Chesapeake Energy Corp (CHK) 2015 Q3 法說會逐字稿

Good day and welcome to the Chesapeake Energy Corporation Q3 2015 conference call.

Today's conferences is being recorded.

At this time, I'd like to turn the conference over to Mr. Brad Sylvester.

Please go ahead, sir.

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

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 Nick for a review of our financial results, before we turn the teleconference over for Q&A.

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

Thank you, Brad, and good morning.

Our results in the third quarter provide good solid evidence that we continue to execute on our strategy of improving margins, maximizing liquidity in this low price environment, preserving our cash generating capabilities and improving our core strengths of capital efficiency, speed and flexibility.

During the quarter, we have advanced several organization and operational initiatives to further prepare Chesapeake for an extended low commodity price environment.

We continue to see market efficiency improvements across the portfolio and we are pursuing new value-adding opportunities.

As previously announced, we have taken action in the third quarter to make our Company stronger and we will continue to focus on improving our financial and operational competitiveness.

Here are just a few highlights from the quarter.

We executed new gathering agreements in the Haynesville and dry gas Utica which have dramatically improved the value of these two assets.

We secured an amended revolving credit facility which has provided a significant increase in our financial flexibility.

We eliminated our common stock dividend and also eliminated drilling and financial commitments resulting from the sale of our Cleveland and Tonkawa subsidiary, both of which have added cash back to the Company.

We continue to reduce controllable costs and eliminated approximately $200 million of annual production in G&A costs from our cost structure.

We signed or are in the process of signing several sale agreements for non-core, non-operated assets.

And finally, we achieved several operational records and accomplishments in the field, including meaningful progress in new resources like the Meramec, the Upper Marcellus and the black wall Niobrara.

Moving to our quarterly performance, our daily production averaged 667,000 barrels of oil equivalent per day, which after adjusting for asset sales, is a 3% increase year over year.

This includes the impact of Utica and Marcellus curtailments of approximately 51,000 barrels of oil equivalent per day and the sale of our Cleveland Tonkawa assets of approximately 8,000 barrels of oil equivalent per day.

As a result of our continued strong production performance and base optimization, we have raised our guidance for the full year.

Importantly, we continue to drive cash cost reductions on an absolute and per unit basis.

Third quarter lease operating expenses and G&A costs were $4.88 per barrel of oil equivalent, down approximately 9% year over year and down 10% sequentially.

We have lowered our guidance again for these two categories for the remainder of 2015.

Additionally, we have reduced our full year CapEx guidance by $100 million to a range of $3.4 billion to $3.9 billion.

Due to greater capital efficiency and expected low prices, we intend to meaningfully reduce our capital spending in 2016.

As I've noted before, we recognized the challenging nature of our balance sheet and we are firmly focused on improving our financial strength during this difficult commodity price environment.

The quality and diversity of our portfolio will continue to provide flexibility and optionality.

I'd like to touch on a few of our operational highlights for the quarter.

We continue to focus on improving completion efficiency as a value differentiator at Chesapeake, as measured through finding and development costs.

We are attacking our capital costs in a numerator and with technology and innovation.

We are making significant improvements in the recoverable reserves per well in the denominator, and also the associated productivity per well.

We are drilling faster and cheaper, drilling longer laterals and enhancing our completion techniques to drive further value from each investment.

In the Eagle Ford, we expect to see approximately 9% production growth this year compared to 2014, with approximately 45% lower capital investment.

Compared to last year, we have seen a 13% reduction in drilling cost per lateral foot and a 8% reduction in cycle time, despite a 7% increase in average lateral length.

We currently have 19 wells drilled with greater than 9,000-foot laterals including two record 13,000 foot laterals.

We also put our three highest rate wells online in the third quarter, each reaching peak production rates of over 1,000 barrels of oil per day.

In the Mid-Continent area, an asset that I consider to be one of the most undervalued assets in our portfolio, we have drilled our first two wells in the Meramec and are drilling a third.

We drilled our first Meramec well in 27 days and our second in 18 days.

Our first well has been on production for just a few days and still cleaning up.

However, it's already reached over 870 barrels of oil per day and is still climbing.

We are obviously encouraged by the early results of this well and our second well will be placed on production later this month.

With over 1.8 million net acres in the STACK area in Oklahoma, we estimate that we have more than 1,200 future locations to be drilled in the Meramec and the Oswego formations.

Not to mention also the exposure to many other prolific oil horizons in the area.

So expect to hear more from our Mid-Continent plans and performance in the future.

Moving to the Northern Division.

In the Upper Marcellus, we completed two test wells in Southern Bradford County.

These two Upper Marcellus wells achieved peak production rates of approximately 19 and 17 million cubic feet per day.

This performance is highly competitive and we believe this opens up the potential for over 1,000 Upper Marcellus locations, previously uncaptured in our portfolio.

Because most of our acreage in this area is currently held by production, we have development and timing flexibility.

The Powder River Basin asset has progressed dramatically in the past year and our estimate of recoverable resources there, it continues to expand.

In October, we placed a black oil Niobrara well on production that reached 1,500 barrels of oil equivalent per day with 85% an oil cut and 43 degree API gravity.

This test is significant proof of the concept and validates the great work that our teams have been doing to add value to our shareholders in this asset.

Overall, I'm pleased with our progress but we still have a long way to go, and significant value-add opportunities to capture.

The strength of our portfolio offers great diversity in a resource base that is growing in size due to the improved productivity and capital efficiencies that we are seeing every day.

As I've said before, and I'll continue to say, we are not done.

We will continue to deliver and we will continue to improve our value proposition.

I'll now pass the call to Nick for a review of our balance sheet and liquidity and then we'll open the call for questions.

Thank you, Doug, and good morning, everyone.

As Doug mentioned, we've done a lot in the past quarter to strengthen our liquidity and enhance our financial flexibility and we continue to see significant progress in many of the areas within our control.

Our production, CapEx and cash flow outperformed expectations for the quarter as we continue to see operational efficiency, and capital efficiency deliver strong results on our reduced capital program.

We finished the quarter with over $1.7 billion in cash and an undrawn credit facility, with capacity of $4 billion at September 30.

The amendment to our revolving credit facility at the end of September was an important step in securing and enhancing our liquidity through the term of the facility in 2019.

Shoring up of this important liquidity and the methodical progress we are making towards selling non-core assets gives us confidence to fund the required tender on our 2035 convertible debt this month with cash on hand.

Given the continued volatility in the market due to commodity prices, and the better clarity around our forward liquidity position, we have been happy to be patient when it comes to any assets we evaluate for sale.

However, we are making solid progress on the sale of non-core, non-operated positions where we are in the process of contracting several deals that we believe will bring in $200 million to $300 million between the fourth quarter of this year and the first quarter of 2016.

This does not include some potential larger asset sales that we are evaluating.

As we enter 2016, our liquidity and cash flow generation are of utmost importance.

We are committed to preserving that liquidity and driving stronger cash flows every day, focusing on both the cost side and the revenue side.

We have added meaningful gas and oil hedges for 2016 when the market has provided opportunities to do so.

We structured the amendment to our revolving credit facility, assuming no asset sales and low commodity prices, giving us confidence in our ability to remain flexible throughout the year.

As such, cash provided from any asset sales or higher prices can be invested in our balance sheet, or our business in the way that creates the most shareholder value.

Our strong and flexible portfolio and our people, who are relentlessly driving for better solutions, will both help us to weather this tough commodity price environment.

That concludes my comments so I will now turn the call over to the operator for questions.

Thank you.

At this time, we will start the question-and-answer session.

(Operator Instructions)

We'll take our first question from Doug Leggate with Bank of America-Merrill Lynch.

Mr. Leggate, your line is open.

Please check your mute function, sir.

Okay.

We'll go to our next question from Neal Dingmann with SunTrust.

Good morning, guys.

Say -- quick question, Doug, first, on this STACK.

Obviously, the first well at 870 barrels of oil equivalent per day after the three days looks quite good.

How do you see that cleaning up over the next few weeks and, again, I guess you guys have identified a lot of that area.

If you could talk about potential acreage after seeing that first well and now drilling your third, how big a position you have in that area.

You bet, Neal.

I think I'll let Jason provide just a little bit more color but I'll make a few comments, just high level.

What's really exciting to us is this large acreage position and the capital efficiencies that Chesapeake continues to drive in all of our operations gives us the position to continue to expand core opportunities and really good investments in the STACK.

And so I'm very pleased and we expect that well to continue to clean up.

But what I also really am excited about is when you see the strength of Chesapeake's operating performance driving those days down, drill and complete on the well.

And you -- we'll continue to see improvements there, you can expect to see continued successive capital efficiency and productivity gains from this asset.

I'd just really highlight that I think Chesapeake's position in the STACK continues to be our most undervalued asset.

Jason, if you want to kick in there, I'd appreciate it.

Yes, again, with only three days and this well is drilled with the farthest north part -- or inner part of the Meramec, so I think that makes it additionally encouraging to me.

The flowback that we've seen have been fairly flat in their production rate for the first month.

Again, this well is flowing at 1,000 psi.

We put a tracer on the very first stage of the frac and we have not seen that tracer chemical come back yet.

So we haven't seen all the well bore yet but it's been fairly flat for the first few days and it's in the inner part of the play.

The second well that we're drilling, or about to turn online here in the next couple weeks, is in a much thicker part of the play and the pressure from the drilling out the plugs has been very positive as well.

So it should surpass even this first well.

As Doug mentioned, our drilling and completion efficiency have really been what's outstanding there.

This first well came in 23.5 days.

Current estimates for that well are $7.4 million.

So we did a really good job out the gate.

On the second well via the help of our operations support team and a fantastic drilling group, the second well was at 18 days.

It was $500,000 savings on drilling alone which could put this well in that $6.9 million range, which based on some of the peers that I've looked at their data, this is kind of industry-leading cost for a 10,000-foot well.

So we're really excited about it.

We're also taking a core on this third well.

I think they're just about finished taking the core on that.

One of the advantages of Chesapeake is having a drill core lab across the street so we should be able to get a lot of our data back from that which will help us in the future with spacing and staggered laterals and really the development of the field.

Combined, again, we -- our STACK is a little bit different than others.

I consider the STACK the Miss.

Lime, Oswego, and the Meramec here.

So together those are -- almost got a almost 400,000-acre position between those three formations.

We didn't mention it, I think, in our notes but we have drilled our first two 10,000-foot wells in the Miss Lime as well.

Those two wells came in for an incremental $200,000 of drilling.

So those economics will be competitive with Meramec, Oswego or any other formation that's out there.

That one 10,000-foot well saves $1.4 million versus drilling two of our traditional 5,000-foot intervals.

That well is also being completed and should have production online but it saves 35% on our cost to develop that field if those finds are successful.

So we're really excited about all the formation.

It's not officially the STACK but we've got that STACK interval play out there that just has three powerhouse formations that all have great economics.

Very good, and then Doug, just one if I could.

How do you all think -- you've obviously done a tremendous job on shoring up your liquidity position.

But how do you think about with where gas prices currently are, how you see your spending next year?

Maybe if you could talk a little about any potential outspend or how you see that going next year?

Sure, Neal.

It's a great question and I think a very important question for Chesapeake, particularly given our balance sheet and we are not providing any capital guidance today for next year.

But I just would like to highlight that the flexibility and the options we have in our portfolio give us a lot of strength and as we look next year, I wanted to make sure to note on this call that we are looking to meaningfully reduce our capital next year.

Gas prices obviously being lower, you look at the strip, you see some recovery.

But we're not designing this business, Neal, around increasing prices.

And so the drive for efficiencies, the quality of the rock, the quality of these assets, we have got to find a way to be competitive and I can assure you that the capital spend and investment next year will be directed at how we can capture from the strong portfolio the greatest value.

And with our program, we have significantly ramped down our activity.

We've continued to take it down and as we look forward to 2016 we'll maintain that flexibility to make further adjustments, based on prices, based on capital efficiency and based on performance.

You can expect we'll be providing that guidance a little bit later but the focus on capital efficiency and the focus on directing capital investments either to gas or oil will be where we can capture the greatest value.

Great.

Thanks for the details.

Nice quarter.

We'll go to our next question from Brian Singer with Goldman Sachs.

Thank you.

Good morning.

Hey, Brian.

Your mindset a quarter ago may have been characterized as Chesapeake needs to sell assets to increase activity levels to maintain or improve efficiencies.

It seems like you moderated the tone a bit on activity levels for next year and you mentioned $200 million to $300 million of asset sales but wondered if you could just characterize, A, the extent of asset sales that we should expect, and B, how that would translate into activity levels and further efficiencies versus the strong reduction in, say upcosts, that we've seen now this quarter?

Sure, Brian.

As you look at the commodity price environment, you look at the opportunities that we have going forward, our focus is still the same and that is if we can accelerate the value from an asset sale, we will do that and we're looking at many different opportunities with that respect.

What I think is really important to note is we're not dependent upon an asset sale in any way and if we can capture and accelerate value, we will do that.

But we don't have to perform the asset sales.

We want to make sure to note that we have a number of underlying non-core things that are moving through and we expect to close on, as Nick highlighted.

But this environment and how we drive greater value from a large portfolio is something that we believe we still have opportunity to bring forward greater value.

So we'll continue to look at asset sales but our position is the same in that we are not dependent upon asset sales.

If we do sell something, we've got a lot of options.

We could put it, direct it towards the assets and invest in our program or we can also attack the capital structure that we have highlighted that we will continue to improve.

So Nick, you want to ride -- add any update to that?

Yes, so we've talked quite a bit earlier this year about our desire to sell non-core assets.

We've tested the market around a few things there.

Like we said today, we have visibility into a few things that are moving forward, relatively small at this point and we're, again, happy to be patient on that front because we do have the operational flexibility to take capital lower.

But really what's, I think, driving things more than anything at this point that is our capital going lower for next year is driven more by commodity prices than it is by whether or not we're sell an asset.

We're going to invest in our properties the way that we think is the most prudent.

Right now, if I turned around tomorrow and found that we were selling a large asset for a lot of money, it's not really going to change our capital plans in the near term.

It might give us flexibility to think about things differently over a longer period of time or something like that.

But the short term, as we get into most of 2016 here, we see prices at a level that encourage us to be pretty low capital investment and allow the market to continue to heal itself.

And so we're setting up our programs such that if asset sales surprise to the upside, we'll be able to look at our balance sheet, try to do things that make the most sense for the long-term health of the business and depending on how things unfold for next year, it could change.

That means we would ramp capital but it may not.

We have some challenges with our balance sheet, as everyone is well aware, that we focus on every day.

And we've made some progress there and we'll continue to make more.

One of the things that we look at is with our maturity here, the put on the converts in November, this modest amount of non-core asset sales and the cost reductions that we have in front of us that are real cash on cash reductions allow us to fund that.

And so we end up in a cash position across a couple quarters that's the same as we were planning to be earlier this year when you might have thought that, that was a piece of debt that you would refinance.

So instead, we'll retire that completely and we'll move on with the same liquidity position.

So we feel really good about that and we feel really good about the ability to be patient, the ability to look at our capital program and say what's driving lower capital spend as prices and we're making the right decisions for long-term value creation.

Thanks.

That's really helpful color.

One follow-up asset level type questions.

Couple quick ones there.

One, on STACK, you've highlighted this now a couple times as a really underappreciated asset.

Is STACK now strategic to Chesapeake from a development perspective, as a retained asset or is this a candidate for asset sale?

And then in the Utica, you highlighted in the release an additional $350 million of new capacity, allowing access to Gulf Coast pricing.

Should we expect that your Utica production goes up by that amount or just you take gas currently, getting lower prices and get higher prices on that gas?

Thank you.

Sure, Brian.

I think you should consider that the STACK is a highly strategic asset to Chesapeake and as Jason noted, we've got great optionality there and a lot of excitement and energy around it.

And with respect to the Utica, this is a powerhouse asset within our portfolio and having that additional capacity gives us a significant amount of flexibility.

I think what's important to note there is that we are not activity driven.

We are not volume driven.

We are value driven.

And so what we direct our investments and how we fund, whether it be the STACK or whether it be Utica, is all directed at how we optimize the greatest value.

Brian, this is Chris Doyle.

Just a little additional color on the Utica to answer your question.

The $350 million was the planned open expansion.

It's online.

We're building out a lateral to connect our gas.

What we saw in the third quarter, and what you saw in our results of 15% sequential decline, that was a planned decline curtailment.

We brought that gas back on for a number of reasons.

One, to access the Gulf Coast; part of our plan to get 80%- plus of our gas to that pricing.

That's now in place.

The other thing is seasonal NGL pricing that we see flip October 1. We've brought most of that gas back on.

We've -- actually that asset set production records last week and continue just to hit it out of the park.

Thank you.

Thanks Brian.

We'll go next to Doug Leggate with Merrill Lynch.

Thanks everyone.

Can you hear me?

Yes, sure.

I'm so sorry, guys.

It was some kind of phone gremlin this morning.

I'm quite embarrassed.

Doug, if I may just prod a little bit on your comments about capital expenditures.

I realize you're still some way away from giving us the guidance for next year but can you frame for us how you see the areas that you're prepared to flex?

Clearly, the opportunity set is getting a lot broader with the STACK and the Powder River.

But just order of magnitude, what are the moving parts that you see that's going to drive your decision for how -- where you want to be next year relative to cash flow?

Sure, Doug.

The -- as we look at the commodity prices and project through the year, I think it's really important that investment community know that we are not counting on price recovery.

We are not structuring our investments.

We are not structuring our focus on our balance sheet or any part of our business expecting recovery.

That said, that means we're going to see meaningful reduction in our capital program next year.

What I love about this Company and I'm so energized about is that despite that, the technology, the focus on improving our cost, the competitive tension within the organization for capital funding, I just would love for you to have the opportunity to see as we work through our portfolio the tension and the competitiveness for where the next dollar of spend would potentially go.

With the Meramec and the emerging opportunities that we see there, the quality of the Sussex and Niobrara opportunities that exist, as well as the Eagle Ford and as well as the continued reductions in the -- on the gas side, we have significant opportunities.

And I think that's why it's key to note that as we look at -- for the near and longer term, why we would consider looking at asset sales, not depending on asset sales.

But if there's an opportunity to accelerate value there given the fact that with this large portfolio, some things may not be funded for some period of time, we will look at that.

But that isn't a commitment to do it and it's all the value focus.

So we'll provide that detail to you and as I've noted, it's just the quality of the portfolio, this is not a one-trick pony outfit and not a two trick.

We've got six really, really strong powerful assets and that provides us a lot of flexibility.

Appreciate the answer, Doug.

My follow-up is, also if I may, on the STACK and the Powder.

You've talked obviously a little bit about potential asset sales this morning but you haven't talked much about potential joint ventures.

One could be forgiven for thinking these well results this morning at a terrific guide rope for the quality of your assets.

I'm just curious to whether there's any joint venture progress coming on the back of that.

And I'll leave it there.

Thanks.

Sure.

The -- we consider the JV to fall under the same umbrella, Doug, as an asset sale.

So that opportunity exists as well across the portfolio on anything that we would want to accelerate, under the -- improve the underlying cash flow ability and direct JV type dollars to.

So I would just consider that the same as an asset sale that we see option and opportunity in that.

Great.

Thanks a lot, guys.

Hang on just a second, Doug.

Hi, Doug, I was just going to add a little bit of additional color on Powder for you.

The team just e-mailed me the latest test on the black oil.

It continues to clean up.

Yesterday, it made over 1,400 barrels of oil, over 1,600-barrel equivalent.

So we're really excited about that.

It's been about a month online.

You mentioned, that's a great advertisement for any type of deal, and while that's true, we're also saying that we're reducing activity there.

We pulled a rig out.

And there are a number of reasons why we do that.

One, it's response to low prices.

This acreage position is held.

I'm not real excited about selling into a market that is trying to tell us to slow down.

But finally, there's a lot of work that we need to get done on the Midstream side.

We've talked about the cooperative, renegotiation discussions we've had with Williams.

I'm really encouraged by what we're seeing out in the Rockies.

At the end of the day, the Niobrara is dedicated.

The Frontier is dedicated.

But what's not dedicated to Williams is the Sussex, the Parkman, the Teapot, the Turner, the Mowry and if it's $3 gas and $50 oil for a long time, our development dollars are going to go away from the Niobrara.

We've got some work to do and we'll get it fixed and we'll be back at it.

And really excited about what we continue to see out there.

Appreciate that color, Chris.

Just to check, your working interest in the Powder is about 80%; right?

That's correct.

We doubled up last year.

Great stuff.

Thanks very much.

We'll take our next question from Charles Meade with Johnson Rice.

Good morning, Doug, and to the rest of your team there.

I was wondering if I could pick up on some of the comments that Chris was offering a little while ago on those 51 MBoe a day that's curtailed right now.

More generally, I'd like to ask what are the -- I think the obvious answer to what would induce you to open those bottoms up is better price but if we could dig in a little deeper below that.

Are there more things like this change in marketing arrangement with the Utica volumes that are going to induce you to bring those -- that 51 MBoe a day back to market?

Yes, Charles.

This is Chris.

Just to clarify on the Utica where we saw in the third quarter, we were about 20 MBoe per day curtailed.

Decision there's was not only a little bit of a strength in the gas realization, partly because of the open capacity that is now available to us, but also the seasonal nature of the NGLs and our contracts that flip that switch and makes sense to bring those volumes on.

So we are not curtailed in the Utica at this point.

This is a daily conversation, weekly conversation that happens and we will respond to what the market's telling us.

But at this point in the Utica, we brought those volumes on to capture better NGL realizations and better gas realizations getting to the Gulf Coast.

Now, in the Marcellus, we still have about 500 million a day behind choke.

We pulled off all of our activity, or largely all of our activity.

We're excited about the resource.

Obviously, we highlight the Upper Marcellus.

But again, this is a daily, weekly conversation that happens.

We anticipate bringing some of that gas online in the fourth quarter but it's going to require higher gas prices.

We anticipate that will happen but we're not going to bring gas on just to hit a production number.

We're going to do it to bring up cash.

So I hope that adds a little bit of color to your question, Charles.

That does.

That's very helpful.

If I understand correctly, this is about in basing gas pricing.

There's no new marketing arrangement for Marcellus gas that is going to change the picture.

(multiple speakers) --

That's correct.

That's correct.

Okay, got it.

Thank you.

That's very helpful.

Nick, if I could go back to some of your comments which I agree, they're helpful, your discussion about how you guys are looking at 2016 CapEx.

But to go back to your prepared comments, you made a comment about investing in the business or the balance sheet.

And I'm curious if you could talk a bit, is there a certain target level of cash or perhaps -- I know you're focused on total liquidity but is there some kind of target level where you're trying to preserve optionality, like do you want to keep at least $500 million cash on the balance sheet absent some fabulous opportunity?

No, I don't really think about it in terms of there being some sort of Mendoza line there because we have a very sizable liquidity position.

Really, more I think about is we have a number of obligations with maturities coming due and other things like that, that we need to preserve liquidity to meet.

And in the meantime, we'll continue to look for additional ways to enhance the liquidity position that while sizable today, we're focused on its uses over time.

So there's not a magic number there.

I'd like to have more as the bottom line.

Got it.

Thank you, Nick.

I'm not a baseball fan so I had to Google that Mendoza line, but --

You knew it was a baseball reference, so there we go.

(laughter) No, I didn't even know that but anyway, thanks.

I appreciate the color, Nick.

We'll go to our next question from David Tameron with Wells Fargo.

Hi.

Thanks for all the color this morning.

Most of it's been answered.

But a couple -- one clarification and then one big picture.

Those slides you have which shows the breakeven for the PV10s, it looks like it's 50 and 3. Is that held flat and then as far as well costs and assumptions in there, those -- can you just talk about the math behind those?

Those current well costs, assume well costs targeted?

Those type of things?

Yes, this is Chris.

The color behind that slide is that's the opposing commodities is held flat whether it's $3 gas or $50 oil to find the breakeven.

That is deliverable well cost, what we are doing today.

And so this improves going forward.

In fact, I think on the Mid-Con STACK, that's an update from where we were previously.

So yes, these bars continue to move and these teams look at where that bar is and they beat the -- they are beating each other up for capital.

And it's a fantastic thing to watch.

That's helpful.

The easy work's obviously been done there.

What -- how much more do you have?

Could we anticipate in the current cost environment, everything drifts a little lower but there's another 5% to 10% in these type of numbers or how should we think about that?

I think for sure 5% to 10% just on operational improvements; no service costs decrease.

We've got now two, three years of track record showing continuous improvement.

We've taken a big chunk out of each one of these plays and I fully expect that we'll continue to do that.

That's why you see operational records continuing to be set quarter after quarter, drilling longer wells for faster.

The Utica averaging under 10 days for all the wells in the quarter.

Drilling a day -- a well in 6.8 days.

This is -- these are teams that are bred to get better every single day.

So 10%, 15%, I'd be shocked if we're not there within two quarters.

Maybe (multiple speakers) -- this is Jason.

At Meramec, for example, that curve was based on a $7.1 million well.

As I mentioned, our second well looks like it's a $6.9 million well.

But they'll continue to improve on that and take it down.

At Miss Lime, we're in the process of completing our first 10,000-foot well there.

We could have a whole rig line of wells to do next year.

That takes that curve down by 35% if that is a successful program.

There's some big things on the horizon.

Eagle Ford as well.

We're continuing to push longer laterals there.

Again, we highlighted our first well's over 12,000 feet with one over 13,000 feet.

I was looking back at what that meant to us.

2015 average drilling costs for Eagle Ford was -- I'm sorry, 2014 average cost was $6.1 million.

These two wells with laterals over 12,000 feet came in at $7.4 million and $7.1 million.

So we've had an increase of cost of 28% but increased our exposure to the reservoir by 100%.

So when you're doing those kind of things, they're transformational to those breakeven costs.

Okay.

That's good color.

Thanks.

And then I guess for Doug or Nick or whoever, and I'm not trying to be a jerk here but I'm going to ask the question.

So why not just tap the capital markets and issue some equity.

How -- I know what your answers have been in the past but can you just talk about that?

Sure, Dave.

We do sit with a large liquidity position.

We sit in an environment where we know we have a lot of operational flexibility.

We need to continue to evaluate things and think about the future and think about how things are going to evolve here and be planning for what everyone, I think, in the industry is planning for, which is lower prices for longer.

But there's so many things for us to do within our existing portfolio, within our balance sheet as it exists today that I just don't see where that's at the forefront for us.

I think just to add on top of that, the way we look at it, Dave, and I don't -- it doesn't -- the question is a good question.

When you look at Chesapeake and the strength of the Company and with the current commodity price environment and what's -- all of those options are available to us.

And we will continue to look at the options that can drive the greatest value for the long term.

And so that's just one option and we'll continue to evaluate our investments.

We'll continue to evaluate our investments.

We'll continue to evaluate our capital structure and we'll be what you can expect is we'll continue to be making changes to improve this great Company.

All right.

I appreciate the candidness.

That's all I've got.

Thanks.

We'll take our next question from Dan McSpirit with BMO Capital Markets.

Thank you.

Good morning.

Just a few questions on the STACK.

Appreciating that you're very early in the process of exploring and exploiting this asset.

But any thoughts, early thoughts on the potential recoveries as well as maybe the B factor or the shape of the curve, as well as the product mix, at least on these Meramec wells?

The Meramec wells have been highly oil weighted, 83% oil, what we've seen a lot of times.

Our type curve is kind of a 900-barrel of oil per day.

IP 600 days you're out to the 300-barrel or so per day.

So we'll be publishing more on our type curves out there.

But the data is just early across the field.

The really long-term estimates are difficult.

But looks, again, very economic, very competitive in the portfolio.

We're really excited about it and as I said, we've got our rig going there.

What's great about it too is just the continued cost reductions out there that really enhance the economics.

Okay.

Great.

And then on the asset sales, is there any one asset or operation that's not on the table to be monetized in one form or another?

Sorry, you're asking if there's anything that's not on the table to be sold?

That's right.

Well, I mean --

That's off limits.

We can talk about what assets are core and what assets we're investing money in and what assets we believe have the longest term horizon for attracting investment within our portfolio.

Those things move around as to what we think is top of the list and how we think about the long-term value of each of our assets.

With all of the things that Jason and Chris talk about on a regular basis, each time, they deliver a new set of results that's improved in one asset, it's going to improve its relative performance to another.

We sit in a position where we would like to sell some assets.

We are long assets and in this market, we don't believe shareholders are valuing us being long assets and for good reason.

So we would like to trim our portfolio but it has to be for good value.

And so while we don't get credit and like I said, probably shouldn't get credit for being long assets, we also should not put ourselves in a position where we take a really poor market and force a deal into it.

Capital markets are pretty tough right now.

The ability for other buyers to access funding, to buy large assets is pretty tough.

So we need to be patient.

We don't have a burning platform from which we need to sell an asset but we have an urgency and a need in our business to be getting our portfolio right for the long term.

So we continue to have discussions.

We continue to push on things.

But we don't find ourselves in a place where we have to force something into the market.

As to which assets are being considered for sale or not being considered for sale, we really don't go into that kind of detail but I guess the right way to answer that question and I think the way we think about those kinds of things or that we have a portfolio of assets and each one of them has a value.

And if anyone has a different view of value than I do of our assets, a higher view of value than our assets, for because they're going to develop it differently or whatever reason, then we'll be commercial and listen to them.

But that doesn't mean that we go out and actively shop things.

Okay.

Great.

I appreciate that.

Just revisiting the question on equity versus asset sales, do you anticipate the sales to be accretive, appreciating where the shares are trading?

Well, sure.

The few things that we're doing right now are very accretive.

It's very little production.

It's non-core.

It's non-operated.

It's a handful of transactions.

It's things that sit within the wheelhouse of other operators that we happen to own.

It's just a variety of things that drive what people want to buy from us, even given the market that we sit in today.

So yes, very accretive.

Okay.

Great.

Lastly here, just on the Eagle Ford, the inventory of wells waiting on completion maybe at the end of this year and next year that you can estimate?

We have 135 wells waiting to be completed at the end of this year and we're working through budget for next year, so that number will fluctuate as we go through the budget process.

Much appreciated.

Have a great day.

Thank you.

We'll take our next question from David Heikkinen with Heikkinen Energy Advisors.

Good morning, just a couple quick questions.

On the curtailment in the Utica, what was the split of condensate gas and NGLs?

It was pretty -- it was all coming from what we call the wet side so it's consistent with our overall split.

We're currently just on the ethane side, at about -- recovering a 20% hit the ATEX and get our gas into pipeline spec.

So we're -- it was heavily weighted to gas.

But it was consistent with the overall asset.

And then just in the STACK, good well results and you gave some details.

What's your working interest, I guess, on average in that 400,000 acres and then in those first couple wells?

The first well was 95% working interest.

We're starting to form units now so it's kind of hard to say what your average working interest will be over the development of the play.

We're working as we go.

The first few wells we put together are in the 90%s as far as working interest, so --

So you're having success doing asset swaps and kind of --

Yes, everybody's trying to kind of core up their position, maintain operation of those sections.

So we've been working together to everybody block up their position to maximize -- or minimize LOE expense and drilling, et cetera.

The real win there is if you can drill the 10,000-foot laterals and sometimes we're checkerboarded, et cetera.

Getting it together so that you can drill 10,000-foot wells are big wins for all the operators in the area.

Is there any issue with the OCC qualifying the Oswego, the Miss Lime as a shale for the cross-section laterals?

We're working on it.

The Oswego is thinner, so that's our technical debate we're having internally.

Is it thick enough to drill the 10,000-foot and be precise, as you get towards that toe area?

But we've challenged it -- we've gone to 10,000-foot laterals everywhere in the Southern Division and North is doing the same thing, drilling as long as they can.

So the preference is to push these things out as far as we can because it maximizes our efficiency of the drill bit, our LOE, minimizes surface footprint as well.

So it's a win for everybody when we can drill those cross-unit laterals.

That's great.

And then Nick, the cut to CapEx of $100 million, $50 million of that was capitalized interest.

So is the other $50 million going from seven rigs in the Haynesville down to six or where does the other $50 million of capital sit.

It's really just trimmed across the portfolio.

There's a few completions.

There's, like you said, the drop with the Haynesville rig.

There's a variety of small changes across the portfolio.

Okay.

That continues to come down and it will move lower in the first quarter.

(multiple speakers) Sequentially lower is what you guys have said --

Right.

So the point though there, Dave, is that it's sequentially lower, not just lower year over year.

Yes, okay.

Thank you guys.

Hi, Dave, just to follow-up on the -- when I look at our production through that time we were curtailing, it was about 15% to 20% NGLs, the rest gas.

Thanks, guys.

That's perfect.

We'll go to our next question from Dave Kistler from Simmons & Company.

Good morning, guys.

Just a few maybe clean-up questions.

With respect to the Spectra open line coming on, was the production that's flowing through that factored into the 4Q guidance and is that potentially what's driving a portion of the increase to the gas guidance?

The -- that was always forecasted.

It was forecasted in there after last quarter as well.

It - that line will be connected to our tailgate at Kensington this quarter.

We're taking advantage of it.

We've seen a little bit of strength in basin there in the Utica and we have that capacity to get to the Gulf Coast.

That's been baked in there, to answer your question, for quite awhile, bringing that volume back in.

And I assume obviously that transport cost is as well.

But can you refresh us on what the transport cost is or the economic uplift from getting gas out of basin?

It is significant.

And I don't know that we've gone into the detail of what are transport cost but what I can tell you is exceptionally competitive versus our peers, like half.

Okay.

Appreciate that.

And then one last one, just on the breakeven analysis that you guys put out.

Can you talk a little bit instead of on the PV 10 breakeven the actual maybe cash on cash payback periods in terms of how quickly those pay back and does that also influence what you'll select as far as what you're going to be drilling this next year?

I don't know if we have it necessarily for every single play but like the Meramec wells, there can be two years or less, in that time frame for paybacks.

Miss Lime, same thing, so the things that we're focused on are that two year, 2.5 years or less time frame from what I've seen out there.

But I don't have payout period by bar that we've got out there.

That's going to be fairly consistent.

It absolutely goes into the decisions that we'll make.

If we're looking at a really strong asset but we've got to build out to it and it's going to be a three-year delay type deal, we're just not going to put money there.

We'll look at that cash turn and focus in on areas like Mid-Con where we've got the infrastructure.

We can hook wells up very, very quickly and get a quick cash return.

As we're laying out our 2016 program, that is a big driver relative to the weight on that in the past and for obvious reasons, with decreased revenue you've got to be focused a little bit more on short cycle cash opportunities.

And so finding ways to put capital to work that has the nearest term payback makes the most sense from a return perspective in this market even if bigger return opportunities are out there but they require a longer lead time to achieve it.

Appreciate the added color, guys.

Thanks so much.

We'll take our next question from James Sullivan with Alembic Global Advisors.

Good morning, guys.

Just quick clean-up question here.

You guys had talked about the target for year-end 2015 of $1.5 billion of cash on hand.

Does that include the $200 million to $400 million of asset sales you guys are contemplating here or is that kind of absent that?

This was the $1.5 billion.

The $1.5 billion, just to be very clear about all that, the $1.5 billion is prior to handling the November maturity.

So to the extent we're paying for that in cash, it will come down but then the cost reductions that we're seeing in those asset sales will then again offset that back higher.

So depending on the timing of those asset sales, it would either be still at $1.5 billion or maybe a little bit below.

But then you have $400 million reduced debt.

So you have to include that in the analysis.

Got that.

I got it.

Got it.

That's great.

Doug, then another little clean-up on this.

You had the royalty, the payment for the Barnett royalty settlement.

Did that happen in Q3 or is that going to be a Q4 event?

I'm not actually certain on the timing of the payout of that settlement.

Okay.

I'll follow up with you guys offline on that.

But then just the last one from me.

In the STACK, you guys talked a little bit about your negotiations with Williams going well.

Can you just remind me when it comes to the gas contracts, is there any part, and this includes obviously laterals, because I know you're a little bit broken up in terms of deep and shallow rights there.

But is there any part of that, that is in Blaine, Kingfisher, or Canadian or wherever or even a little bit broader in the STACK that is dedicated acreage on for gas gathering.

I can't tell you.

The Williams are all over the place.

I'm trying to remember.

I know that -- Energy transfer has some of the oil gathering or Sunoco for the Meramec wells.

This gas I'm trying -- I can't recall.

There will be plenty in that area that is dedicated and plenty that's not.

We have such a legacy position through that area and legacy production from many different producing zones that there will be some that would include the STACK zones that's dedicated and some that's not.

So it's going to be an important part of our discussion with Williams going forward.

It's going to be a driver of our activity.

It will be business that Williams and, frankly, many other gatherers.

That's probably the most competitive gathering area in the country given the legacy footprint of development in the area, conventional production in area and all the pipe that's laying underground and frankly, in that part of the world on top of the ground.

So it's very, very competitive area and a lot of gatherers will be pushing hard to get our incremental business there.

Okay.

Great, guys.

Thanks.

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

Mr. Sylvester, at this time, I'll turn the conference back to you for any additional or closing remarks.

I'll turn it over to Doug.

Thank you.

Thank you, everyone.

Chesapeake will continue to be responsive and flexible during this commodity price environment.

We are not forecasting price recovery.

We're encouraged about our production volumes.

We're encouraged our cash costs are down.

We will be a low cost leader.

Our capital is down.

We're also maintaining industry-leading capital efficiency.

Our capital program will be adjusted in a meaningful way in 2016 and the stable liquidity and strength of this Company and value -- how we drive further value for our shareholders will continue to be a strong focus for us as we roll into 2016.

So that concludes our call.

I thank everyone for their time.

That concludes today's conference.

We appreciate your participation.