional casing string, and that's fine.

But I'll put my chips behind, again, what I think is a really strong operations team.

What we tried to highlight on slide 20, some of those 30 million a day IPs, is really just to get a sense of what we're expecting as we cross the river into West Virginia.

And just to reiterate what I mentioned earlier in the call, we are very excited about what we saw in the Wetzel County Messenger well.

And really excited to get that online.

And excited to further delineate as we approach the end of the year up into the panhandle, and really unlock significant value for our shareholders with dry gas tests in West Virginia.

Chris, are you drilling -- and then, lastly - are you drilling anything even further south than Wetzel anytime soon?

I'd have to check and get back with you on that, Neal.

I don't believe so.

When we look at -- ultimately we will but when we look at where we are focusing it's probably Wetzel County North into the panhandle, just where the concentration of our acreage is.

But we'll definitely continue to push not only a little bit south but also further east.

Makes a lot of sense.

Thank you all.

Charles Meade, Johnson Rice.

Good morning, everyone.

If I could ask a question about the Northern Marcellus, that you guys have a slide in your presentation you put out today that talks about the new completion design.

And it looks like it's giving you pretty attractive non-existent decline.

I'm wondering if you could talk about what you're doing differently, and maybe where you're doing that, and if that's perhaps a function of where geographically it is.

Like I know that Wyoming County is relatively untested but highly prospective.

And just give us a sense of how applicable across the whole position this kind of completion might be.

Sure.

This is Chris Doyle again.

It is very applicable across the entire position, not just in the Marcellus but we see it across the entire North and Southern division, the entire Company.

What we're doing here is optimizing the value equation.

What that means in the Northern Marcellus and the slide that you're pointing to is additional sand being pumped, stage spacing being contracted, pumping more efficient completion design.

It cost us about an initial $1 million but results in over a Bcf of incremental production, as this example alludes to, in the first year.

The key point of this slide is that these two wells are in the same exact area.

This is not a difference of being in a core area versus a non-core area.

These are two core wells in the same exact area and the only difference is really the completion.

And, so, we get real excited, as I'm sure you would be, seeing the results here.

And we'll continue to push more and more sand, tighter spacing, not only here but in the other assets, as well.

In the Northern Marcellus, what that has allowed us to do is keep production flat.

And we're running four rigs right now.

And I would say going into the year we would have projected probably running about six or seven, but that completion optimization, the capital efficiency gains that we've seen in the first half of the year gives us clarity to reduce rig count there.

And, so, we are excited about that.

Got it, Chris.

And that's good detail.

And just to clarify, so these wells are both producing against the same gathering pressure with the same compressions and all that other stuff?

Same system.

Same area.

Got it.

Thank you.

And then transitioning over to the Powder River Basin, I know going back 18 or 18-plus months ago, one of the big constraints was takeaway.

I guess it's processing it, but also just oil takeaway.

And I know that you guys said that you expect a gas processing plant to come on in Q4 that's going to give you guys a boost there.

But can you talk more generally about what other above-ground bottlenecks you might be dealing with there, whether it's on the processing or permitting side?

Sure.

Our biggest constraint right now is gas processing, as you allude to.

And Buckinghorse coming on at the end of the year is going to open that up.

That's 120 million a day that we anticipate being online at the end of the year.

Continue to be excited as we see that capacity expand.

We will build into that capacity and probably hit capacity at Buckinghorse in the first early second quarter of 2015, and then continue to go into the Tallgrass capacity we currently have.

That's our biggest surface production constraint.

You allude to permitting, and I've gotten a lot of questions about how quickly can you ramp up with permitting issues in Wyoming.

I can tell you this Company and this team has a lot of history dealing with longer protracted permitting timing.

And it's something we work into our plans.

And, so, you won't see us go to 30 rigs next month.

What you'll see is a nice steady build towards the end of the year and into 2015 as we fill up capacity and get that permit machine rolling.

So, you hit on, I would say, two of the above-ground pressure points that we're attacking aggressively all over.

Great.

Thanks for the detail.

(Operator Instructions)

Jason Wangler, Wunderlich Securities.

Good morning, guys.

Up in the Utica or even Southwest Marcellus, is there an ability to try and get some of that gas out of the basin?

I know some other operators are starting to look at pushing it to Midcon or Gulf Coast.

Just your thoughts around that opportunity, if there is any.

Yes, we are looking at some of those opportunities.

We've had a number of good conversations with the takeaway partners, looking at building new projects out of the basin.

Those are all pretty active discussions.

So I'll leave it at just saying that we're looking at ways to further increase our takeaway to other parts of the country.

Okay.

And then, just curious, in the Utica, as you are looking at the reemergence of the different windows, if you will, you've got eight rigs up there now.

How do you see that rig count as far as just within that?

Is that mostly just in the condensate or wet gas area?

And then anything in the dry gas or even oil would be incremental, at least in the near-term or maybe into 2015?

I think that's a fair way to look at it.

As we look at the pace of our drilling activity up there, one thing that is just absolutely critical to the Company is we're not going to park capital in the ground and not get a cash-on-cash return as quick as possible.

And so, strategically, as we look at our capital allocation, the areas where we can ramp up rigs and be flexible in our program and capture the greatest returns is where we're going to be focused, versus parking capital in the ground and waiting for infrastructure in six months or a year or longer to allow us to sell our products.

We'll be continuing to drill in the gas and wet windows, and doing some of our limited testing to prove up the other areas, and, as Nick noted, looking for opportunities to secure additional takeaway as we see the economics support it.

The only thing I would add there -- this is Chris Doyle -- Is we will be seven to nine rigs next year.

But, in effect, what we'll be doing is adding more wells because of continued cycle time reductions.

Point two, what they've been able to accomplish in the Utica but also App North.

This is an area that we have drilled going into this year 800 wells.

And year to date we've seen a 20% reduction in cycle times.

What that means is I can peel a rig back and effectively have not lost any delivery of this asset.

And, so, we'll think more in terms of well delivery than we will rigs.

And it's one of the great value drivers for this Company as we continue to see those cycle times come down.

I appreciate it, guys.

Thank you.

Matt Portillo, Tudor Pickering Holt.

Good morning, guys.

Just two quick questions for me.

I wanted to ask first on the completion side, particularly in the Eagle Ford, I was wondering if you could provide maybe a little bit of color on where you are in completion optimization, and how you think about industry moving towards bigger proppant, longer laterals and tighter stages, and the opportunity set you guys see on your Eagle Ford assets.

It's something -- this is Jason -- we are looking at that all across the Company.

We've got a completions team that we've spun off as part of our transformation initiatives.

We were looking at it.

They've got 50 initiatives as far as completions going on across the Company.

We're very excited about it.

So, all of the things that you mentioned we are in the process of testing right now.

We've really seen some high cost leadership from that team.

They've been able to drive costs down in every single asset that we operate, with the Eagle Ford being no exception.

At our Analyst Day we highlighted $6.4 million wells were our year-end target, but they're already achieving that today.

So very excited at the progress they're going to make.

Another big change for us as we transition to some of these interventionless completions, these are slide-in sleeves, dissolvable plug systems that we've tested in the Haynesville successfully.

We're going to be moving those to the Eagle Ford.

Those systems are safer, faster, and cheaper for us.

So, very excited to tell you about the results in the Eagle Ford as we progress those systems moving forward.

We've also tried, similar to they have, in the North - we've been very successful.

Tighter proof cluster, spacing test, more sand.

Some of our cost savings have come from reducing the amount of gel and being able to get the same proppant concentrations away with water.

So we're really expecting to make some big moves on our completion cost side in the Eagle Ford going forward.

We're also going to be testing some 330-foot spacing tests out there.

Those will be going down in the third and fourth quarter that can hopefully optimize the ultimate recovery from our asset in the future, as well.

So, lots of great things going on in the Eagle Ford overall.

Great.

And just specifically to the Eagle Ford, we've seen recently, particularly in an area where you guys are developing pretty significant increases in the amount of sand content in the well, is that something you guys are testing at the moment?

And is there any context you could just provide as to where you are today on a proppant per foot or proppant per stage perspective, and maybe where that could trend to?

I do not have the pounds per foot with me right now.

But it's something that, as you go to these increased density clusters, we're not diluting our sand over that interval.

So, by testing tighter intervals, we by default pump more sand and more fluid into a well.

We are testing up to 20% to 50% increases in some of our sand out there.

It's really just looking at maximizing the NPV.

These tests cost you more money so do you get incremental EUR from them?

Those are the things we're looking at and they just take time to really see the impact in EUR.

But we have observed some of our offset operators are pumping more sand out there.

But we've got a system that works for us; we're just looking to tweak it.

Great.

Last question for me, just on the completion front you mentioned accelerating completions into the back half of 2014 by 35%, or wells online.

Could you give us some context of where those will primarily be?

Is that primarily in the Utica and the Eagle Ford?

Just any incremental color you could provide on those completion accelerations.

Sure, Matt.

That's principally the main areas.

Utica is a big component of it.

Eagle Ford, as well.

But really across the whole portfolio, our focus and drive towards capturing greater value is just consistent with all of our planning.

The other area I'd mention is the Powder where we strategically deferred some completions in the first half of the year because of weather and because of capacity constraints.

We are back at it right now and completing wells and accelerating completions in the second half of this year as we get ready for Buckinghorse at the end of this year.

Thank you.

Doug Leggett, Bank of America Merrill Lynch.

Thanks.

Good morning, everybody.

I apologize, I was a little late jumping on the call, Doug, so maybe I missed a couple of these things.

My question is on the portfolio simplification, to kick us off here.

The asset sales that you've announced on the outlay of the Utica preferred balance, I guess, if you add it up.

And I'm just wondering, is that how we should think about this simplification effort going forward that's going to be self-funding, if you like?

And where would you say we are in that process in terms of getting where you want the portfolio to be?

And I've got a follow-up, please.

Sure, Doug.

It's a good question.

We've covered a lot of ground in the past 18 months.

And as Nick noted, we've had a significant number of asset sales or non-core divestiture.

As we look forward into the remainder of 2014 I see a number of other opportunities that we'll be looking to execute upon, and there'll be some in 2015, as well.

And the key there is really that we're going to continue to mold and shape and optimize this portfolio around what I consider to be some of the absolute highest quality assets in the United States.

And as we look for core up opportunities or divesting of non-core affiliates, or things that we're not getting competitive returns on, you can absolutely expect to see more of it.

And we've got other things that we presently are evaluating and looking at for 2014.

As part of that process, Doug, I know it's a long time ago since we talked about debt targets, but are you comfortable with where the balance sheet is now, or do you see any urgency in bringing that down?

I'm not so much thinking about the credit issues and so on.

I'm thinking more just about the interest rate burden that you have relative to the rest of the operating cash flow generally.

So what's your priority to try to bring the debt down?

Yes.

Doug, you know that I'm a huge capital efficiency guy.

And you know that I'm a huge cash cost leadership guy.

And part of that whole cash situation with the balance sheet, where we have obligations that consume our cash flow, or consume cash, we are focused on continuing to improve.

And when you look at the portfolio, when you look at our product mix, I'm not happy with where we are, and we're going to continue to make improvements to it.

As you noted, it's not specifically that we are targeting investment grade.

Investment grade is a byproduct of running our business right.

And, so, we expect to reach investment grade because we're going to clean up the excessive debt that can be a burden on our capital program in high price environments or low price environments.

But the financial stability of the Company, as Nick had noted, we are in a position today of really very good strength.

And it creates optionality for when we can either pay off debt, pay off other obligations, and continue to mold and improve the portfolio to capture the greatest value we can from these high-quality assets.

Appreciate the answer, Doug.

My last one is hopefully a very quick one.

Over the course of the last year, and particularly the last six months, we've seen a number of your competitors talk about signing long-term gas contracts, or at least signing up for that.

The most recent one, which was a little bit of a surprise, was Southwestern in the Fayetteville.

They didn't disclose details but they did say they had signed a contract for LNG.

Where are you guys in that?

And obviously how would it impact your Haynesville, assuming the back end of the curve did come up in this one for that?

And I will leave it there.

Thanks.

That's a good question as well.

I think if I were a purchaser of LNG I'd want to go to a company that had the best assets in the country, and that's Chesapeake.

And so, for long term deliverability and capturing the greatest price opportunities for our gas, we will continue to look at opportunities to secure LNG contracts at pricing that we would consider to be favorable.

And we've not signed anything yet but we have had a number of discussions and will continue to discuss with those purchasers about offtake capacity from the new liquefaction facilities being built on the Gulf Coast.

And there's a direct line of sight to the Haynesville.

And part of the reason we went into the Haynesville is we believed -- or went back to the Haynesville, rather -- is we believed that huge value in that asset hadn't been captured.

And applying the teams the way they are reducing costs and adding value there is significant.

And there was a second part of that, that we also believe that competitiveness of the asset would be a fantastic source for LNG purchasers if we could be more competitive.

So, we're recognizing that and seeing outstanding results in the Haynesville.

That team is doing a fantastic job.

And we are in a great position to move forward, provided we capture the value from an LNG contract or any other sales contract that we might pursue.

Appreciate it, Doug.

Thank you.

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

At this time I will turn the conference back to our speakers for any additional remarks.

Thank you very much.

We appreciate everyone's time.

Just to encourage, if there are subsequent follow-up questions please contact Gary.

And what you can expect with a company like Chesapeake is we will continue to drive towards greater value.

And just want to reiterate one more time the year-end exit growth rate of 730,000 barrels equivalent per day is a very realistic expectation for us.

We're really excited about our program.

So, thanks, everyone.

This concludes today's conference.

Thank you for your participation.