Chesapeake Energy Corp (CHK) 2017 Q2 法說會逐字稿

Good day, everyone, and welcome to the Chesapeake Energy Corporation Q2 2017 Conference Call.

Please note that today's conference is being recorded.

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

Please go ahead, sir.

Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2017 second quarter.

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

During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements.

Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and in other SEC 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.

We may also refer to some non-GAAP financial measures, which help facilitate comparisons across periods and with peers.

For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website and in our earnings release.

With me on the call today are Doug Lawler, Nick Dell'Osso, Frank Patterson and Jason Pigott.

Doug will begin the call and then turn the call over to Nick for a review of our financial results before we turn the teleconference over for Q&A.

So with that, thank you.

And I will now turn to tell the teleconference over to Doug.

Thank you, Brad.

Good morning, and thank you for joining our call this morning.

Chesapeake continued to deliver our business as planned in the second quarter.

We have several exciting well results that prove the quality and strength of our portfolio and provide confidence in our capital efficiency and operational performance.

As a reminder, our 2017 capital program was designed to improve our margins and increase cash flow following a production decline resulting from asset sales and low capital investment in 2015 and 2016.

We are reiterating today our full year guidance for capital and production as previously disclosed.

I'm pleased to share that the value and capital efficiency of our investments continue to improve through our extended lateral expertise and completion technologies.

We are on track to deliver our 2017 oil growth target of 10%, and we expect to exceed our goal of 100,000 barrels of oil per day prior to year-end.

This production target is a leading indicator of our strategic goal of restoring the company's cash flow.

We are pleased to see the oil production coming online.

And I'd like to highlight the improvements in our EBITDA per boe, which has more than doubled from a year ago.

These are important metrics to monitor as we position the company for growth within cash flow and increase returns on capital.

Production in the second quarter averaged over 528,000 barrels of oil equivalent per day, flat compared to our first quarter production.

In July, we have already seen a significant uptick in production from the second quarter average to approximately 548,000 barrels of oil equivalent per day.

We expect our production will accelerate further beginning in August as we plan to place on production approximately 60 wells in this month alone.

In the second half of 2017, we expect to turn in line approximately 250 wells, representing more than half of our total turn-in-line wells for the year.

Just turning to the assets quickly.

In western Dimmitt County in South Texas, we are in the process of bringing online 20 wells that have some form of enhanced completion design.

Our oil growth trajectory for the company for the remainder of 2017 is primarily driven by the Eagle Ford.

For the second half of 2017, we expect to place roughly 100 wells online in South Texas compared to 61 wells turned in line during the first half 2017.

In the Powder River Basin, we are presently operating 2 rigs, and we plan to add a third rig in October.

We are very encouraged by the results we have seen from our first Turner and Parkman wells along with the early results from our first Mowry well.

Our first 2 Turner wells continue to outperform our predrill expectations.

These 2 wells have each recorded cumulative equivalent production of 224,000 barrels, approximately 78% oil; and 134,000 barrels, approximately 46% oil, respectively, after 142 and 76 days online, respectively.

We plan to dedicate the third rig exclusively to additional Turner development and place another 4 wells on production in the turn of this year.

Our first Mowry wells provide confirmation of what we estimated to be a significant resource.

While it has only unloaded 21% of the fracture stimulation fluid pump, it has reached a peak rate of over 6 million cubic feet of gas per day with a relatively short lateral.

We have seen spot rates as high as 7.6 million cubic feet of gas during flowback.

But as noted, the well is still flowing a large volume of frac fluid.

We drilled this well in a gas window essentially as a proof-of-concept well to test productivity, permeability and pressure.

And it's strategically located near existing infrastructure to minimize cycle times and maximize value.

We have taken 2 cores in the oilier area this year, and each showed good saturation.

Our plan will be to move into this oilier area and drill a longer lateral on our next well.

The Powder River Basin will also contribute to our oil growth target in 2017 as we plan to put 19 wells to place in the latter half of the year compared to 9 wells in the first half of the year.

In the Mid-Continent, our produced water cut is on the high end of expectations and putting pressure on the economics of our north Meramec wells.

We continue to redesign our completion techniques and will redeploy capital from this program as necessary as we evaluate new results.

In the Marcellus, we have begun testing different completion designs and flow capacity.

Our earlier results from the McGavin well are nothing short of outstanding.

We started flowback on the McGavin well last Friday.

And after 6 days, it has already reached a peak rate of 61 million cubic feet of gas per day, making it the highest-rate well we have operated in the Marcellus and possibly the highest rate well ever recorded in Northeast Pennsylvania.

We will continue to be -- to test enhanced completion in many of the 40-or-so remaining wells we plan to place on production in the Marcellus by year-end.

Finally, in the Haynesville Shale, we recently drilled and completed a 7,500-foot lateral well in DeSoto Parish with a peak rate of over 38 million cubic feet of gas per day or nearly 5.15 million cubic feet of gas per thousand lateral feet.

This result is particularly important because this well is located outside of the Springridge area where the majority of our recent success has taken place.

This well's performance gives us additional encouragement as we prove the concept of long laterals and enhanced completions across our entire acreage position.

We also performed our first Haynesville rig completion utilizing a new production liner.

Peak production from this refrac reached almost 9 million cubic feet of gas per day from a lateral of only 2,990 feet.

This is an encouraging result, and we look forward to doing more refracs in 2018.

In the first 6 months of 2017, we made good progress in increasing our EBITDA through growing oil production, keeping our cash costs low then reducing our market commitments and obligations by approximately $585 million.

Looking to 2018, our operating and capital efficiencies provide significant flexibility in capital spending.

And of significant note, free cash flow neutrality is achievable at $50 oil and $3 gas in 2018.

We are prepared to adjust our 2018 capital program and production growth targets based on market conditions.

Our key priorities are unchanged for the company.

Further reducing our debt is our top priority while continuing to improve our operating performance, capital efficiency and EBITDA margins.

We are resolute, determined and confident in our ability to achieve our strategy and to deliver differential value to our shareholders.

I'll now pass the call to Nick to share further details on our second quarter financials.

Thank you, Doug, and good morning, everyone.

We're pleased with the results for the second quarter.

Our production grew 2% sequentially after adjusting for asset sales.

As Doug mentioned, our production started to move higher in July, and we expect that our multi-well turn-in-line projects in the Eagle Ford, Utica and PRB will provide strong oil production acceleration in the third quarter.

On the cost side, we expect our combined production and G&A expenses to move lower in the second half of 2017 on a per unit basis.

This is despite a modest increase in G&A costs as -- primarily as a result of asset sales.

We've reduced our producing well counts in which we had a working interest by over 24,000 gross wells over the last 18 months, primarily driven by our divestitures in the Mid-Continent, Barnett and Devonian areas, reducing our overhead recovery on producing locations.

Regardless, we expect these combined metrics on a per boe basis, particularly LOE, to continue to decline in the last 6 months of the year.

Our gathering, processing and transportation expenses improved sequentially on a boe basis.

And we reduced our oil and NGL GP&T guidance along with our basis guidance on oil.

We are currently projecting an improvement in our oil basis by $0.30 per barrel, due in part to strengthening market conditions in the U.S. Gulf Coast and a flatter contango oil curve, along with several successful marketing development initiatives across all 4 oil basins in our portfolio.

On the gas side, although our basis for the first 6 months of the year came in better than we had anticipated, we are maintaining our basis guidance due to the recent pressure seen in the Northeast with the delays of Rover and the Nexus pipeline.

We increased our income statement interest expense guidance primarily as a result of accounting adjustments related to the $750 million debt refinancing we completed in June.

This is primarily a function of refinancing the second lien notes that were accounted for under the troubled debt restructuring accounting rules where the second lien notes have a GAAP carrying value premium that depreciates over time.

With the tender, we saw an acceleration of a portion of that depreciation that was previously an offset to reported interest expense.

Notably, our cash interest expense was virtually unchanged as a result of the June refinancing.

Regarding our cash position.

As expected, we have used the cash balance we started the year with to retire debt and other obligations and now sit with a $575 million revolving credit facility balance and $3.1 billion of available liquidity.

Related to our core business, total CapEx has outpaced EBITDA by approximately $200 million year-to-date as we restore the company's cash flow-generating capability.

Separately, we have retired debt of approximately $1 billion inclusive of tender settlements, open-market repurchases, calls of near-term debt and debt maturities.

We've paid legal settlements and judgments of approximately $500 million, including the Bank of New York litigation; paid approximately $400 million in buydowns of marketing contracts; and paid interest in preferred dividends of approximately $450 million.

All this activity was offset by sales proceeds of approximately $950 million to date.

This outspend was in line with our expectations for the first half of the year, and as a result, we have reduced debt, improved our working capital deficit and improved our profitability on a go-forward basis.

On the A&D front, following the close of our Haynesville Shale assets in the first quarter, we have sold or agreed to sell multiple additional producing properties and acreage for approximately $360 million to date.

We expect approximately $265 million of these signed asset sale agreements to close in the third quarter.

The production impact of the assets sold to date in 2017 is minimal, about 16 bcf of gas.

Since we have not adjusted our total gas production guidance for the year, it's also a reflection of the productive power of our remaining gas assets.

We continue to work other noncore asset packages, particularly the Mid-Continent area as well as larger assets as we work toward our goal of removing $2 billion to $3 billion of debt from our balance sheet.

Finally for 2017, we currently have approximately 74% of our remaining projected gas production hedged at $3.09 per mcf and approximately 60% of our remaining projected oil production hedged at approximately $50.32 per barrel.

Using the midpoints of our production guidance, we have also hedged a meaningful portion of our 2018 gas production hedged at $3.09 per mcf and have added to our 2018 oil hedges, which have an average hedge price of around $49.87 per barrel.

Operator, that concludes my comments.

I will now turn the call over to you for questions.

(Operator Instructions) And we'll go first to Neal Dingmann from SunTrust.

Doug, my first question really is just about your comments this morning about the potential upcoming reallocation of capital, specifically besides bringing that rig in the PRB, could you talk a little bit -- I think in the prepared release, you mentioned about potentially reducing spending in certain areas altogether.

So just any color you can give on where you might reduce altogether and in the reallocation you could give us more color on.

Sure, Neal.

Thanks for the question.

The reduction in our rig activity has been part of our pro-capital program all year.

And as we noted, we intended to average 17 rigs for the year.

We've been high to that a little bit, and we planned on reducing our rig activity in the latter part of the year.

So this is really consistent with our plan.

Keep in mind as well that the flexibility around our program today is we have tremendous optionality to direct our capital towards where we see the best returns based on market conditions and based on the results of our investments.

That capital efficiency and flexibility the company has is something that I consider to be one of our competitive strengths.

As a result of that competitive strength, we are in excellent position to reduce our capital or increase our capital based on market conditions.

And we're prepared to do so.

With the hedging protection that we have in place for 2017 and our goal of restoring that cash flow after these asset sales and the reduced activity in the past few years, we feel very comfortable and very confident that the extended lateral program, our completion efficiency and the results we're seeing in some of these areas such as Powder River Basin, this monster well we've seen in the Marcellus and the continued improvements in the Eagle Ford that -- where there are bigger -- we're pumping bigger fracs and seeing good results from it.

So we're in great position to perform exactly as planned.

It's noted as a reduction in drilling activity, but it's really -- just it's the allocation of capital towards where the best investments for our strategy are to be located.

And as we look forward to 2018, we are in excellent position at $50 oil and $3 gas to be free cash flow neutral.

And we're prepared to adjust that program as necessary.

Good point.

And just lastly, by my numbers here, certainly, your cash flow, it's been coming down dramatically, but could you talk about, in addition to that -- you mentioned the asset sales, I think around $360 million to date, how you see those sort of shaping up the rest of the year and into '18?

Certainly.

So the asset sales, we're pleased with the progress we've had to date, but we are not done.

We see several other opportunities that we look forward to sharing with you as the year progresses.

Keep in mind that we have a stated goal of $2 billion to $3 billion of further debt reduction to reduce the leverage on our balance sheet and to make the company more competitive.

And we still are very confident.

Keep in mind that this company has a tremendous land position and a tremendous number of assets, high-quality assets.

We've got a significant resource potential in each of those assets, and that gives us a lot of flexibility as what we choose to divest of.

And as we test concepts and test new plays with the extended laterals and the completion technologies, we are narrowing in on value and what we think are proper prices to divest of any additional assets.

So we will continue the divestment program.

We've not put a target out for the year, but what you can expect is we'll continue to be divesting of noncore assets and looking to further strengthen our balance sheet with the proceeds.

And we'll go next to Brian Singer from Goldman Sachs.

Wanted to further focus on a couple of the assets that you discussed in your comments.

First is the Mid-Con.

I think you made some comments in your prepared remarks with regards to some higher water cuts and redesigning completions.

Can you just give us -- and take a little bit of a step back on the various Mid-Con plays that I think were areas of focus, going back to the analyst meeting last year, and how you see the path forward?

Brian, this is Frank Patterson.

So in the Mid-Con, the Oswego, which we've been pushing hard on, that is a play that's really working for us, but we've always said that has a limited running room.

It's a relatively small footprint.

We're going to continue to push on that.

And we've seen really good results, over 1,000 barrels a day in most of our wells.

In the Meramec, the hydrocarbon content is there.

What we're struggling with is, as we frac these wells, we believe we're probably fracking out of zone and down into the Mississippian, which is a high-water cut type of a formation.

So we need to redesign our completions.

And because the water cut is higher than we -- on the high end of our expectations there, we're going to slow down just a little bit, redesign, rework the G&G, rework the engineering.

And we'll probably redeploy some capital out of that asset and then come back to that as we understand how to redesign the completion.

Great.

And my follow-up is on the Marcellus.

You highlighted the very strong well there and your interest in potentially reallocating -- maybe it's a perception of reallocating capital.

Can you talk a little bit more to that point?

To the degree that we have new pipeline capacity coming online to you that improves local prices in Appalachia, how aggressively should we look to Chesapeake to add capital and what you think the production impact to be?

Okay.

Thanks.

First, I'm just really, really happy to call out the team on this.

They were looking around the organization at the completions that have changed many of our fields and said, "Hey, what if we do that in the Marcellus?" So they did a great job of challenging themselves and coming up with, "Okay, how could we optimize and make the best Marcellus completion possible?" Kudos also to the field team for safely and efficiently bringing a well that magnitude on.

That's an incredible achievement.

We had to basically redesign the surface facilities.

As you can imagine, we're not used to bringing on 60 million a day wells in the Marcellus.

So that's great.

As far as the Marcellus as we see it today, we have been producing pretty steady in the 2 to 2.2 bcf a day, and that's our capacity as far as being able to get pipe out -- gas out of the field.

We are still looking for more opportunities, which are -- this is great rock, and we can step on the accelerator.

But I think the more important thing about the big well is it tells you how -- first how good the rock is because this is in a developed portion of the field.

It's not an outlier.

It's kind of in the heart of the field.

Secondly, as we push these better completions and longer laterals, it's going to speak to the capital efficiency.

We're going to have less capital in the ground for the same gas, which is pretty substantial.

And then the third and probably the most important thing for the future is this is in the core of the field.

But just like in the Haynesville, this completion design, this well design, if we move it out into the -- what we consider the less prospective area, the less core area, we can actually change what the core is in this field.

And our footprint of really high-quality gas is now probably expanded substantially.

I might add, Brian, to Frank's comments that this company is all about capital efficiency.

And the benefit of our portfolio as we deploy capital and the expertise that we have from all the wells we drilled, all of the completions that we pumped, it just gives us tremendous flexibility and optionality to direct the capital.

Whether it be from Mid-Continent to Marcellus to Powder River back to Haynesville, we're just going to continue to improve.

And we take these learnings and are seeing excellent results.

And we're recognizing core expansion based on those technologies.

And so the -- what we consider to be one of the strongest attributes of this company with our capital efficiency is the strength in this portfolio and the diversity that it provides to us.

It's a significant value lever for the company.

Appreciate the comments on the resource and the timing.

From a capital allocation perspective, should we expect you to be adding rigs in 2018 in the region, in Northeast PA?

Brian, the -- right now, we have about 2.2 bcf a day cap on our capacity.

So what you might see us actually do is, in 2018, we may deploy less capital and allow more capital to be put on other assets until we get additional takeaway capacity.

And we'll go next to Charles Meade from Johnson Rice.

I wanted to pick up, I guess, maybe where Brian left off.

And again, those are really impressive results, and it's good color you've given on the Marcellus well.

But I wonder, just keeping with your theme of capital efficiency, can you give us an idea for what the incremental cost of this well was over your typical design?

Or maybe if you don't want to give that, a sense of what that incremental capital efficiency was, and if it's not where you wanted to be, whether it can improve?

Are you sitting down, Charles?

No, I have a standing desk model.

So I'm teasing, yes.

So I'm sitting now.

Okay, Charles.

Hold on to your sideboards to your desk there.

So this well is a little bit more expensive than the wells we drill.

And this is a 10,500-foot lateral with a relatively aggressive frac on it, about $8.5 million.

That's the field estimate today.

These are early numbers, of course, because we've only been on for about 6 or 7 days.

But we believe that we can get that cost down as we go forward.

Well, I'll tell you what, I'm out of my chair and on the floor now.

Okay.

Jason's team has done a great job.

I'd love Jason to put a little color on that as well.

Well, as far as they -- the team, again, they were trying to figure out how to get 60 million a day out of one of these wells.

And they -- actually, they call it the Rambo frac because they needed to attack that formation like Rambo would a POW camp.

So they increased the cluster efficiency and attacked that with 32 million pounds of hell on earth.

So we succeeded in setting the captive gas molecules free.

All right.

If I could ask a question about the Haynesville also, the -- that 40 million a day well outside of the core is certainly remarkable.

But to me, that -- what caught my attention more was that refrac of that early well in that rate you got from, frankly, a short lateral.

So can you talk about how that came in versus your expectations?

And I know, Doug, you mentioned in your prepared remarks you're planning on doing more of that.

But can you elaborate a bit on where that fits in your outlook for 2018 and perhaps where it ranks in the stack of capital efficiency or attractiveness?

Yes.

This is Jason again.

We're really pleased with the well.

Again, we're just continuing to optimize the Haynesville and focus on those designs.

I mean, we started last year with 55 million pounds.

Now that's a little bit bigger than we actually needed.

So what's great about this well is that we're pumping less sand, and we did hit at the 5,000 pounds per foot and still getting these really strong reserves -- results.

So again, just optimization from the team, it's more than just sand.

It's the number of clusters that we treat, the distance between the first, and all those things come together.

And each well is unique, and they're unique even within the field.

So they've really done a great job of trying to customize the jobs for the rock that we have in each of these parts of the company.

And the refrac, Jason?

Oh, refrac.

Refrac is good.

Again, it's 9 million a day.

It's our first one that we've tried a liner on, which gives us a fresh piece of pipe to work with.

There's 2 ways to do these refracs.

One is to treat the whole well and then pump diverters in one giant job versus putting this liner in place.

So it's still early, so we don't have EURs.

Costs about $3 million, what we expect to do on a regular basis.

So compared to a few years ago, we were drilling and completing new wells for $8 million and getting 12 million a day IP, that's been [$3].

Our first refrac of this type, I think, is a good step forward and opens a lot of potential for us in the future.

And we'll take our last question from David Tameron from Wells Fargo.

Eagle Ford, the Upper Eagle Ford, that -- obviously a very good well there.

Can you talk about how many more you have planned for this year and remind me of your potential kind of locations there longer term?

This is Frank again.

We are going to continue to work the Upper Eagle Ford into our program.

What we've come to the conclusion is that it probably needs to be a co-development associated with the Lower Eagle Ford both for efficiency and ultimate -- the best completion design.

So we are currently reworking that.

Kind of the western portion of our field has Upper Eagle Ford over it, and we are working on what is the best spacing associated with that.

As we've seen these bigger completions, we're looking at, should we adjust our spacing assumptions maybe a little bit further apart and driving capital efficiency by doing that?

Okay, that's helpful.

And then jumping over to the Powder, it sounds like for the -- I'm just reading the press release, right?

The rest of the year, you're doing some of the Turner, some of the Sussex.

I think in the past, you've tested the Parkman and the Niobrara.

Can you just talk about -- just step back and give us a big-picture view on the Powder and kind of where you see the most potential?

And where -- when we think about 2018, where do you expect the activity to be focused?

What we've seen so far in the Sussex and the Turner, those are probably the lowest-cost producers we have in our inventory.

Those are low $30 breakeven prices.

Now we're going to step on the gas on those.

We will focus on those.

The Sussex, we are drilling -- we are basically in development mode.

It goes at the heart of the field.

And we will be bringing a bunch of those wells online here in the next 2 to 3 weeks.

The Turner has been fantastic.

We've basically drilled the edges.

We have not drilled the core of the field yet.

We are now moving rigs into a more core area.

We've learned quite a bit about the GOR across the field, which is -- it changes slightly, but the pressure has been good.

The deliverability has been outstanding.

So we're going to continue to tweak our completions to optimize these.

We're drilling longer and longer laterals now, both in the Sussex and in the Turner.

So you're going to see us focus in -- the rest of '17 and into '18 and into '19 on those 2 plays.

The Niobrara, what we determined to date is that completion matters.

And so the bigger completions really changes the dynamics of that play.

We will continue to work that into our plan.

Parkman is good.

It's just not a large player on our acreage position.

So we're going to focus on our best economics.

We're pretty excited about what we've seen in the Turner.

And I'm really, really excited about what we -- what I anticipate the Sussex is going to do here in the next few weeks.

Okay.

Just one -- I'm just going to sneak one more in.

So Mowry, you guys talked about validating the concept, I think is what you put in the slide deck.

Can you just give us what you saw from that and what it means -- just what you learned from that well?

We have drilled no Mowry wells on our acreage.

There had been Mowry vertical penetrations on our acreage but no horizontals.

We knew that formation would be higher pressure and potentially naturally fractured.

So what we did was we decided to drill a well where we had access to pipes so we could maximize the value of what we were testing.

So we went to kind of to the center of the field where our gas pipe -- gathering system is robust and drilled a 4,100-foot lateral.

We did not want to take a big bite on this because the Mowry in the area has always been notoriously difficult to drill horizontally, but we got a really good 4,100-foot lateral.

We've put a very large frac on it.

Honestly, didn't really want to talk about it this early because we're early in the flowback.

We're only about 20-plus percent of frac fluid back, but the well came on gas almost instantaneously.

And it's been a pretty stout gas well.

Until we get it unloaded, we just don't know what it's going to do.

We've taken 2 cores in Turner wells.

The Mowry is just below the Turner.

We've taken 2 cores this year.

Those cores are in our lateral.

We've analyzed them.

They have good saturations of gas and oil.

So the next test we do will probably be up in the oil or wet gas realm to see what we can do as far as getting a hot one, a longer well, a higher-rate well.

Not knowing what this one's going to do, we don't know what it's going to do.

But a higher-rate well and a better economic well.

So that is in the testing stage.

Powder, the way I look at Powder in the near term is Sussex, Turner and probably Niobrara, Mowry is something that will come on the back side of that.

Okay.

We appreciate everyone joining the call today.

For any additional questions, please contact Brad.

We're excited about the things we're executing upon but certainly see a lot of potential and opportunity.

Just to highlight again, we're executing as planned with our program, reiterating our guidance on capital production.

But the capital efficiency that we continue to improve upon is something that we will be taking advantage of across the strength of our diverse portfolio.

So thank you all, and hope everyone has a good day.

Ladies and gentlemen, that does conclude our conference for today.

Thank you so much for your participation.

You may now disconnect.