Chesapeake Energy Corp (CHK) 2016 Q1 法說會逐字稿

Good day, everyone, and welcome to the Chesapeake Energy Corporation Q1 2016 conference call.

Today's conference is being recorded.

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

Please go ahead.

Thank you and good morning.

And thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2016 first quarter.

Hopefully you've had a chance to review our press release and the updated slides 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, and 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 note that, except as required by applicable law, we undertake no duty to update any forward-looking statements, and you should not place undue reliance on such statements.

With me this morning on the call are Doug Lawler, our Chief Executive Officer; Nick Dell'Osso, our Chief Financial Officer; Jason Pigott, our Executive Vice President over the Southern Division; and Frank Patterson, our Executive Vice President of Exploration and the Northern Division.

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 now turn the teleconference over to Doug.

Thank you, Brent, and good morning, everyone.

I trust everyone's had an opportunity to review our press release from this morning.

We're continuing to make solid progress in reducing our costs, strengthening our balance sheet, and optimizing our portfolio.

Starting with the portfolio, year to date we have closed or have under signed purchase and sale agreements approximately $1.2 billion of gross sales proceeds.

This is up approximately $500 million from our earnings call in February.

As previously discussed, certain of these transactions are contingent upon the repurchase of VPPs, so net proceeds from these property sales will be approximately $950 million.

On the February earnings call, we guided to an additional $500 million to $1 billion in gross proceeds by year-end 2016.

With our announcement this morning, we have already achieved the lower end of that range.

In February we stated that the closed sales and signed purchase and sale agreements targeted smaller, non-core, non-operated properties.

As noted in today's press release, we are divesting to Newfield Exploration a portion of our STACK acreage position in northern Oklahoma for approximately $470 million, maintaining the objective of divesting smaller, non-core assets, and in this case, principally non-operated acreage.

While we believe the play is highly economic at today's prices, the value acceleration from this currently undeveloped, principally non-operated acreage position is highly accretive and allows us to direct cash to our balance sheet, creating greater value for shareholders.

The year-to-date asset sale agreements have minimal impact on 2016 and 2017 production and EBITDA.

For 2016, total production is projected to be reduced by roughly 5% due to the announced sales, or approximately 35,000 barrels of oil equivalent production per day, of which, roughly 60% of that represents gas production.

The 2016 EBITDA impact is also minimal, currently estimated to be approximately $20 million, using today's strip pricing.

We continue to focus on improving our margins, not only by addressing the cost side of our business but also working to reduce our operational leverage and midstream commitments.

Our operating and G&A costs continue to fall, and, together, were 28% lower in the first quarter on a per barrel of oil equivalent basis compared to the first quarter of 2015.

We intend to further expand our margins through continued discussions with our midstream and downstream partners on several fronts to find mutually beneficial solutions that will increase EBITDA.

These efforts are ongoing as we speak, and we believe we will have more to share as the year progresses.

Nick will speak more about our balance sheet and liquidity in a moment, but I wanted to note that we successfully reduced debt that matures in 2017, or that can be put to us in 2017, by $282 million in the first quarter, with the potential for additional debt exchanges, open market repurchases, and the capability to issue additional secured debt.

In addition to our sufficient liquidity, we have several tools, as you can see, at our disposal, to handle our 2017 maturity obligations.

In closing, Chesapeake continues the ground game progress, working hard to advance our strategies while improving our financial and operational strength.

This process and journey begins with each highly motivated Chesapeake employee.

Our employees have worked exceptionally hard over the past three years to improve our Company, both operationally and financially.

We are actively working on liability management initiatives, and our balance sheet is getting leaner and less complex.

Asset sales are progressing and are providing additional fuel for our collective efforts.

I want to thank all of our shareholders who have stayed with us during these difficult and tough times, and I encourage other investors to keep your eye on Chesapeake.

Our outstanding employees, combined with high-quality assets, industry-leading capital efficiency, cash cost leadership, and further balance sheet improvements will drive further value creation.

We look forward to discussing further progress on all these fronts throughout the year as we prepare for operating in a time of greater commodity price stability.

I will now pass the call to Nick, and then we will open the call up for a few questions.

Thank you, Doug, and good morning, everyone.

As Doug has stated, our priority is the continued refinancing, exchanging, and reduction of debt from our balance sheet, specifically debt maturing in the next 18 to 24 months.

We continue to look at all of our options, including the use of additional secured debt, private transactions with bondholders, and other types of exchange offers and open market purchases to manage these maturities.

As you are aware, in April we amended our revolving credit facility to receive significant relief on our covenants and expand our flexibility with respect to issuing new secured debt, while reaffirming the $4 billion borrowing base through at least March of 2017.

In return, we pledged additional properties.

As of March 31, we had approximately $619 million of revolver capacity utilized for letters of credit, the majority of which were supporting the surety bond related to our 2019 notes litigation.

So while we are pleased to have shored up our current liquidity position, we are squarely focused on utilizing the flexibility granted under our credit facility amendment to refinance or exchange our pending 2017 and 2018 debt maturities.

On the expense side, we expect our cash costs, in aggregate, to continue to decline throughout the year.

You may have seen in our outlook that we lowered our production expense guidance due to additional cost savings.

We have also adjusted our total gathering, processing, and transportation expense estimate down due to lower costs we are seeing for both gas and NGLs, partially offset by higher stabilization fees for our Utica oil.

The reduced costs on gas and NGLs are the result of closer alignment with our midstream partners on future capital expenditures, as well as optimizing usage of contracts and negotiations.

The oil stabilization fees will allow us to reduce vapor pressure and improve API, providing more marketing options to downstream pipes and access to better prices.

As a result, we expect to see our basis for oil improve throughout the year.

As Doug mentioned, we continue to have meaningful dialogue with our midstream and downstream partners to further reduce and optimize our gathering, processing, and transportation agreements.

We will keep you posted on any new announcements as they happen.

We also increased our interest expense guidance recognized on the income statement due to a decrease in expected capitalized interest, so that change will have no cash impact.

Since we last spoke to you in February, we have layered on additional hedges for 2016 to help increase our cash flow.

We have approximately 476 Bcf of our remaining 2016 gas production hedged at $2.71, and approximately 18.2 million barrels of our remaining 2016 oil production hedged at $46.32 per barrel, representing 64% and 69% of our Q2 through Q4 2016 gas and oil volumes, respectively.

We have also started to add some 2017 hedges at recent prices.

So, to close, we are continuing to deliver on our 2016 plan, as we outlined in February, to maximize liquidity, optimize our portfolio, increase EBITDA, and reduce our debt.

We have achieved a bit more success in the A&D market with our announcement this morning, and that has no impact on our borrowing base under our revolving credit facility.

We are attacking the challenges of our financial and operational leverage and continue to work on many fronts to make Chesapeake a stronger company, regardless of commodity prices.

We look forward to being able to talk with you about those later this year.

That concludes my comments.

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

(Operator Instructions).

Neal Dingmann, SunTrust.

Congratulations on the sale.

Say, Doug, your thoughts -- reasoning for just the -- I'm wondering on the piece you did sell, and the piece you kept, is it just positioning as far as -- any color you can add on the piece you sold versus why you kept the other piece.

Yes, sure, Neal.

We really like the STACK.

We talked about it in the past, and we feel very confident in our position.

This transaction with Newfield we think is mutually beneficial to both companies.

We still have approximately half of our STACK acreage in the play, with other significant opportunities, as noted in the past, and particularly like the Oswego that we still really like and are encouraged by.

What we know here is that this position, it's for Chesapeake, the amount of funding that we're going to put towards it in the near-term.

And the value acceleration opportunity was just compelling for us, at this point in time.

So, bringing those proceeds in versus investing the capital over a multi-year period for Chesapeake, it was in our best interest to divest of the property.

So, as we evaluate other assets, the non-core areas that, in many cases, are non-operated properties, we will continue to look for those to continue to apply proceeds toward our capital structure or other corporate investments.

So, I think it was a good thing for the Company and a mutually beneficial transaction.

Doug, are you saying that mostly further sales to get to that 1.2 or so -- or I guess you are already there -- but beyond that, would be more likely to be more non-core?

I'm just wondering, things like parts of the Eagle Ford or parts of the Utica, which obviously are great asset positions, how do you view things like that?

Or are you just looking at more non-core sales going forward?

At this point in time, it's really more non-core that we're looking at.

And just highlight that in February, Neal, we said $500 million to $1 billion for the remainder of the year.

Having accomplished the lower end of that range, we will continue to look for those incremental, non-core sales that are not going to materially impact our production or our EBITDA position.

Got it.

And one last one, just looking again at that slide 13, where you show about the amounts that turned in line versus the spud.

Obviously looks like the activity, no surprise, was focused in the mid-con and the Haynesville.

Is it fair to say for the remainder of the year that will be continue to be the focal as far as spud versus the TIL?

Yes, I think that's fair.

Okay.

Thank you very much.

Congrats again.

Brian Singer, Goldman Sachs.

Wanted to just get some updates on how you are thinking about capital allocation and backlog in a couple of the natural gas plays.

First, where you stand with curtailed wells and -- or curtailed production, as well as uncompleted wells in the Marcellus.

And then in the Haynesville, can you just talk to plans for the year and how that could change, if at all, based on natural gas prices?

Yes, Brian, this is Frank Patterson.

In the Marcellus, we are making about 1.8 Bcf a day.

We've seen a little bit of uptick in price recently, so we're doing well there.

We have about 350 million a day curtailed.

These are wells that we can ratchet up as the market allows.

And we have about 200 million cubic feet a day on wells that need minor repairs to bring back online.

So, a substantial amount of gas available to us at a very, very minimal cost associated with that; and we will manage that as the market allows.

We have about 100 wells sitting back waiting to be fracked, so that will give us another 450 million a day.

So we have a little bit over 1 Bcf a day available to us at a pretty reasonable cost.

This is Jason.

I'll give you a little update on the Haynesville.

We've got some really exciting stuff going on in the Haynesville.

We've brought on our first two 10,000 foot wells.

They're doing fantastic.

They're both coming on at 22 million cubic feet a day and nearly 8,000 pounds, so we've had some really positive results in the Haynesville.

These wells, we expect to get the costs down to about $8.5 million.

What's great about that for me is a couple of years ago when I came into the role, the teams were making 4,500 foot laterals at $8.5 million a well.

So we've seen wells that are twice as productive at the same costs we were two years ago.

So it's been a huge efficiency gain for us.

Because of our agreement with Williams, we will continue to run three rigs there this year.

We are also pulling down our inventory.

We had 31 wells in inventory at the beginning of the year, and expect to be at eight wells by the end of the year.

Great, thank you.

And then on the topic of midstream, can you just talk about any updates, as applicable, on some of the midstream commitments, and whether there's anything that we should expect in terms of renegotiations or updates?

Thank you.

Sure, Brian, I'll take that.

It's Nick.

We remain in constant dialogue with Williams on a number of fronts, as well as some of our other downstream partners.

And you've seen us have a variety of success across a number of fronts this year to align our current operating activity to current market environment with the contracts that we have in place.

And we've had very good receptivity from all of our partners to do that.

With respect to Williams, you did see that we lowered our gas gathering outlook by $0.05.

And that just really comes down to, as we set the cost of service for the year, an alignment around what our activity plans are, where to spend money, how much to spend, and how that rolls through the calculations.

So that's minor evidence -- although it does generate a pretty reasonable amount of capital, of course -- minor evidence of how we can continue to work together to optimize around existing structures.

Negotiations on new structures, like I said, do continue, and we are making good progress there.

And we will just have to ask you to hang with us.

Obviously we have had good success over the last year there, and are confident that we will continue to have more in the coming months.

Thank you.

Matt Portillo, TPH.

Just an additional follow-up question on the Marcellus.

As we think about capital allocation decisions for the next few years, you guys obviously have a lot of productive capacity behind pipe.

But the market remains fairly dynamic in terms of takeaway capacity, with some delays that have been announced recently.

As you guys look at that asset and compare it maybe the Utica and the Haynesville from a rate of return perspective over the next few years, how does that fit into the stack in terms of capital allocation?

And longer-term, does this still fit in terms of the core strategy from a development perspective going forward?

Or are there potentially opportunities to extract additional value from an asset sale perspective, in plays like the Marcellus where we've seen an uptick in A&D activity as of late?

This is Frank Patterson again, Matt.

We have gas that we can manage our production rates to a very manageable -- no decline, basically, which is a great opportunity for us in the Marcellus.

As far as the delays that we've seen, we were not on constitution, so that's really not something that we were counting on.

We did have a small amount of gas that we wanted to put through net.

Of course that's apparently gone now.

So, we have an opportunity here to really manage this field to a really nice, no-decline position, with very little capital.

If you go to page 13 on the slides, you'll see that we're really not putting a lot of capital into the Marcellus because it doesn't need capital.

As far as monies being spent in the field, it is going to the Utica.

The Utica has access through -- open to the Gulf.

And we are going to be putting on additional Utica dry wells this year and next year, and drilling some additional Utica dry wells going forward.

As far as sales or divestitures of assets, Marcellus is a core asset.

There are parts of the Marcellus that might not be core, and we would consider that with the right price.

Utica, we're pretty happy with our position.

I might just add on to Frank that the Marcellus is an incredibly powerful asset: stability in production, significant upside in terms of future opportunity there in the Marcellus, the Upper Marcellus; an ultra-low cost operating team up there.

It just presents a significant high-return opportunity for us.

Obviously the gas position and getting the gas out is the key issue.

And we will continue to monitor that, and ready to invest there when the opportunity presents itself of getting more gas out of the basin.

Great.

And just a follow-up question to Brian's on the Haynesville.

You guys have seen some pretty significant improvements over the last few years on completion innovation in the basin.

I was wondering if you could just give us some context around maybe your thoughts on breakeven economics within the context of the Haynesville.

As we look at the forward curve for 2017, I know that's starting to come up on the horizon from a discussion perspective.

But is this probably the area where you would first allocate incremental capital as we roll into 2017 as that forward curve plays out?

Well, I guess I'd have to go back to -- we've got a lot of exciting things still left in the mid-con.

We have 1.5 million acres there, so we've got really strong economics there.

And then our Eagle Ford has experienced a renaissance, as well, with the longer laterals.

So those are still preferentially, if we're spending more dollars, those plays always look a really strong.

In the Haynesville, again, we are continuing to improve.

We are getting close to 20% returns at the strip here, so it's hard to explain how impactful these long laterals have been to that play out there.

Because we see no degradation in performance with these 10,000 foot wells, so we're getting double the production for effectively half the cost out there.

We also have a new play there I didn't mention on my first set of comments.

We've got our first 7,500 foot Bossier well that's flowing today, and it's 17 million cubic feet a day at 7,300 pounds.

There's a lot of exciting things going on in the Haynesville.

But our Eagle Ford team, they are drilling -- plan to drill for this year 9,800 foot wells, on average, which is nearly double what they were couple of years ago.

So their returns have gone through the roof, and we're actually -- our returns today in Eagle Ford, with the current cost, are about the same as when oil was $80.

It's just significant how much of a change the Eagle Ford team has made there.

We had wells coming on a year ago at 500 barrels a day.

Our latest wells are coming on close to 1,000 barrels a day.

So we've had just a huge transformation in the Eagle Ford team over this first quarter here.

But for me, again, if I'm fighting for capital, that's the area I want to send it first.

Great.

Thank you very much.

Charles Meade, Johnson Rice.

I was wondering if I could ask another question about the Meramec sale.

And looking specifically at your slide six, that map, if I'm interpreting it right, it looks what like you guys have retained is the down dip or gassy portion.

And I'm curious, am I looking at -- am I interpreting that correctly?

And if so, is that an expression of your preference that you think that asset or that portion of the play is the higher upside now?

Or is that more a function of where the inquiries were for the acreage that you might want to sell?

So, just to reiterate that we really like our mid-con position; continue to believe it's a significantly undervalued asset in our portfolio.

Specific to your point, Charles, we see upside in the Meramec in the remaining acreage that we have.

It's not necessarily all gas, or more gassy-related.

And we see other significant opportunities with the Oswego that we've noted before.

When you look at our position, we've got what we believe to be still good upside opportunity.

And we will be balancing the investments across oil and gas in mid-con, where we can get the best return.

Do you want to add anything to that, Jason?

Now.

Again, when we would talk about the acreage we retain, we're focused on the yellow in the Northeast part of Kingfisher County up there.

That's where the Oswego acreage is that we looked at.

But we had it on one of our releases a while back, just map of all the stacked plays in mid-con.

They are much larger than just this small stacked area.

We've struggled to come up with a name of what we would call the stack, as we've got Miss Lime wells that, again, continues to get downplayed but have fantastic results out of the Miss Lime continually.

But there's just all kinds of stacked plays that are -- there's new tests going out on the mid-con all the time, and because of our large acreage position, we are set to take advantage of those.

And we've got some new prospects that I'm really looking forward to talking to you about as this year progresses, and into next year.

Because our G&G teams are just really fired up about all the potential they see in mid-con.

It's more than just the Meramec.

Got it.

And forgive me if this should be obvious, but on that map it's that gray portion that you sold, and the yellow you've retained.

Yes, there's two sales there.

So we had the FourPoint sale, which is the southwesterly sale; but yes, that's -- the target in the middle, though, is what we sold this time.

Got it, got it.

And then if I could ask, perhaps for Nick on this slide 9. And I know that you guys have had a lot of moving parts with the way you've -- the different avenues you've chosen to reduce your debt.

But Nick, I understand that this is specific -- slide 9 is specific to your 2017 maturities.

But can you take us through what of this -- is there anything new here that's incremental since your last disclosure?

No, this is all just a repeat of our last disclosure.

We had done the debt for equity exchanges, some open market purchases, and then we had completed our exchange obviously back in December.

So, no, there's been no increment activity since then.

I think the last time we updated the market on this was around the -- sometime in March.

And then pretty quickly thereafter that, we got into an earnings quiet period and all of those things.

So we've been quiet on this front recently, as we completed our bank amendment and got through earnings, and look forward to being more active in the weeks to come.

Great.

Thanks, Nick.

Doug Leggate, Bank of America Merrill Lynch.

The acreage you've kept in the STACK -- I know this has been a bit of a theme for the call -- but one of the things that you had talked about in the past was that, if and when you decided to start increasing activity there, it could be used as leverage to help with your midstream negotiations.

I'm just wondering if you could just frame generally where you stand in that whole picture, in the context of -- clearly, you are signaling you are going to get active at some point.

Sure, Doug.

A good question.

We still see good opportunity with the other remaining STACK opportunities and the remaining acreage that we have -- as Jason noted, 1.5 million acres that we still have good leverage in that particular asset to help us with our midstream negotiations.

And, likewise, in the other assets, we continue to work closely with Williams, looking at additional stratigraphic dedications, lateral dedications, potential other business lines.

There are a number of things that we are working.

We still remain excited and encouraged that we will continue to find improvement there, and win-win solutions with Williams.

And what I would just encourage you to focus on, as we have done several times, and highlighted what we intended to do, we have accomplished just that.

And I'm confident that that will be the case again.

Okay.

I'll look forward for more news on that.

Doug, my follow-up is -- I guess it's a little more of an obtuse question, and something that hasn't been talked about too much lately.

And it's basically the VPPs, when you start to get the volumes back from those.

I'm just wondering if you could walk us through the timeline.

Because my understanding is that some of those, over the next year or two, will start to come back to you.

Yes, so the volumetric production payments, we presently have six remaining.

Each have a different timeline.

With the asset sales that we've highlighted, we will see the number of VPPs, and the complexity associated with them, continue to reduce.

With these transactions, we should see three or four of those go away.

As we noted in the press release, and I put in my comments, that's principally the reduction that you see from the gross proceeds down to the net proceeds of about $950 million, Doug.

So, what remains, we will -- are at different time intervals.

But when I started the Company, we had nine.

We have six today.

And we will continue to see more roll off this year.

And so that volume really is insignificant, at this point in time.

Doug, just to provide a little bit more color there.

We will -- after the transactions that Doug just spoke about, we will have remaining our VPP in the Devonian and our VPP in a field in northern Oklahoma called the Sahara field.

Other than that, everything else will have been retired, like the Barnett last year, or repurchased.

Nick, just to be clear, is it fair to characterize the VPPs remaining as in the non-core asset category?

In other words, if you secure the balance of your disposals, do those disappear as well?

It's possible, Doug.

I think it just depends on structures of transactions and where assets sit, and what else is around them.

So, it is certainly possible.

Doug, my last one, if I may, is just on costs.

You are making tremendous progress obviously on getting costs down, so it's good to see.

But I'm curious, with eight rigs running, what do you think -- this is kind of a horrible question to ask -- but what do you think your capability is within the firm?

And assuming things get better at some point, what are you capable of running at, up from that eight-rig program you are running currently?

And I'll leave it there.

Thanks.

Well, first, I will never underestimate the Chesapeake employees.

They are doing a phenomenal job on our costs and those continued improvements.

And I expect there to be nothing more than continued improvement.

In terms of capability, Doug?

Capability with (multiple speakers)?

What I'm getting at is -- obviously there's been headcount reduction, and there's been activity reduction and so on.

Now you are running eight rigs, but what's the capacity of Chesapeake?

What level could you operate at?

Well, I think I just would highlight again the capability and capacity of this Company is phenomenal.

And the technology improvements, the efficiency of the organization, G&A reductions that we've had to undergo, like a lot of the industry, have not compromised the strength and ability of this Company.

And so, I feel very good about our competitive position -- competitive position to reduce costs in the current pricing environment; and competitive position that, should we see a more stable, higher-price environment, that we could ramp up and handle that additional capital activity level very easily.

Okay.

I'll leave it there.

Thanks a lot, fellas.

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

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

Okay, well, I appreciate everyone's time on the call today.

We are very encouraged about the progress that we continue to make at Chesapeake.

As I noted in one of the questions there, we have highlighted a number of times our strategy and our intent to further improve the Company.

And I just want to reiterate that today.

Our commitment is as strong as ever -- our commitment to drive greater value for our shareholders and all the stakeholders, the excellent work by the employees of Chesapeake in making sure that we drive for the greatest return and the greatest value for this Company.

We will continue to be focusing on that, and I look forward to the rest of the year and sharing with the investment community our continued progress.

Thank you all for your time.

Ladies and gentlemen, that concludes today's conference.

Thank you for your participation.