Chesapeake Energy Corp (CHK) 2014 Q1 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation Q1 2014 conference call.

Today's conference is being recorded.

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

Please go ahead, sir.

Thank you, Lauren.

And good morning, and thank you all for joining our call today to discuss Chesapeake's financial and operational results for the 2014 first 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 at Pages 23 to 31 of our February 27, 2014 10-K 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; Jason Pigott, our Senior Vice President of Operations Southern Division; and John Reinhart, our Senior Vice President of Operations and Technical Services.

As a reminder, we will be hosting our 2014 Analyst Day in Oklahoma City on Friday, May 16.

This event will be webcasted, and details can be found on our website.

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.

I hope that everyone has had the opportunity to review our 2014 first quarter results issued earlier this morning.

It was an excellent growth quarter for Chesapeake.

We reported year-over-year adjusted net production growth of 11%, adjusted EBITDA growth of 34%, and adjusted earnings per share growth of 97%.

I'm particularly proud that we've achieved this growth while running a disciplined capital expenditure program that's approximately 50% less than a year ago.

This morning we are also very pleased to note that we have raised our 2014 full-year operating cash flow guidance by $700 million to $5.8 billion to $6.0 billion.

We have increased our production growth guidance to 9% to 12%, up from 8% to 10% on an adjusted basis, and we have maintained our capital expenditure guidance at $5.2 billion to $5.6 billion.

The ability to provide this growth in capital efficiency demonstrates the power of the Chesapeake portfolio, as the industry's beginning to emerge from a prolonged period of depressed natural gas prices, and as we focus our efforts on generating incremental shareholder value out of every dollar spent.

Our cash flow increase is prompted by a number of factors including better than expected first-quarter operating cash flow performance, an increase in our production outlook, a decrease in our expense outlook for the remainder of the year, and an increase in our benchmark oil and natural gas price deck to $95 and $4.50 respectively, which is more reflective of the current strip pricing.

Nick will cover the rest of our outlook changes in more detail later in the call.

As noted in our press release this morning, overall production in the quarter was impacted by approximately 7,600 barrels of oil equivalent per day of weather-related downtime, mainly affecting our Mid-Continent assets but still within our forecast weather-related downtime that's in our guidance.

In the Eagle Ford, production was down slightly on a sequential basis due to a combination of factors including gas gathering and processing facility downtime, operator and competitor offset activity-related shut-ins, and weather-related activity reductions.

April production trends in both the Mid-Continent and the Eagle Ford give us a high degree of confidence that most of these issues are now behind us, and we believe the production growth, particularly on the oil side, is poised to grow sequentially for the remainder of the year.

Notably our average daily production rate in the Eagle Ford is currently 95 to 1,000 barrels of oil equivalent, which is roughly 8% above the daily average rate in the first quarter.

And I'd like to note that we plan to exit the year in the Eagle Ford is a substantially higher rate than in December of 2013.

In the Utica and southern Marcellus, the start-up of our ATEX pipeline shipments ahead of forecast, combined with stronger first-quarter production from these areas, has resulted in a very robust NGL growth profile.

These are the primary factors behind the increase in our 2014 adjusted reduction growth outlook to 10% to 12%.

As the lowest cost anchor shipper on ATEX, Chesapeake is well-positioned to maximize its margins in this region via our valuable ownership of firm transportation on the ATEX pipeline.

Chesapeake has, and will continue to, evaluate opportunities to utilize third-party ethane volumes to fulfill capacity commitments and reject a portion of our own ethane.

Given the rapidly-growing regional production profile and the potential for BTU-related pipeline restrictions, we are very pleased with our transportation position on ATEX.

And we intend to use this asset strategically to maximize our margins and maintain ethane recovery flexibility.

Turning to capital expenditures, despite a very low level of spending in the first quarter, we still anticipate total CapEx within our previously stated range of $5.2 billion to $5.6 billion for the full year 2014.

Total capital expenditures in the 2014 first quarter were approximately $850 million, of which drilling and completion capital was approximately $729 million.

We invested cash of $882 million during the first quarter in drilling and completion activities, which was partially offset by lower than estimated drilling and completion costs and other adjustments related to prior periods of approximately $153 million.

Net expenditures for the acquisition of unproved properties were approximately $24 million, and other capital expenditures were approximately $97 million.

In the first quarter our drilling and completion CapEx decreased 37% sequentially from the 2013 fourth quarter, in part because we completed approximately 15% fewer wells.

This decrease in completions is largely due to the timing impact of increased pad drilling, which can delay the completion in connection of new wells until an entire pad is drilled out.

We expect many of the pads drilled during the first quarter will be completed and connected during the second quarter, and that E&P CapEx will rise accordingly.

Additionally, given the severe weather experienced during the first quarter, we voluntarily delayed some completion activity from the first to the second quarter.

Improved capital efficiency was also an important driver of our lower spending during the first quarter.

We reduced our average capital cost per well by several hundred thousand dollars in the first quarter of 2014 compared to our 2013 average well cost.

Consequently, we are spending substantially fewer capital dollars year over year while still achieving or exceeding our production growth targets.

As part of the strategic initiative to reduce future corporate obligations and complexity, we chose to utilize a portion of the excess cash we generated during the quarter to purchase a number of rigs and compressors subject to long-term lease agreements.

These transactions will reduce future cash commitments and help facilitate asset sales and the possible spinoff or sale of our Chesapeake Oilfield Services unit.

Chesapeake has undergone a remarkable transformation.

Our strategies and financial discipline and profitable and efficient growth from captured resources are becoming readily apparent in our results and are generating foundational improvements across the business.

I am extremely proud of the Chesapeake team and the rapid pace at which we have embraced our challenges and opportunities.

We will relentlessly pursue continuous improvement and drive towards our goal of becoming a top performing E&P company.

This concludes my prepared remarks, and I will now turn the call over to Nick Dell'Osso, our Chief Financial Officer.

Nick?

Thanks Doug, and good morning.

I'm very pleased with our financial performance this quarter and the progress we continue to make in simplifying our balance sheet and reducing leverage cost.

In our updated investor presentation posted to CHK.com this morning, we've included slides to provide more detail on some of the topics that I'm going to discuss on this call, including changes to our 2014 outlook, natural gas differentials, and basis hedging, and balance sheet improvements.

As Doug mentioned in his opening remarks, we increased our 2014 operating cash flow outlook to a range of $5.8 billion to $6.0 billion, which is an increase of $700 million from the prior outlook midpoint.

The drivers of this increase our attributable to the following.

First, approximately $340 million is associated with an increase in our benchmark oil and gas price forecast for the remainder of 2014, net of hedging impacts and increases in oil and NGL differentials.

Note that our new oil and gas price deck for second quarter through fourth quarter is $95 per barrel and $4.50 per Mcf, up from our previous assumption of $90 per barrel and $4 per Mcf.

Second, approximately $190 million of our operating cash flow increase is associated with a change in the hedging presentation assumptions embedded in our outlook.

Previously our Outlook guidance treated all realized hedging gains and losses as cash and all unrealized gains and losses as non-cash.

However, a portion of our realized hedging gains and losses actually consists of non-cash amortization from previously closed out hedges.

The new outlook guidance presentation we've adopted includes only cash related to hedging gains and losses and excludes non-cash amortization, which we believe more accurately aligns with reported cash flow.

Please note that cash flow from operating activities on a GAAP basis is unaffected by this presentation change.

It only affects our outlook and improves the accuracy of our estimate of cash flow.

Lastly, approximately $170 million of the operating cash flow increase projected for 2014 is associated with our increased production outlook for 2014 coupled with Chesapeake Oilfield Services net margin improvements, as well as the various other expense improvements that I will cover shortly.

Next I would like to discuss the positive impact that strong northeast natural gas price realizations had on our first quarter results.

And I would also like to provide some detail on our natural gas basis hedges for the months of April through October of 2014.

On a Company-wide basis, our natural gas price differential decreased to $1.08 per Mcf in the first quarter from $1.76 per Mcf in the fourth quarter.

Very cold winter temperatures and increased heating demand in the first quarter coupled with Chesapeake's beneficial firm gas transportation position in the Northeast was the primary driver of the quarter-over-quarter improvement in differentials.

As a reminder, in November 2013 Chesapeake began delivering natural gas from its northern Marcellus play into the Spectra pipeline, which receives pricing at the Tetco-M3 Hub and accesses the Manhattan market.

During the 2014 first quarter the Company delivered approximately 425 million a day to the Tetco-M3 Hub, where we received an average premium to NYMEX Henry Hub prices in excess of $5 per Mcf.

These volumes represented approximately 30% of Chesapeake's net northern Marcellus production during the first quarter.

The Company estimates that this firm transportation commitment on the Spectra line enabled it to generate $210 million of incremental operating cash flow over sales in the Basin during the first quarter.

It is important to point out that the positive effects of the premium pricing in the Northeast I just described were largely known at the time we issued our 2014 outlook guidance on February 6. And as a result our full-year 2014 natural gas price outlook remains unchanged at $1.60 to $1.70 per Mcf.

Looking ahead, Chesapeake expects the Tetco-M3 natural gas prices will regard to a discount to NYMEX Henry Hub in the months of May through October.

And has accordingly entered into basis hedges on a significant portion of its 2014 gas to be delivered at Tetco-M3, as well as other sales points related to its northern Marcellus production.

Please refer to Slides 12 and 13 of our updated investor presentation on CHK.com, which includes new disclosure on our natural gas sales points, basis hedges, and associated volumes in the northeast Marcellus, the Utica, and the southern Marcellus.

To wrap up, I'd like to walk you through a few of our other outlook changes and key elements that drove the quarterly results on the cost of margin site.

We are pleased to increase our projected Oilfield Services operation net margin by $25 million for 2014, which reflects the general impact of improving industry trends and increased third-party utilization of our services equipment.

On the cost side, we are reducing the high end of our G&A range to $1.30 per BOE from $1.40 per BOE as we continue to achieve cost savings through disciplined spending.

Production cost during the first quarter came in at $4.73 per BOE.

Our full-year 2014 outlook range anticipates decreasing unit production cost as we realize additional volume growth throughout the year, however.

So we are leaving our production cost range of $4.25 to $4.75 for per MBOE unchanged.

Turning to the interest expense, we are reducing the expected range by $0.20 per BOE to reflect the impact of our recently completed $3 billion debt refinancing, which reduces our weighted average interest cost from 5.9% to 5.1%, and is projected to generate an estimated annual cash interest cost savings of $115 million.

We are also beginning to see the benefit of our capital efficiency programs in are DD&A rate, and accordingly have reduced our DD&A Outlook by $0.50 per BOE.

That concludes my remarks.

Thank you for your time this morning, and we will now open up the call for questions.

(Operator Instructions)

Mike Kelly, Global Hunter Securities.

Thanks, guys.

Good morning.

Nick, you had some good comments there on the differential outlook going forward.

And was hoping you would take it just one step further.

And for modeling purposes, what should we dial in for 2Q and 3Q -- if you'd give us a head start there.

Well, to avoid getting into too much granularity on the call, Mike, I will just remind you that we did keep our range at $1.60 to $1.70.

And also, I'll point out that in the first quarter we did bake in our expectations of cold weather, as we presented our outlook in February.

However, when we did so, we still did see incremental high prices through the remainder of the quarter.

With that ends up doing, in certain contracts where we have basically a value component to the transportation price, is that when you have those spikes in prices, there are some contracts where we pay higher transportation costs.

And so, actually, even though our realized prices came in even higher than expected at that time in February, so did our transportation costs as a result.

So, while we baked in a big portion of that improvement, there was an incremental transaction cost in the first quarter that we couldn't predict at that time.

So, relative to where we were then, the $1.60 to $1.70 for the remainder of this year takes into account that incremental cost in the first quarter.

So, it's actually a bit of a better picture than it was in February.

Okay.

Appreciate that.

And if I look at your guidance, in terms of the real drivers of the increase here on the production side, it looks like it is NGL-driven primarily.

And was hoping you could talk about the composition of that.

Is this mostly more ethane stripping, which is the driver of that?

And if it is, maybe you could just talk about the factors that would potentially take oil production guidance higher as you go throughout the year here, given comments that the Eagle Ford looks fairly stout going into Q1 here?

Thanks.

Hey, Mike.

This is Chris Doyle.

Let me touch on the NGLs; the big driver there is really in our AP South business unit, which includes our Marcellus South and Utica assets.

ATEX came online in January.

We started recovering NGLs, shipping ethane down ATEX in January from Marcellus South, and we brought in Utica in March; honestly it came in a little bit ahead of schedule, which is great.

The teams out in the field executed on a significant production ramp that we could risk down in our forecast.

And in addition, we started seeing plant statements.

We get very comfortable with the ethane and NGL coverage that we're seeing from those streams.

And so, that gives us the confidence looking forward to go ahead and raise that guidance, from already a very stout NGL growth guidance that we put out in February.

In terms of oil -- I'll just touch on the Rockies.

As you know, we're capacity-constrained until the fourth quarter.

We are moving ahead with Bucking Horse; that's the one that gave us a big jump in oil volumes in the fourth quarter.

And I'll kick it to Jason to touch on the Eagle Ford and Midcon, the other two world-class assets for us.

As far as the Eagle Ford, again, we've had a transition with the rig fleet.

So, we've moved from a high of 32 rigs in 2012, to a low of 10 in 2013.

We've ramped back up during this first quarter, up to 20 rigs with two spudders, and we've also transitioned to pad drilling.

We've had a little bit of a slowdown this first quarter, but that was totally anticipated so looking forward to grow our oil volumes out of the Eagle Ford.

And those first sets of pads get drilled and the wells start to come online -- looking forward to the growth there.

In Midcon, it's been a really exciting story for us, especially in our Miss Lime play.

We've hit a record rate out there of 30,000 barrels a day in Midcon North.

So, very excited about the progress we're seeing in Midcon, as far as our big oil growth engines there.

So, again, I think we're going to look really well by the year end, as far as oil growth is concerned.

Appreciate that.

If I could sneak one more in -- just on the capital efficiency front here.

Doug, I was hoping you could quantify, or just give us your thoughts on how far along we are in the goal to get well cost down $1 million across the board on each one of your basins per well?

Thanks.

Sure, Mike.

I'm glad you asked that question.

As everyone is aware, we set out a goal at the end of 2013 in the fourth quarter.

As part of our capital efficiency and improvements in the Company, we were going to drive $1 million per well out of our capital program.

And we have made substantial progress in every single area in which we are investing.

Our outlook for the year -- that was a program that we were looking to achieve and accomplish over the course of 2014.

We essentially have captured a good amount of that, if not all of it, in several areas.

And we still have more opportunities through efficiency and synergies that we anticipate that we can capture.

So, excellent progress with that respect.

We will be providing more detail on an asset basis at the Analyst Day next week, and provide more color around how those capital efficiencies are being captured and where we anticipate further capital efficiency to be recognized in our program going forward.

All right.

Good deal.

Great quarter, and look forward to the update next week.

Thanks.

Thanks, Mike.

Doug Leggate, Bank of America Merrill Lynch.

Thanks.

Good morning, fellows.

I appreciate the detailed explanation on the basis differential, but obviously, sometimes that's never enough.

So, if you don't mind, I'm just trying to dig a little bit more into this.

What I'm curious about is: As the Haynesville production kicks back in towards the back end of the year, in terms of growth that is, and obviously the big ramp you have in the Utica, what does the mix change do to the basis outlook?

Because I'm guessing you've got a bit more flexibility than perhaps beyond your current midstream commitments to be able to see improvements, perhaps we're not baking into our numbers right now.

So, I'm just wondering if that was part of what we saw in Q1, or if I'm just completely off base?

I appreciate that color.

Sure, Doug.

This is Nick, I'll take that.

So, we are expecting an increase in our Haynesville production this year as we ramp our rig activity there, as we'd previously noted.

The timing on that, of course, is the key to figuring out exactly how many volumes come in this year versus next year, and determining what the MVC impact will be.

So, as you think about what I said earlier about the $1.60 to $1.70 staying where it is for the remainder of the year, and that being actually an improvement on where we thought it would be in February for the remaining three quarters, the Haynesville MVC as we're getting ramped up there, is probably a bit higher than we thought it would be then.

And the Barnett is lower, as we've seen better production come out of our Barnett wells than we anticipated at the beginning of the year, and as we see some opportunities to bring on some low-cost completions and things like that in the second half of the year.

So, we continue to stay on top of the forecast of that, overall MVC impact in our second half of the year is lower than we anticipated originally.

And we will always continue to try to optimize our capital program around those types of items that we can take advantage of opportunities, whether they be basis, like we saw in the Northeast, or whether they be transportation related to optimize the contracts we have in place.

Forgive me for pushing this, but if we look into 2015 and beyond, can you just give us a rough start as to how you would expect that basis differential to evolve?

Yes, there's just so many components to it there, Doug, when you talk about transportation as well as basis.

So, it's a bit hard for me to do that until we get into really giving the Street some detail on our capital allocation across our assets, and where we see the best return coming out for shareholders, and how we go about prosecuting the program for 2015.

I'll just tell you that it certainly would not be in our forecast to have the same strength of Winter that we had this year.

We'd all love to forecast that, but that's probably not realistic.

So, we wouldn't necessarily have that basis improvement there.

And from a transportation side, we will have some of the same types of challenges around where our firm transportation and MVCs are, but we think it's manageable, like it was this year, where we optimize our capital program around that.

We think potentially there are opportunities to continue to do that and improve what we see.

Thanks.

My follow-up is maybe a little more philosophical, and Doug, I guess this one would be for you.

There's been a little bit of speculation that perhaps you would be prepared to look outside of the US strategically as you move forward.

Now, obviously, I don't want to front-run the analyst update, but I just wonder if there was really any substance to that, or if obviously you've got a lot of wood to chop in the lower 48 to date.

But how do you feel about the overall direction of the Company going forward?

And I will leave it there.

Thanks.

Thanks, Doug.

That's a great question, and I really appreciate you asking it.

I think you categorized it properly that we've got a lot of wood to chop, and I think we're making a lot of progress on several fronts.

The efficiency in our programs, our cash costs, our capital program, the synergies operationally that we are capturing -- I could not be more excited about the progress that we're making.

What we see with our high-quality assets is a great growth potential and excellent running room.

And as the Company continues to grow, the strength of our assets provides a lot of flexibility.

And I think we have an outstanding portfolio; a highly competitive portfolio compared to our peers.

So, I'm very pleased with that, and I want to highlight and point to our strategy of which is the financial discipline, which we are making great progress on.

And the second point: profitable and efficient growth from captured resources.

And the emphasis there is that that captured word is there for a specific reason, Doug.

It is there because we are focused on driving the greatest value from these assets.

Now, that said, I think that it's important to note, and I've shared it in a few external presentations, that the Chesapeake geoscience talent, the Company's speed, the operational capability and expertise is outstanding.

And as the world, and countries around the world, look for opportunities to develop their own unconventional or shale resources, Chesapeake has that expertise, and could potentially be a part of it.

I believe it's something that we should evaluate.

We have not made any commitments to enter into the international arena.

But I do believe that, in the Company's future, that that could be a possibility.

We just have to be very careful that we do not compromise the value-creation story from our current assets, and it has to be a very prudent and value accretive to our shareholders.

So, as everyone is aware, there's different risk profile in international, and the last thing we're going to do is, in any way whatsoever, sacrifice any value for our shareholders and our growth story.

So, that's where I'll leave it in response to your question.

But there's extremely good growth opportunities in our current assets.

And for the size of the Company, there's an option lever there that could potentially be pulled, but it has to make good sense for our shareholders and the Company's growth progress going forward.

I appreciate the answer, Doug.

And I will see you next week.

Thank you.

Great.

Thanks, Doug.

Charles Meade, Johnson Rice Brokerage.

Good morning, everyone.

Thanks for taking my question.

Doug, I want to go back to a discreet comment you made in your prepared remarks about the ATEX line.

It sounds like what you are considering is perhaps not doing -- just doing partial ethane recovery to get the pipelines back, and then using your extra capacity on the ATEX line to buy heavily discounted ethane that other people have to strip out to meet pipelines back?

Have I got the right read on that?

Yes, that's a fair look at what we're trying to describe.

The ATEX pipeline gives us a tremendous amount of flexibility and strength there with our production.

And I guess what I'm really after is, where is that going to show up?

I'm guessing it will be in the marketing midstream line.

And what kind of order of magnitude are we talking about, as far as the value capture opportunity there?

Well, we haven't put that exact level of detail out in our guidance yet.

The key, in my mind, is the flexibility that it offers to us with the production growth there and its optionality, how we can capture the greatest value for our shareholders given that asset and that capacity that we have available to us.

Got it.

So, it's several birds in the bush, just none in the hand yet.

And then, shifting back over to the Utica, I'm wondering: You guys have had some, I guess, some midstream challenges with the Natrium plant fire, and -- but that's in the past.

You've now got the ATEX line up.

Can you talk about how that play, and whether -- I'm more interested in the well performance and the takeaway, that kind of thing.

How that is performing versus your expectations of maybe three or six months ago?

Hey, Charles.

This is Chris Doyle.

I am exceptionally pleased with the continued performance, and honestly, outperformance of the team that we have working the Utica.

When I came on six months ago, I had many of the same questions I think some of you guys have.

I spent six months looking at the results that this team has executed upon.

I'm really looking forward to sharing that with you guys next week at the Analyst Day.

I could tell you everything is lining up.

As you said, we've had some challenges -- had some challenges late last year, and we came back kicking.

We are setting production records, probably two or three a week, as we continue up this aggressive production ramp.

As the press release indicated, we average about 50,000 barrels a day equivalent net from that asset, and we're significantly higher than that today.

Just an update: The next tranche, the next bump up will come in the form of Kensington -- the third train at Kensington -- another couple hundred million a day.

We are on track for a June start-up, which is reflected in our forecast.

We tied in that third train a couple weeks ago.

We're finishing sort of final adjustments -- electrical -- and should be commissioning in a couple weeks.

This is a team that continues to out-execute just about anybody in that play.

And you'll see that in black and white next week, and couldn't be prouder of the team.

Thank you.

I'll be tuned in when we see you next week.

Thanks a lot.

David Heikkinen, Heikkinen Energy Advisors.

Good morning, guys.

I just wanted to check my math on differentials first.

With $1.08 in the first quarter in guidance, does that basically mean second-quarter gas will be $1.85 to $1.90 for -- in third quarter and fourth quarter?

Didn't calculate that out in front of me, Dave, but with $1.08 in the first quarter and $1.60 to $1.70 for the remainder of the year, that's the math.

Third (multiple speakers) quarter should theoretically be the highest, Dave, because you got the MVC coming back in.

Yes, and then, on the NGL realizations and NGL growth, you basically added 10,000 to 15,000 barrels a day of NGL volumes to increase your guidance.

As I look at the differential increase for the NGLs, and just attribute the volume increase and the differential increase to the same amount, that would be like a $99-a-barrel differential on the incremental NGLs?

Is that just tied to those incremental NGLs being primarily ethane?

A lot of those NGLs are ethane, Dave, you're right to note that.

But I would also remind you that when you look at the NGL differential as it's adjusted here, keep in mind that we increased our oil price by $5.

And so, if you look at the projected realized price for NGLs, they're actually a little bit higher than they were previously.

So, what we've really done, as we've said, NGL prices that we expect to receive are flat to a little bit higher, and the delta to NYMEX oil is wider as we've continued to see that NGL pricing is challenged in a way that oil is more volatile.

So, what we're really projecting there is less volatility in the NGL price this year than we've seen short term in the oil price, as we've gone from $90 to $95 a barrel.

Okay.

And then, Doug, you talked about first-quarter CapEx being down and a 15% reduction in completions.

Can you give us your outlook for second-quarter CapEx and the percent increase in completions as those pads come online?

We'll share more of that detail with you next week, Dave.

The key there is just noting that the strength of the portfolio, the capital efficiency, things that we are driving forward towards, that we are maintaining that CapEx we are projecting for the full year, and very confident on our production profile.

So, we will get into more details there on the asset side next week.

Just take the full year minus first quarter, and divide by three for second, third and fourth quarter?

Is that fair?

Well, keep in mind that the comments that we shared about some of the timing of the first-quarter completion activity -- probably a rough approximation is okay, but there will be some volatility around the quarters just based on the pad drilling and the activity.

Okay.

All right?

See you next week.

All right.

See you, Dave.

Brian Singer, Goldman Sachs.

Thank you.

Good morning.

Good morning, Brian.

Going back to the Utica, can you just talk about the trajectory of your production mix in terms of oil gas versus NGLs, both based on the various midstream debottlenecking, but also as you contemplate doing more, or looking more at the dry gas window versus the liquids-rich window?

Yes, Brian.

This is Chris Doyle.

I think we will probably get into that kind of detail next week.

What I'll say is that our trajectory has not changed.

You look at our total gross processing capacity, we laid out back in February was that we're going to ride that capacity all the way up through the end of the year.

We are definitely in line to do exactly that.

I'd say right now, just rough approximation, the component split's probably 10% oil, 30% NGL, and 60% gas, plus or minus.

You mentioned the dry gas, and we're excited about some of the tests that we've seen.

We have some of our own dry gas tests, but honestly that's probably two or three generations of completions ago.

So we are out there.

We'll be out there testing the dry gas window, and excited about the hundreds of thousands of acres we've got in it.

But what I'll also say is: It's not just about the dry gas window.

We are testing every part of that play, and just have a tremendous amount of excitement about what we are seeing.

And we'll share a lot more next week.

Great.

Thank you.

And then, shifting to the Haynesville, you talked about production bottoming here starting to return to sequential growth in the third quarter.

How are you thinking about that as you look into 2015 on an annual basis?

I think you've said flattish in the past.

Is that still the case, or do you expect a more secular trend in growth?

Right now, we're trying -- I'm sorry, this is Jason.

We're still kind of working on what our 2015 rig allocation is going to be.

We are looking at a steady eight rigs probably.

Again, we are factoring in, as a portfolio, just MVC.

Again, we've got -- first of all, we've got great economics in there.

We had a first-quarter post-appraisal that we just finished last week, and those wells averaged about over a 50% rate of return.

So, real excited about the economics and results that we are seeing from that program.

But again, the Haynesville program is designed to optimize the cash flow at a corporate level.

So, we we'll kind of avoid our 2015 discussions for right now, and touch on those maybe more at Analyst Day.

But for this year, we are planning an eight-rig program that will get us up above our MVC by the end of -- close to that by the end of the year.

Great.

Thank you.

David Tameron, Wells Fargo.

Good morning.

Some of my questions have already been asked.

If we look back at the Eagle Ford, it looks like that oil, the percentage coming from oil went down in the quarter from 4Q to 1Q.

Was that infrastructure, or can you just talk about anything changing out there?

The only thing I could point to -- again, I hadn't looked at that actual percentage going forward, but then we did have some down-time issues that impacted oil more than the gas.

So, that could be influence that we lost about 120,000 barrels just, again, gas and stuff, just due to some processing problems and gathering problems.

So, again, I don't think our overall fluid composition out of the Eagle Ford is going to change long term.

It's a pretty steady profile.

So it just may have been something that happened during the quarter.

Okay.

So, no change to what you're drilling?

No.

Again, we're 75% liquids pretty much out of the program, and 25% gas.

So, again, there may be minor fluctuations here and there, but I don't think it's anything major or long term.

Okay.

And then, Nick or Doug or whoever wants to take this -- the natural gas side -- I think I asked you about this before, but as far as hedging for 2015, you're not that hedged.

And just given the focus on debt repayment, and then a little more conservative approach on the financials, why not go ahead and just lock some of that gas in rather than take that bet that gas moves higher?

Can you guys just talk about that?

Yes, Dave, it's a good question.

One on which we continue to look at, and we view the hedging program to be very important and critical to protect our cash flows.

And we look at it very often, and we'll continue to look at it.

So, I think that there's opportunity there.

And the way we look at it right now, I think that we have a lot of strength in the pricing.

And as you are well aware, the focus on protecting our cash flows and improving our balance sheet -- they are key elements.

And what you can expect is we'll continue to hedge at an opportunistic time that we think is the best for the portfolio.

All right.

Let me flip one more in here.

You guys have put this capital discipline slide in here -- the cash flow versus the CapEx.

And you're finally, I guess for the first time in at least five years on that chart, you're above CapEx.

If we maintain a positive -- let's say we maintain current prices, should we see that gap widen in 2015 and 2016?

Doug, I'm sure, will want to have something to say here, too, but, Dave, we've held off on giving any kind of guidance on what we are going to do for 2015 yet, because we're going to continue to assess our opportunities there.

All things equal, if prices stay high relative to how we have things planned, yes, that guidance -- that gap would widen.

But I'd just remind you of the strength of the portfolio and the places we have to invest capital at a very high rate of return when you think about that question.

And I think, just to add there, that everything we do will be tied back to our strategy.

And that strategy is to provide top-quartile metrics -- growth metrics from an operating perspective and capital perspective and a financial perspective.

And so, we're not looking for a one-quarter win or a one-year win.

We're looking for the long haul -- steady, repeatable performance that's in the top-quartile category.

And we are making great strides in that way.

And as we look forward to 2015, and we'll be sharing some additional color about that next week, we have a lot of opportunity.

Okay.

Thanks for the color.

Good luck next week.

We'll see you out there.

Thanks, David.

Thank you.

Jason Wangler, Wunderlich Securities.

Good morning, guys.

Curious on -- just with obviously a raise in the commodity prices and what we've seen just in general, whether it's within individual basins or just across the entire portfolio, are you seeing much of a change in just the activity plans for the year, or even as you look even further out?

Well, the portfolio that we have gives us a lot of flexibility.

And as we look at our capital program and we plan going forward looking to capture the greatest margins, we have a considerable amount of flexibility in being able to add rigs in certain area, pull rigs from another area, and we will do that as we see necessary.

I don't expect that you're going to see major deviations in our program, but because we have the strength like in the Haynesville, you could see us increase a rig there, but it's not like you're going to see us ramp up to 15 rigs there or something like that.

So, we really are trying to take a very disciplined approach to it, but the strength in the prices and the strength in realizations, we will opportunistically look to capture that value, but it will not be a significant deviation from our planned programs.

Sure, that's helpful.

And then maybe just on a high level, and I'm sure we'll get into this more next week, but from the asset sale perspective, just the non-core side, it seems like you just kind of keep peeling things off.

I mean, do you have an idea, at least on a high level, how far along in that process you are?

Is there much left to do, or have you kind of gotten through that portion of it the last year or so?

There's still a fair amount to do there.

It'll come in pieces.

It won't be a big wave necessarily, like we've had in the past, of as many kind of volume of deals.

But we do have a large portfolio.

We continue to note there are a number of things in the portfolio that others look at and feel they would covet more highly than we do.

And therefore, put more capital into, and therefore, be worth more to them than it would be to us.

So, things that we're not investing in that become non-core to us over time, we will either determine if there's ways to improve them and make them more competitive in our portfolio, or we will look at divesting them.

But that's an active process that this Company will be in, in perpetuity, given the breadth of the portfolio.

And just to add to what Nick said there, I think that our target about that financial discipline and improving the balance sheet and the strength of our balance sheet is something that we are actively working and we will continue to work.

I appreciate it.

Thank you, guys.

Neal Dingmann, SunTrust Financial Services.

Good morning, guys.

Just two questions.

First, just on -- noticed that obviously the CapEx for the acquisitions of unproved properties, you've got that down now.

I think it was $24 million or so for the last quarter.

Your thoughts -- are you continuing to add just some bolt-on things to block up some acreage?

Or, Doug, is it fair to say that, especially in your Eagle Ford and Utica, most of that now is pretty blocked up?

You described it perfectly, Neal.

We will have some small, incremental acquisition costs in there for bolt-on type of stuff, filling in acreage, but it's not a significant part of our program and you won't see any major deviation from that.

Okay.

And I'm sure you'll probably hit this next week, definitely more detail in the Utica, but just questions on -- I think you said for the 47 wells, it says in the release that the average was about 1,180 boe per day.

Just wondering on -- now, on further wells that you're doing, existing -- what do the completions look like?

Are you extending the laterals?

And so, I guess two questions there, just on the overall cost of these wells, and then how you're seeing the laterals sort of develop?

Hey, Neal.

This is Chris.

As you and I discussed probably a couple months ago, our focus for this year is capital efficiency.

And what that means for us in the Utica is extending those laterals out and actually optimizing our completions.

And so, we are seeing quarter-over-quarter or year-over-year increase in EURs and performance.

We are, as you know, not aggressive when it comes to the choke.

We think the long-term performance of these wells, and it's interesting to see some of our competitors come out and now do the same thing.

We think long-term performance is not driven by the first month of production.

It is driven from the first year or two years of production -- how you bring these wells on.

As we've said, we're exceptionally pleased with the performance.

We'll get into a heck of a lot more detail next week, but for the discussion you and I had earlier this year, is still on track, and longer laterals and optimized completions.

And well costs -- what we were talking about was we could drive well costs into the $6 millions.

We're staying right around in the $7 millions, low-$7 millions, but reallocating some of the efficiency gains that we're seeing -- some of the cost reductions that we are seeing into better wells.

All right.

Thanks, guys.

Thanks, Neal.

Arun Jayaram, Credit Suisse.

Good morning, gentlemen.

Good morning, Arun.

Doug, I just wanted to see if you could maybe highlight maybe your opportunity set regarding Powder River Basin oil, as well as the Niobrara.

Haven't gotten an update from you guys on that in a while.

We're going to give you a good review of that, Arun, next week.

We are excited about what we see up there.

We think there's good opportunity.

I view it as another strong asset.

This will be important in our future and for our oil growth strategy.

So, we'll be sharing a little bit more detail with you next week on that.

Okay, fair enough.

Doug, as you think about -- as we look at the big cap peers to date in earnings season, haven't seen really any of the large caps putting incremental dollars into gas.

So, I just wanted to get your thoughts on what it would it take for CHK -- obviously you added some rigs in the Haynesville, but to get more capital allocation towards dry gas?

Is there a gas price, or what are you looking towards to do that?

It's not really driven by gas price, Arun.

It's more focused on how can we drive the greatest value over our program and how can we continue to sustain that over time?

So, we have tremendous flexibility in our rig fleet and how we can move our rigs around.

I don't see us materially changing, as I had commented on a previous question, materially changing our program as gas -- in the current gas price environment.

But keep in mind that with four assets that can produce greater than a BCF a day, several of those can produce greater than 2 BCF a day, we have a tremendous value lever there that has proven in the past this Company's abilities to ramp production very quickly and take advantage of a strong opportunity.

We can do that.

The key in my mind is just that we're going to do it at a prudent pace.

We're going to do it at a value-capture pace, and not do anything to compromise the long-term growth profile of the Company.

So, that said, you can see a few rigs move around to capture greater value, and we will do that and just react in a more opportunistic way.

But we're certainly pleased with the gas prices, and looking to capture greater value there.

Okay.

Thanks a lot, Doug.

Yes.

Subash Chandra, Jefferies

Hi, good morning.

Trying to understand, I guess, I might struggle in asking this question, but should we think about these cost goals per well as sort of an initial stage of cost reduction that is heading towards best practices?

Or is this sort of phase one of cutting the fat, and best practices might involve putting more horsepower to completions or stages, et cetera, to where you're maximizing output?

I mean, it doesn't seem at all like you're sacrificing output while you're reducing costs, but trying to understand if, as you -- if this is the best practice completion you're looking for, based on the basin in the current program?

That's a great question, and I appreciate you asking it.

I would answer it in -- the way I would describe it is, is that we, our initiatives that are in place are driven, and how do we capture the greatest value?

And I've mentioned this a few times in different presentations, but there's a difference between cost management and cost leadership.

And what you're seeing take place in Chesapeake's program is some of both.

We are managing costs, in my mind, the differentiation between the two is: Managing cost is driving the things out of our program, out of our expenditures that we know, the efficiency gains that we know exist.

Cost leadership is how we continue to deliver the same results in driving further value and cost reductions into our program.

The teams have done a fantastic job.

We've made significant progress.

I think we still have a long way to go.

The excitement in our teams and on campus here is very strong.

The asset reviews, the opportunities for further synergies, further cost reductions are fantastic.

So, I think we've got a lot more opportunity on the cost leadership side, and the focus that we have there is great.

And so you'll continue to see improvements on the cost side, but as Chris was highlighting a little bit there that we also are very mindful -- how do we capture the greatest value?

So, as we look for ways to reduce our costs and to be more efficient, in some cases it may be adding additional frac stage to get a greater recovery or to optimize on our rate or to optimize a program.

So, the key there is: Drive the costs out, cost leadership, but also how do we capture the greatest value?

Okay, thanks.

And I'll probably hear more about that next week, as well.

Along those same lines, you're talking about optionality in the portfolios.

Wondering if, if you had unlimited dollars, if you can put in context what more you'd rather be doing?

And if you, given the competitive hiring environment out there, are you currently staffed to pursue these options?

With respect to the staffing question, we are.

And we've got a great, great group of talented employees that are doing a fantastic job with our new strategy.

As we look to grow the program, it's all really focused on: How can we drive the most competitive metrics for the Company and the greatest profitability for the Company?

We are just ever mindful: it's not one metric.

It's several metrics.

It's several things that we need to be competitive in driving towards top-quartile performance.

So, as we look at that, we're not going to sacrifice value, and we will staff accordingly, and we will maintain the discipline in our programs that we will perform not only this year, but we will perform in the subsequent years.

So, it's a little hard to answer that question, in that if we had -- if we allocated some additional capital, or we had some additional money to spend, we are building the programs where we know we can capture the next value opportunity for our shareholders.

Okay.

Thank you.

Dave Kistler, Simmons and Company.

Good morning, guys.

Real quickly, looking at your full-year CapEx budget, and then reflecting back on Q1, Doug, you had mentioned $850 million in the release and on the call, but that obviously had some nuanced adjustments to it.

Was that $850 million factored into the budget?

In other words, were you anticipating these accounting adjustments, divestitures that sort of balanced it out to $850 million?

In general, yes.

Keep in mind that as we had some weather-related issues, we deferred some of the completion activity to the second quarter, Dave.

There's some variances across all the different areas there, but in general, yes, it's all accounted for.

Okay.

And should we expect similar things going forward in D&C budget -- yes.

Yes, absolutely.

I mean, it's the recognition of the capital efficiency is also very, very significant in how we continue to capture cost savings in our capital program, and that's a huge driver for us.

Dave, just when you say significant things, I just want to be clear.

We would not expect those types of adjustments to be recurring.

Okay.

Okay, that's exactly what I was trying to understand.

So, then switching over back operationally, real quick on the Haynesville.

Well costs have gotten down to $7 million, as you highlight in your presentation.

You highlighted the 50% rate of returns.

Has there been any incremental productivity of the wells?

Or is that $7 million just the benefit of going back to existing pads?

Any kind of color you can give us on how those have been driven down so aggressively versus the rest of the industry.

This is Jason.

We have done a little bit of everything there.

We've been really playing with different completion techniques to get our costs down, so it's been no reduction in sand or anything like that, that we would pump.

It's just reducing chemicals that we use, testing some slick water fracs, et cetera.

So, those are really -- a lot of the savings is driven by the completion side, but drilling is doing a phenomenal job as well.

So, we've seen almost $2 million come off of those costs in a year.

So, very excited about that program going forward.

As far as productivity, again, we clock the performance of these wells on these tests to see if there's been any negative impact.

So far we haven't seen anything, so time will tell for that.

But we're really encouraged by what we've seen so far.

We do flow these back on our restricted rate choke, just like they do in the Utica.

So, you won't see big IP performance changes in those wells because we restrict flow on a restricted rate every well that we bring on.

So, they're performing exactly like we would expect from those wells.

We monitor pressure and rate to make sure that we are not seeing performance degradations, but, again, it's just been a great program, great turnaround for us in a short amount of time.

So, really excited about the Haynesville program overall, and just what it's adding to the Company as a whole.

Great.

I appreciate that.

One last one, and maybe this is going to be held off to the Analyst Day.

But when you look at what you're doing, you're driving down the cost dramatically, and you've given us some examples of that.

Can you give us examples that correspond with also increasing recoveries while those costs have come down?

Yes, we will be pointing you to the Analyst Day on that, David.

Okay.

Appreciate it.

Thanks, guys.

Matt Portillo, Tudor Pickering Holt.

Good morning, guys.

Just a quick question from me.

In regards to your inventory across a number of basins, could you give us a little bit of color as to how you think about working that down over time?

And in particular, just trying to get a better sense of how we should think about planning your Marcellus growth trajectory over the year.

And then just a second quick follow-up question in regards to service cost trends.

Just curious if you could provide some color on how you're seeing the service market evolve, as we've seen some uptick in activity from the industry?

I'll comment real quick, Matt, and then Chris may want to throw some additional comments in as we talk about a few of the areas.

The inventory has come down significantly compared to previous years.

We've made huge progress on that.

Keep in mind that as we've made this big shift, this efficiency shift to the pad drilling, that you'll have some inventory build associated with the timing of the wells coming online just by virtue of drilling four or six wells on a pad.

The one area that we still have some inventories in the Utica, and we'll be working that down over the year as well.

But we anticipate that throughout 2014 that we will be at a steady state, or a pseudo-steady state type of inventory based on the capital program and the timing of the pad drilling and bringing the wells off-line.

And then, Chris, do you want to add any comments?

Matt, the question about Marcellus growth and how should we think about that for the end of the year -- I'll add some color there.

I will say what we are forecasting is not requiring any growth out of that asset, honestly.

What we have is a tremendous position in one of the greatest dry gas basins known, and our wells continue to outperform our expectations and the industry's expectations.

So, what we are focused on is capital efficiency.

And we've got a lot of optionality, and we will share that with you next week, where we could ramp up, and potentially grow the asset, but we don't need that growth to grow the Company, and we are in a fantastic position with lots of flexibility when it comes to our expectations for the Marcellus.

On the service cost side, Matt, I'll just comment real quickly on that.

John Reinhart and his team that are focused on supply chain has been capturing part of our savings on a per-well basis have been heavily driven by our focus on supply chain capturing the greater aggregate purchasing power of the Company.

And so, in general, there's some service pricing pressure, but we are addressing that through greater synergies and greater cost management through our supply chain.

And, John, do you want to comment on that at all?

Yes.

I think we've been really pleased with the supply chain group.

This is an organization that started up in Q4, and just in a very short period of time has really driven a lot of value throughout the Organization.

And as Doug said, we are very early on in our capital improvements, but this has certainly been a big part of the improvements we've seen year to date, and look forward to further success throughout the year.

Thank you very much.

Joe Magner, Macquarie.

Thanks for taking my questions.

Just curious on some accounting adjustments that were made.

There's a comment in the release about how capitalized interest has gone down as the unevaluated pool has been reduced.

How should we think about the management of that?

We don't have the detailed balance sheet in the release, but has that come down meaningfully recently, or is there more to come?

And how should we think about that in the context of your DD&A guidance has come down, but how will that be accounted for going forward?

A lot of moving questions, maybe I'll have to follow up off-line, but just curious on the high level, what's driving some of these changes and how should we think about that as it rolls through?

Sure, Joe.

We will file our Q later today, so you can follow up with us if you have any further detail after that.

But just to comment at a high level, as we decrease our leasehold spending and we continue to evaluate properties through the drilling program, and other evaluations that we perform from time to time, you'll see that unevaluated pool decrease, just by nature of our activity levels.

So, as a result of that, you'll see interest expense be recognized in the income statement more than it was in the cash flow statement in the past.

I'll remind you, though, that when you think about modeling this Company from a valuation standpoint that we did decrease our cash interest expense on an annualized basis by $115 million through our recent refinancing.

So, what you're seeing there is a geography change from the cash flow statement to the income statement, and certainly is important to modeling EPS correctly.

But overall the trend on interest expense is decreasing.

Okay.

And I guess I'll just follow up afterwards once we have a chance to take a closer look.

I'll leave it there.

Thanks.

Thanks, Joe.

Okay.

We are going to cease taking calls now.

We've gone over our time just a little bit.

Just want to highlight: If you had any questions that weren't answered today on the call, that please follow up with Gary Clark.

He'd be happy to help with that.

And then also in addition, we are really excited about the Analyst Day next week.

And continue to share further detail in Chesapeake's growth program as we go forward, and additional asset details.

So, we look forward to seeing you next week.

Thank you, operator.

We appreciate everyone's time.

And that does conclude today's conference.

We thank you for your participation.