Chesapeake Energy Corp (CHK) 2014 Q4 法說會逐字稿

Good day and welcome to the Chesapeake Energy Corporation's fourth-quarter 2014 conference call.

Today's conference is being recorded.

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

Please go ahead, sir.

Good morning, everyone, and thank you for joining our call today to discuss Chesapeake's financial and operational results for our 2014 and the fourth 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 our 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 earlier this morning and in 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 now like to introduce the members of the management team who are on the call.

With me today are Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Chris Doyle, our Executive Vice President of Operations for our Northern Division; and Jason Pigott, our Executive Vice President of Operations for our Southern Division.

So with that, I will now turn the teleconference over to Doug and Nick and then we'll move to the Q&A session.

Thank you.

Thank you, Brad.

And good morning.

I trust that everyone's had a chance to see our press release that was issued earlier this morning.

I'd like to start this call by first thanking the Chesapeake employees for an outstanding 2014.

Together we made remarkable improvements in our operating efficiencies, financial stability and competitive performance.

And here are a few of the significant accomplishments achieved in 2014.

Our safety performance in 2014 as measured by total recordable incident rate, or TRIR, was the best in history of the Company, a 35% improvement over 2013.

We reduced our cumulative reportable spill volumes by 42% compared to 2013.

And I'm very proud of these two significant improvements in our safety and our environmental performance.

Of the operations side of our business, we grew our total oil and natural gas equivalent production by 9%, adjusting for asset sales in 2014, an impressive accomplishment when considering the reduction in our total capital expenditures compared to the prior year.

In mid-December we reached a new production record of 770,000 barrels of oil equivalent per day, and achieved the highest production in our Company's history while operating an average of 64 rigs, which is less than half of the number of rigs we operated in 2012.

Since 2012, we've improved our capital efficiency by 30% to 60% in each of our major operating areas.

Through these efficiencies, the continuous improvement, and the cost leadership of our employees we have driven hundreds of millions of dollars out of our well costs over this time period.

We reduced our drilling and completion expenditures by nearly $1 billion compared to 2013, all due to our increased focus on value and efficiency, but also because we created a supply-chain group in 2014 that delivered significant synergies and cost reductions.

In total our capital expenditures fell by 14% in 2014 to approximately $6.7 billion.

If we exclude acquisitions our capital expenditures were 23% below 2013.

We reduced our cash costs by 9%, achieving the lowest production and G&A costs on a BOE basis in a decade.

From a financial perspective, Chesapeake became significantly stronger, less complex and much more flexible in 2014.

There are three major accomplishments that set us apart from our peers.

First, we completed the largest and most significant transaction in our Company's history with the divestiture of our Southern Marcellus Shale and Eastern Utica Shale assets for approximately $5 billion, giving us tremendous financial flexibility.

While the assets represented just 7% of total production the proceeds from the sale equaled 40% of our market capitalization at the time it was announced, another reflection of our industry-leading, high-quality unconventional portfolio.

We completed a $450 million acquisition and exchange that doubled our equity interest in the prolific, oil-rich Powder River Basin, an area which we believe will be another strong oil growth engine for the Company.

We successfully spun off our oilfield services division, a critical step in divesting non-core assets and affiliates, and focusing our efforts and resources on our core E&P business.

We redeemed our Utica preferred shares which not only reduced complexity but also eliminated $75 million of annual cash dividend payments.

We reached another first in our Company's history with a new unsecured $4 billion credit facility with investment grade-like terms.

We also received two notch upgrades from Moody and S&P, placing us one level below investment grade at both rating agencies.

We eliminated $4.2 billion of leverage and complexity from our Company in 2014 and ended the year with over $4 billion of cash on hand, and we were completely undrawn on our credit facility.

These, along with many other achievements, have helped Chesapeake to become a much stronger Company which brings us to today.

As I've told our employees many times, the transformation that has occurred at Chesapeake over the past 18 months has prepared us for such a time as we see today.

The current commodity price environment is difficult but our focus on value and industry-leading performance is unchanged, and we're managing our business and activity levels around current strip prices of approximately $55 per barrel for oil and $3 for natural gas.

Looking to 2015 we've reduced our total planned, capital program by 37% compared to 2014.

We are forecasting production growth of 3% to 5% in 2015.

As noted, despite making changes to this year's capital program and reducing our activity levels we are not changing our focus on driving differential performance.

We'll focus even more on increasing our financial and operational flexibility in 2015 and throughout this challenging commodity-price environment.

We'll continue to drive our costs lower and generate more value where we invest, and this confidence comes from using 2014 as a proxy, and I have no doubt we will succeed.

In closing, I've said before that 2013 was our year of transformation.

2014 was our year of foundational improvement.

2015 will be a year of leadership for Chesapeake Energy.

Our determination to drive top-quartile E&P performance and our commitment to creating shareholder value are stronger than ever, and I'm confident that we are positioning Chesapeake to be a leading E&P Company.

That concludes my comments so I'm now going to turn the teleconference over to Nick for a review of our financial results and then we'll open up for questions.

Nick?

Thank you, Doug.

And good morning, everyone.

As Doug mentioned, Chesapeake has never been stronger than we are today, both operationally and financially, and we are very well positioned as we enter 2015.

We made significant progress in 2014 in simplifying our balance sheet and strengthening our financial position, primarily driven by the sale of our Southern Marcellus and certain of our Eastern Utica assets, the redemption of our preferred shares, our oilfield services spin-off, and our new unsecured credit facility we put in place.

We are confident that our strategies to create shareholder value are working.

And while the current pricing environment is not particularly enjoyable for our industry, we will continue to be nimble and flexible with regard to our capital investments, and we'll continue to take the appropriate steps to keep our positive momentum.

Our production of 729,000 barrels of oil equivalent per day for 2014 fourth quarter grew by 12% both sequentially and year over year after adjusting for asset sales.

In December, we began curtailing approximately 250 million cubic feet of gross operated gas per day in the Marcellus due to low in-basin field prices.

Other operators in the area began curtailing gas in the fourth quarter, as well.

These curtailments have totaled approximately 15,000 net barrels of oil equivalent per day, and continued in the first quarter at rates as high as 20,000 to 25,000 barrels of oil equivalent per day.

This, combined with the asset sales of our Southern Marcellus and other producing properties of 57,000 barrels of oil equivalent per day, and various downtime events of approximately 7,000 barrels of oil equivalent per day in our other operating areas, has resulted in a first-quarter 2015 production projection of approximately 645,000 to 655,000 barrels of oil equivalent per day.

I would also like to note that in our outlook we are projecting curtailment to remain in place for all of 2015.

On the pricing side lower NGL pricing due primarily to weaker ethane and other product pricing had a significant effect on our earnings and cash flow in the fourth quarter.

We also recorded the annual impact of our MVC production shortfall in December, as forecasted, which reduced our gas revenues by approximately $120 million, or approximately $0.43 per MCF.

While our hedges helped to partially mitigate the impact of lower pricing, and will continue to help us in 2015, we expect our realized pricing to remain low and have included our estimates of basis and non-basis differentials in our MVC estimate for 2015 in our press release.

Our forecast on cost discipline throughout the entire organization has helped to partially offset the effects of lower commodity pricing.

Our production expenses, production taxes, G&A expenses and net interest expense for the 2014 fourth quarter were $7.56 per BOE, a decrease of 8% year over year.

Operationally we continue to see our completed well costs decline in almost all of our operating areas.

As we become more efficient we will drive our costs even lower.

As the year progresses we believe that oilfield service cost reductions will become more apparent and, as such, we are building in an estimate of about 10% in service-cost savings for 2015 before any capital efficiency improvements by our operating teams.

Finally, our balance sheet is in great shape.

With the successful completion of the sale of our Southern Marcellus, over $2 billion in other asset sales, and the new revolving credit facility we put into effect in December, our liquidity position has never been better.

With over $4 billion of cash on hand at the end of the year, nothing drawn on our credit facility, and a net debt-to-capitalization ratio of around 29%, we are in excellent position to weather this current price environment and take advantage of opportunities to add shareholder value.

That concludes my comments.

I will now turn the conference over to the operator for questions.

(Operator Instructions)

Dave Kistler, Simmons & Company.

Looking at your reduction in wells that are going to be tied to sales in 2015, can you talk a little bit about how you're going to manage that process throughout the year?

A lot of folks have been deferring those completions for better service costs and for higher commodity prices.

Just any color on the cadence of that would be helpful.

This is Jason.

Primarily on the Eagle Ford we'll be looking to defer some of the completions.

We've done a similar analysis that you had mentioned, that our peers are doing, a little bit higher oil prices.

Definitely the value of gaining that higher price outweighs the loss and NPV of deferring that completion.

So, that's something that we'll do this.

We'll build a little bit of inventory as we continue to run rigs in an area like the Eagle Ford.

Okay.

Appreciate that.

And then just looking at the individual stats you were giving on well costs, and realizing that those are basically just through October, I imagine with the comments about 10% reduction in service costs baked into your forecast, can you give us any color where you think those well costs stand today?

Because that seemed to show a slight uptick through October.

This is Jason again.

Yes, one of the things we didn't need to do is separate the supply chain savings from our technological innovation, so we're going to see both of those this year.

In an area like the Eagle Ford, we indicated $6.1 million.

We see $5.8 million in our wells that we are drilling to date with targets of getting down to $5.5 million.

Haynesville is another area where we've seen a lot of innovation and service cost reductions.

We've got a budget.

Those are difficult to put in a dollars per well because we're drilling at least three or four different types of wells out there.

We have single unit laterals which are running around the $7 million range up to, we're trying some of these 7,500-foot laterals that can cost us almost $9 million.

And we've even got a couple laterals planned this year that would be 10,000-foot laterals that would be around the $11 million range.

But just this week we had one of our lowest cost wells go down.

And actually the field cost estimates on that were $6.3 million for a well that was just a standard section.

So, we're seeing really good improvements.

It's going to be difficult for us to put these costs in a dollar per well because we are drilling a wide range of wells out in that field.

This is Chris Doyle.

I was going to give you a little bit of color from the north assets in the Rockies.

The team peeled off $1 million from 2013 to 2014.

What we indicate is a $9.1 million well cost.

I see us, without any supply chain savings, coming in under that $9 million mark.

And then on top of that supply chain savings will push us to the low $8 millions.

We continue, as Jason mentioned, we continue to push longer laterals, additional testing.

So, we're not focused on a one well number, really focused in on value.

In the Utica the team delivered wells in that $6.5 million range.

And I see us in the low $6 millions prior to supply chain, and so we have a chance to bust $6 million there.

And then in the Marcellus, I'd see us in the high $6 millions for well costs.

Great.

I appreciate the added color, guys.

Thank you so much.

I'd also highlight, too, as far as well costs, we are getting those down.

Some of the graphs we show, that capital efficiency where we take the capital divided by the productivity, and those are some things that are difficult to see in an area like the Haynesville where we're testing tighter perf clusters, some different completion designs, more sand.

And they really drive up the EUR.

So, when we look at that, it's really that capital efficiency.

We continue to improve that and have seen great gains this year and don't expect that to stop in 2015.

So, we're really excited about the program going forward.

Yes, I just might add, Dave -- this is Doug -- we are intentionally holding production back in 2015 because we believe it's the prudent thing to do.

Which means that we're going to see some increase in our inventory.

But I'd also just remind everyone that, as you look at Chesapeake and our production-generating capability, it's one of the strongest competitive attributes of this organization.

And the ability to efficiently grow production is simply outstanding.

So, the way I'd describe it is it's like a coiled spring, and once we see that it's the prudent thing to do to increase that production we're going to unleash that spring and we will rocket forward and continue to drive a greater value for our shareholders.

I appreciate all the added color, guys.

Thank you so much.

David Tameron, Wells Fargo Securities.

Doug, can you just talk about the M&A environment.

There's been a lot of questions, obviously, about what Chesapeake could purchase.

Can you talk about -- or Nick or whoever -- your availability, how much financial availability you have to do something like that.

And then just any color you can give us on what you may be looking at.

Sure.

It's a great question, Dave.

With the total liquidity we have available to us, the cash position that we have, we have a tremendous opportunity.

Basically everything is open to us that we could pursue to drive the greatest value for our shareholders.

We see a lot of opportunity out there at present.

We think that that opportunity will persist through 2015.

The key for us is how do we strategically build and improve our portfolio to be more competitive for the long haul.

And we're not focused on just a single year or a single quarter.

We are focused on how we drive the greatest value over the long term.

Anything that we do is going to be focused on how we can materially improve our returns for that long term period.

We are evaluating a number of different things.

We have not publicly stated what our plans are but we will continue to look for opportunities, either bolt-on acquisition opportunities, new opportunities that we can pursue.

We also have a lot of strength in our exploration program and we'll continue to look at that.

And then we always have capital structure opportunities, as well.

So, we are in a unique position with significant liquidity and cash on hand to move quickly and, at the right time, to add the most value for our shareholders.

Can you give us any leanings, Doug, as far as gas versus oil or anything along those lines?

As you guys know, Dave, this Company has one of the best gas portfolios in the entire world.

And our ability to increase gas production from these world-class shale gas assets is just unbelievable.

So, that strength and that power we have a lot of confidence in the portfolio.

We've noted that from the existing asset base we have the capability to grow these assets to 1 million barrels equivalent per day inside a five-year time frame.

Now, obviously, prices impact that and can slow us down a little bit.

But I'd also highlight for everyone that in the latter part of 2013, to come up with better integrated, better planned field development plans, we ratcheted back our drilling program.

And there were a lot of questions about -- what's going on with that and why is Chesapeake reducing rig count?

And then we quickly went in an area like the Eagle Ford from 9 rigs to 22 rigs in less than nine months.

So, our ability to mobilize and drive value is unlike anyone else.

The capability to drive value and drive new volume growth from our assets, we've got tremendous confidence in.

And as we look at the portfolio, and we look at our margins, we have that 70-30 split of gas to liquids.

Our focus and opportunities that we believe are most attractive long term for our portfolio will be oil-weighted.

So, that's just the way I would answer that question.

Okay.

That's helpful.

One more and I'll let somebody else jump on.

If I look at just the CapEx allocation, you guys have it split out there by area.

And I look at the Utica, 25%, which, off of $4.5 billion, call that $1 billion-plus, whatever that number is.

And then I'm looking at the D&C CapEx allocation for 2014 and it looks like about half of that, yet the rigs are being cut in half year over year.

Can you just talk about -- help me true up those numbers?

In the Utica, we'll be running three to five rigs, as we indicated.

Keep in mind that the carry is rolled off in 2015.

One thing I would point out in the Utica, we are currently producing over $850 million a day.

We not only hit our exit rate of 100,000 barrels a day net, as we targeted last investor day, we averaged that for the quarter.

So that asset is performing exceptionally well.

That puts us right around our current processing capacity and compression capacity.

We'll continue to expand that a little bit this year.

But we don't see the need with the way the wells are hanging in there and the way the team is executing to run more than three to five rigs and so that's the plan for us in 2015 for the Utica.

Okay.

So is the facility number in there?

Are you running $200 million-plus a rig -- $200 million a year?

We also have a little bit of an inventory work down that we didn't see in 2014 so that will skew the numbers also.

Okay.

All right.

I'll let somebody else jump on.

Thanks, guys.

Joe Allman, JPMorgan.

Doug, could you walk us through the sequential quarterly production?

We got your full-year guidance and we got the first quarter from your presentation.

The first-quarter 2015 guidance suggests you're going to be flat through the year, but could you just walk us through that?

And, Nick, if you could just give us the details on the curtailment again, where is that and how much do you have baked in for 2015?

I'll answer that last question first and Chris may want to jump in with more details to the curtailments, they're in his area.

We started with about $250 million gross a day in December.

We have at various times through the quarter, curtailed more than that.

On the net basis, we see that at about -- it started at about 15,000 barrels a day.

At points it's been as high as 20,000 or 25,000 barrels a day.

And, so, we baked in between that 15,000 to a little bit higher number in for the year into our guidance.

Price dependent, that could come off at some point, but for now, given where the strip is, given where we see field pricing in the Northeast, we think it's prudent to assume that those volumes would stay off-line for the year.

Nick, is that all Northeast?

Yes, that's all Northern Marcellus.

And that's us plus our non-op.

Okay.

That's helpful.

Thanks.

Joe, if you look at slide 8 in that presentation, it has a simple walk-through of the production volumes basically from that record rate that we achieved in December of 770,000 barrels a day, but also shows for the quarter where we're at 729,000 and basically walking down with the divestitures, curtailments and then just some incidental downtime that brings us down to that 645,000 to 655,000 range.

And then what we are looking in that capital program is that we certainly, as you know, have the ability to ramp up our capital should we want to do that.

And if we did, you'd see corresponding production increases.

So what we have targeted right now is we're looking at all the opportunities to how we can drive the greatest value that gives us tremendous flexibility.

So, with our projection in that $4.5 billion range, which includes everything, including capitalized interest, we are very comfortable and confident in our ability to grow 3% to 5% on an adjusted basis.

And we will have significant opportunity to increase that if market conditions dictate.

Okay.

That's helpful.

And I see that, it just suggests that you're going to be basically flat 1Q to 2Q, 2Q to Q3, and 3Q to 4Q to get to that same 1Q average that matches the full-year average.

Is that fair?

It's approximately fair, yes.

I would just highlight again, Joe, I would not underestimate this Company's ability to grow efficient production.

I appreciate that.

In terms of the deferrals, is your plan to actually complete some of those deferred completions during the year or for the most part, you're going to push those off until 2016?

This is Jason.

We are pushing most of those into 2016.

We'll have an area like the Eagle Ford, for example, we'll build 100 wells of inventory.

Again, like Doug was saying, we have the ability to act on if prices change.

We can instantly bring in some frac crews and complete those wells.

So, we'll build a little bit but we would plan to push that towards 2016 right now.

That's helpful.

And then, lastly, you got into some of the M&A type opportunities you have.

But with the cash you've got, what are the most likely uses of the cash you have?

Is a significant use going out and buying bolt-on acreage or some other assets or do you have other ideas for the cash?

Basically, Joe, we have the ability or the option to do a number of different things with that cash.

We haven't shared anything yet with it but the key there is that we can invest in our own portfolio, we can use it for acquisitions, or, as I noted, we can look at our capital structure.

And we look forward to sharing more with you and the investment community as the year progresses but right now all those options are open to us.

All right.

Very helpful, guys.

Thank you.

Charles Meade, Johnson Rice.

I was wondering if I could ask a bit about the NGL pricing, not so much for the fourth quarter but really for your outlook.

I think most people are aware that pricing has been weak and ethane's got a negative frac spread, and all that sort of thing.

But I'm curious if you guys could talk a bit about what your outlook for the NGL pricing is and if that is possibly related to that negative midstream margin we saw in Q4.

And maybe as part of that, I'm looking at your guidance here where you're guiding to $48 to $52 off WTI.

Is the right way to think about that is WTI is $55 so you're guiding to $3 to $7 a barrel?

It doesn't seem right, but that's the way the math seems to work.

Charles, we are forecasting a very weak NGL pricing environment for the year.

There was a part of your question that didn't come through.

But, in general, we have a fair amount of ethane, some of which we do need to recover, given various specs.

So, we are pulled down by ethane prices, even in this environment, and pricing will be challenged this year on the NGL front.

Got it.

Thank you, Nick.

And maybe the part that didn't come through was if that was related to the negative midstream margin we saw in Q4.

Is that really attributable to the NGL pricing difficulties?

No.

That's really not the same driver at all.

Okay.

And then if I could get you guys to talk a little bit more about your overall CapEx philosophy.

And I know you guys have spent a whole lot of time, and I'm sure more iterations, than you want to talk about looking at what your 2015 plan's going to be.

But, as I look at it, you guys are one of the few companies, there may be just a handful, that are significantly outspending cash flow here.

So, could you talk about what your approach and philosophy is, especially given some of Jason's earlier comments about it's actually paying to wait right now not just on maybe service cost but also with the contango and the commodity price?

So, I'm asking, why wouldn't you maybe hit the brakes harder in the first half of 2015?

As we look at our investment opportunities across the portfolio, maintaining the underlying strength of the operating efficiencies, maintaining the strength of the leasehold position, basically what we're doing is investing at a relatively conservative rate to maintain the production and maintain all the operating efficiencies so that we can accelerate and move forward when the time is right and prudent to do so.

That's good detail.

Thank you, Doug.

Brian Singer, Goldman Sachs.

I wanted to follow up a bit on the production profile but wanted to talk a bit on the production mix side.

It seems like with much of the curtailments coming on the dry gas side, can you talk to the production mix, because it seems like when we take out the southern Marcellus production, relative to fourth quarter, that nat gas seems to be staying a bit flat and most of the liquids are declining.

I just wondered if you could talk more specifically about what your oil backlog would be and how you see your oil production trajectory over the next few quarters.

Certainly, Brian.

It's a good question.

The 3% to 5% production growth we anticipate for 2015 is comprised -- basically we see our oil volumes increasing in that 2% to 3% range for the year, and gas is in that 4% to 5% type range.

NGLs relatively flat or slightly negative for the year.

Got it.

Are you building a big backlog of oil production that you could easily bring on, or not really?

With that inventory we definitely will have opportunities for increasing our production in 2016 when we focus back on attacking that inventory.

As Jason noted a minute to go, the completion deferral in the Eagle Ford, for example, you can always bring a frac crew back and begin to accelerate the newly created inventory whenever you get a price signal to do so.

Okay.

And then given the cost-cutting that you've already done, can you just talk to whether you expect to have at or better than industry cost production opportunities from here?

And I wondered if you could also touch on the SG&A side.

It may not exactly be apples to apples but it looked like on a dollar per BOE basis that it was actually upticking here.

I would say that our cost cutting efficiency demonstrated in 2014 were like no other in the industry.

And I would look to 2014 to the value creation, the value barbarians inside of Chesapeake Energy that are driving further efficiencies and value.

And I would expect nothing less than seeing a low-cost operator, the most efficient operator in these assets, and continued improvements in our cost structure.

When you look back at the year and you look at what's been accomplished in the past few years inside of Chesapeake, this is not -- we hope to reduce costs.

This is a Company that's delivering exactly what we said we were going to do.

And I would expect to continue to see further cost improvements.

To be specific on that, then, if we fast-forward to the end of the year where do you think we could see the greatest surprise?

That you would under-spend your budget, all else equal because of cost reductions that you would see your lease operating costs fall?

Or that we would see SG&A come in below your guidance?

Brian, looking across the board, everything is a focus point for us.

Cash costs are a focus, the capital efficiencies are a focus.

We are structured and we are motivated in all the right ways inside the Company today to drive that greater value.

So, I would expect in every area for us to see improvement and what I believe the way that we are focusing material improvements in all the areas.

The uncertainty around the prices, the uncertainty in the current environment, definitely impacts the amount of rigs we have running, it affects the production rate.

But the whole focus that we have is to be prudent and conservative in our capital allocation, continue driving the things that we built upon in 2014.

And I think you'll continue to see strong operational capital efficiency and financial improvements inside Chesapeake in 2015.

And just to reiterate, one of the points that Doug was making there, you asked us what could be the biggest sources of surprise, well, if prices improve, the biggest source of surprise will be production.

Great.

Thank you.

Scott Hanold, RBC Capital Markets.

I was wondering if I could maybe ask a question again on service costs.

You all talked about a 10% reduction.

It's a little bit less than some in industry have been talking about.

Is there something regarding when you guys have locked in your contracts or where contracts go through that may limit some initial cost reductions in the system?

And, additionally, maybe give a little color -- when you spun off 77, did you have to lock in contracts at that point in time, which may have been earlier than when obviously you would have liked to given what's happened in the market?

Scott, this is Chris Doyle.

We've been working with our partners and vendors to work out a mutual solution here, and for Chesapeake that means bringing costs in line with the current price environment.

For our vendors that means having the chance to work with the most efficient operator out there, and an operator with the long-term financial stability sustainability of Chesapeake.

The 10% of D&C is not a back of the envelope number that we threw out there.

This is a rigorous scheduled out line item by line item analysis of what we see as the opportunity to drive additional capital of our system.

To your question about 77 Energy, we have the contracts in place but we also have market price indications that mean that they have to provide us with market price.

And we're seeing that market move significantly down commensurate with the current commodity price environment.

The supply chain organization that stood up 18 months ago I've been impressed with.

They are there not only to maximize purchasing power of Chesapeake but to solve what is not just a one-dimensional problem.

This is not just cost and that's it.

It's also about value.

It's about getting the best service for that cost.

And from our vendors' perspective it's not all about what they can charge us.

It's about operating efficiency and knowing that a Utica frac spread working for Chesapeake is going to put away 2 times as many stages as any other operator in the area.

So, it's a complex issue.

We've got a ton of folks working it.

I'm highly confident we're going to drive to the best solution for our shareholders.

I might just add on top of that just real quick, Scott, that the 10% is not our target.

So, don't misconstrue 10% is what we hope to achieve or that we're targeting to achieve.

We believe we'll be able to go beyond that.

Our focus and our targets exceed that.

That is just a reflection of the conservatism in our program that we expect to accomplish that, and we'll be absolutely seeking to drive greater cost reductions and that out of our program.

And the 10%, just to follow on, is not a December to December number.

We see that significantly higher than 10%.

Okay.

Understood.

Just one more point of clarification on the budget.

Is there any standby charges on the rigs that's assumed in there?

We have, both North and South, some minimal expenses in there to stand rigs down, but they're not material.

Okay.

And then one more, if I could.

On the curtailments in the Marcellus, can you give a little bit of color?

Were the curtailments, because obviously pricing's been $1 or so in some of the areas, was it because production was uneconomical or was it your positioning that we're going to just defer production for a better price at a future time?

That's really it.

2014, when I think about the Marcellus, it completely redefined the way we thought about that asset.

And rather than grow for growth's sake, to really key in on value.

And we're not going to give gas away.

And essentially what we saw was with the in-basin pricing we were better to curtail that 20,000 net barrels a day than produce into a strained environment.

We'll leverage our take away capacity, or take away to get out of basin.

And we are seeing really good out of basin realization but we're not going to give gas away in basin.

I know there's not a whole lot of dollars budgeted for the Marcellus, but why spend any dollars up there at this point if we're just curtailing gas?

We'll be running one rig up there.

There's a little bit of lease work that we have to do.

Importantly, I've continued to drive the team to look at longer-term testing in the area of the upper Marcellus.

We're going to drill some of those tests.

This is a long-term asset for us and not one that I'm ready to completely shut the rigs down.

It's not that we won't, it's just not our focus today.

It was interesting.

I was going back and we mentioned the Franclair pad in the last quarter.

It was a stark reminder to me this previous week of how far this asset has come.

Franclair pad is a five-well pad, two wells drilled back three years ago and three wells drilled last year.

The three wells drilled last year were 7,300-foot laterals versus 6,500.

They were drilled in an average of 12 days instead of 33 days.

They were drilled for $7.3 million versus $10.8 million.

And the average IP of those three wells was $22 million a day versus $6 million three years ago.

It's a completely different value proposition for this asset.

And that I just get real excited.

I'm thinking about decades of growth and value coming out of the Marcellus.

Appreciate all the clarity.

Thank you.

Doug Leggate, Bank of America.

Someone touched on this earlier about the potential cash flow CapEx balance for this year.

I just wonder if I could get your perspective on this because, obviously, although you have got some hedging in place, given where the gas price is in particular, it seems, at least on our numbers, that the cash outspend could be about 50% of your capital.

Can you give us some idea as to how you see the outspend and whether or not there's a plan in place to curtail further if things don't improve in the second half of the year?

I'm just wondering if this is like a two-step process or if the budget is pretty much set for the year.

And I've got a follow-up please.

That's a good question, Doug.

I look at it that it's an ongoing process.

I don't think it's one-step, two-step or three-step.

I think that we will be managing that capital spend, we will be looking at our activity levels, looking at commodity prices, the cash generating capability of the portfolio, and continuing to look focusing on the long-term on how we drive the greatest value for the long-term.

So it will be an ongoing process.

Indeed, we do see opportunities that we can continue to further reduce our capital.

And as I noted in some of the initial remarks, we can also ramp it up very quickly if we see that opportunity.

So, that balance of cash flow and CapEx spend for the year will be something that we're watching very closely and looking to optimize given the current market conditions.

I don't want to press the point too much but as an order of magnitude -- maybe this is one for Nick -- on your planning assumptions, what would you expect the outspend to be for this year?

Because you've done a tremendous job in capital efficiencies.

Obviously the commodities have all gone against you a bit here.

But you came in on one of the key premises was to get that spending back within cash flow.

And I'm just curious, is it marginal in your view or is it material for this year?

I'm just trying to get a feel as to how you guys are thinking about it.

The way I'm looking at it is long-term value, Doug.

The benefit that Chesapeake has today with our operating strength and our financial strength is that if we continue to invest above our cash flow based on commodity prices, which you can trust to be confident in, is that it has a long-term benefit.

And so obviously where it sits today, we will be in a deficit spending situation.

But the point there is to continue to look at the long term.

So, I hesitate to say what are prices going to be in the latter part of the year, what's the recovery going to be?

What you have is an operating and an efficient capital machine that we can ramp up or ramp down accordingly.

So, rather than guide to what a specific outspend would be, I would just ask you to focus on what's been accomplished in 2014 -- the capital efficiency, the improvements in our cash costs, improvements in the capital program.

As Chris noted, the improvements in capital efficiency, whether it be cost or EUR, across the portfolio are significant.

And so our focus is driving that value for the long term.

My follow-up, hopefully, is related, Doug, it's on the rig allocation that you've laid out in the release.

It seems that the areas getting the least reduction, if you like, are the Haynesville and the Mississippi Lime.

I'm having a tough time seeing that either of those is economic at $3 gas and $50 oil.

So, can you help us understand why they're not seeing a greater decline in the context of that pursuit of value, and whether or not, whether it's HBP obligations or midstream obligations, what's driving the decision to hold the rig count relatively steady in those two areas?

I'll leave it there.

Thanks.

Doug, this is Jason Pigott.

The Miss Lime, again, the teams have been just continually outperforming in the area.

It's one that every time we drill a well it continues to exceed our expectations.

Even at $3 gas and $50 oil we're getting 18% rate of returns out of the Miss Lime in our core.

So, they're really strong returns.

That system, what we do as we build out our water infrastructure as we go along, so it's a little bit difficult to predict some of our expansion opportunities.

But, again, the teams have continually outperformed the type curve, our Miss LIme.

We have a great position.

It's actually one of the best projects in our portfolio and one that we probably don't highlight enough.

With respect to the Haynesville, as I mentioned the teams are really just crushing it there on cost.

We do have the minimum volume commitments there that we consider when we're making our economic decisions.

When you consider that we will pay those gathering fees whether or not we drill or produce the well or not, those returns are 40% rate of return internally in the Haynesville.

They're the most economic project that we would invest in our Company right now, so they're really strong.

The teams are continually pressing the limits there.

We've tried new things like stacked laterals that have come online recently.

We've tried changes to our completion designs.

And those results have both been really positive, and they've been positive in some of our areas that have historically had lower EURs.

So the technological innovation there has just been fantastic and it really is going to expand our inventory in the Haynesville.

Additionally, we've drilled the first and are drilling the second, 7,500-foot laterals in the Haynesville, so we should have those pads online too.

And those generate very competitive rate of returns, whether or not you consider those MVCs as sunk costs or not.

In both of those programs they're one of the best investments we can make in the Company, which is why we continue to have those higher rig rates there.

And just, again, the teams have done an outstanding job of turning both of those assets around in the last year.

I appreciate the full answer.

I'll take it off line but I'm looking at the balance of outspend, for an 18% return in this environment and costs haven't fallen yet, I'm just trying to understand why the activity level doesn't fall further.

But I appreciate the answer, guys.

Thanks very much, indeed.

Neal Dingmann, SunTrust.

Just on Doug's question, in the areas, could you talk about lease obligations?

Is there anything that comes in the play?

I know most of your areas now -- talking to Chris and Jason in the past, I know most are HBP.

I'm just wondering, obviously looking at the Utica, Haynesville, Powder and the Miss, is there anything that is just significant lease obligations to speak of?

Neal, this is Chris Doyle.

As we said in the past, there's still a little bit of HBP activity up in the Utica.

We see that as probably two to three rigs and that creates that minimum rig count to continue to hold that acreage position.

No other acreage or meaningful acreage issues in the Marcellus or in Powder.

Okay.

And then, Nick, you'd mentioned about the service costs assuming some further decrease in there.

Are you able to continue to take advantage of -- if service costs continue to fall as most predict, would you continue to benefit from that?

Or do you have some already termed out?

I'm just wondering what you all have for contract license.

This is Chris Doyle again.

Contract-wise, we will continue to move with the market, up or down.

We don't lock into fixed fees, fixed rates.

We want to capture any further reductions.

And likewise for our suppliers -- if the market returns, we'll see that increase, as well.

But we don't lock into any set long-term prices, for the most part.

Got it.

Just lastly, looking on the guidance schedule at the NGL and the natural gas estimates or differentials, if you will, are those based on some of your midstream?

What I'm trying to get a sense of, when I look at that natural gas at $1.70 to $1.90, a bit lower than the past.

Is that some of your obligations that are factored in there?

Or maybe you could just talk a little bit about how those are established.

That's actually not too dissimilar than what we saw in 2014.

That includes basis differentials, that includes gathering, that includes long-haul transport.

So, that's and all in number.

And, again, it's pretty similar to what we saw last year.

What we've done is we've spiked out the MVC to make sure that it's clear what that number is.

That will be a fourth-quarter expense just like it was this year.

So, the $1.70 to $1.90 is inclusive of all the other.

Again, we are forecasting, as I noted, with curtailments being in place.

Given that we are forecasting curtailments in place for the full year we're forecasting weak North Marcellus pricing for the full-year 2015.

Thanks, Nick.

Great color.

Matt Portillo, TPH.

Two quick questions for me.

One follow-up on the schedule A that you guys put out.

Could you just remind us what WTI and Nymex prices you're assuming as the base there?

It's roughly $55 and $3 for gas.

Great.

My second follow-up question, in regards to your spending program as you think longer term around capital allocation, you've mentioned a number of times that as the commodity price warrants there's the potential to accelerate growth.

Is there a level we should be thinking about heading into 2016 and beyond that triggers that reacceleration of capital, both from an oil and gas perspective?

And where would you likely allocate capital first as you think about adding rigs or layering rigs back into the market?

I think obviously we'll be targeting to where we can derive the greatest value.

And so that's somewhat dependent on the commodities.

Obviously, the opportunities that we have in the Eagle Ford accelerate that program are very strong.

And then the gas opportunities going back to the Utica or additional rigs in the Haynesville provide us great flexibility.

And that's one of the benefits of our portfolio.

We haven't put an exact price target there, Matt, that we are saying that at this price we're going to come back in, because we have a number of strategic opportunities that we are evaluating and will continue to evaluate and how do we drive the greatest value.

One thing I would add there is with the Rockies this is an asset team that redefined themselves, as well, in 2014, prepared to run seven to nine rigs.

We're running three to four so we will be ready to pull the trigger.

2014 saw not only successful expansion tests in the Niobrara aerially but also vertically with multiple benches being tested, successful tests on the Parkman and the Sussex.

We have a successful test now in the Teapot well, exceeding our expectations, making over 400 barrels a day.

Just a ton of stacked potential in that play.

I would see us looking to that area to potentially ramp up given the right price environment.

Thank you very much.

Dan McSpirit, BMO Capital Markets.

Doug, you've seen more than one cycle in your lifetime.

How precious is liquidity this time around?

I ask the question on weighing opportunities that way in an effort to get a better sense of how cautious you may be in the current environment.

It's a great question, Dan.

Liquidity and the ability to have flexible options in this commodity price environment is extremely valuable.

And we feel like that we are competitively positioned to execute with our existing portfolio for the long haul.

We feel like that we are also very strong with respect to having opportunities to improve and build upon the portfolio.

So, that liquidity is absolutely paramount and key to giving us that flexibility.

Very good.

Thank you.

And we have no further questions in queue at this time.

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

Great.

Thank you all for joining us today.

I would like to highlight again that the accomplishments in 2014, the operating, financial and efficiency improvements inside of Chesapeake Energy, are a very solid foundation for which we will build upon despite the current commodity price environment.

I'm excited about our program.

I'm confident in the talent of our employees and the quality of our assets.

And I believe 2015 will be a very strong year for Chesapeake as we continue to drive greater value for our shareholders.

Please follow-up with Brad and the IR team if you have any other questions and I hope everyone has a great day.

Thank you.

This concludes today's conference.

Thank you for your participation.