Chesapeake Energy Corp (CHK) 2018 Q2 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation Q2 2018 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 the 2018 second quarter.

Hopefully, you've had a chance to review our press release and the updated investor 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, 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 may 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 to Q&A.

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

Thanks, Brad, and good morning, everyone.

Chesapeake continued to build upon the transformational momentum established over the last several years through consistent operational and financial improvements.

The announcement of our Utica divestiture is yet another step that demonstrates our commitment to achieve and sustain top quartile performance amongst our peers.

The enterprise strength at Chesapeake Energy comes from our strong diverse portfolio of assets and our solution-minded employees, each providing optionality and opportunities for greater shareholder value.

We have fundamentally transformed all aspects of the company in the last 5 years.

With closure of the Utica transaction, we will have eliminated $12.2 billion in total leverage, lowered our annual gathering, processing and transportation expense by approximately $900 million, while erasing over $10.3 billion in additional midstream and downstream commitments.

We've reduced our CapEx cumulatively by more than $12 billion while keeping adjusted production relatively flat, and removed over $1 billion of annual cash costs.

Importantly, we have done all of this while delivering record environmental, health, safety and regulatory performance.

Simply put, we have accomplished differential performance improvements during the challenged commodity price environment.

As noted previously, our sequential and successive improvements have yet to be materially recognized by Chesapeake's common equity holder.

I believe we are positioned today with continued progress to deliver that differential value growth to our common equity holders.

We recorded another solid quarter, our fourth in a row, growing adjusted production year-over-year and increasing cash flow and operating margins per barrel of oil equivalent.

For the 2018 second quarter, we posted total production growth of 8% year-over-year after adjusting for asset sales, which is roughly 38,000 barrels of oil equivalent per day.

Importantly, we grew our oil volumes 11% adjusted for asset sales, contributing to the increase in our full year oil production guidance of 500,000 barrels.

We obtained a 47% increase in our cash flow before working capital changes compared to last year, while growing our adjusted EBITDA per barrel by 16%.

This is higher than the percentage increase in oil and gas revenues per BOE, so we continue to create additional margin beyond that which is afforded by the move in oil and NGL prices.

As announced last Thursday, approximately $2 billion of proceeds from our Utica sale will go directly to debt reduction, further strengthening our balance sheet and improving our profitability by eliminating up to $150 million in annual cash interest expense.

In addition, the transaction greatly improves our gathering, processing and transportation expenses, yielding a $0.50 per BOE improvement, driven by removing approximately $450 million in projected 2019 GP&T expense and a total of $2.4 billion of future midstream and downstream commitments.

Additionally, assuming flat 2018 commodity prices, we anticipate our divestiture of the Utica Shale will increase EBITDA by approximately $0.70 per BOE in 2019.

As also noted in our Utica divestiture release last week, this transaction marks the conclusion of Chesapeake's strategy of asset sales being the primary driver of debt reduction.

That strategy was necessary, given the debt profile of the company.

Going forward, organic production growth, exploration, strategic acquisitions and portfolio management will drive us to achieve our ultimate goal of improving our leverage ratio to 2x net debt to EBITDA.

We also shared last week that we expect our diverse portfolio to deliver 10% adjusted oil production growth in 2019, and additional growth is anticipated for 2020.

Notably, with that oil growth, we project that we can organically replace the EBITDA loss in the Utica transaction within a year through the production ramp we are expecting, principally driven from our Powder River Basin asset.

We believe the production growth and trajectory of the Powder River Basin is now fully evident.

Thanks to optimized completions and customized facility design, we recently reached net production of 32,000 barrel oil equivalent per day.

And while we currently anticipate our production will reach 38,000 barrel oil equivalent per day by year-end, we've already increased our net oil production in the Powder River Basin by 90% year-to-date with additional growth that will come from a further 28 turn-in-lines anticipated for the remainder of the year.

From a cash flow perspective, I'm especially pleased that we have been able to reduce our cost and cycle times, as drilling times on 3 recent Turner wells are less than 20 days from spud to rig release, and total cycle times are now in the 90-day range.

While the Turner continues to drive our Powder program, we anticipate moving to other zones in 2019, another benefit to our acreage unique hotspot advantage.

Oil production from the Powder River Basin is expected to increase by 100% in 2019.

And depending on oil price movement, we're considering adding a sixth rig in 2019 to attack those opportunities.

While we are pleased with the progress in the Powder recognized this year, it's not the only asset that has seen significant performance improvement.

The South Texas team continues to demonstrate improved capital efficiency, driving costs out of the operation and turning an asset which was cash flow negative even at $100 per barrel as recently as 2014, into one expected to generate approximately $475 million in free cash flow this year.

While South Texas will continue to deliver low-cost, high-margin barrels, the team is also excited to implement our first improved oil recovery project in 2019 and begin development in the Austin Chalk in Upper Eagle Ford, 2 horizons which we believe can provide additional growth opportunities.

Chesapeake continues to produce oil-efficient growth from the Mid-Continent -- or volumes from the Mid-Continent, and we're attempting to reinvent this legacy asset in our portfolio.

In many ways, as we work to appraise liquid-rich opportunities across 6 Mid-Continent formations, our technical team sees parallels to the Powder River Basin from a few years ago.

Meanwhile, our Oswego volumes continue to decline, with average 30-day production rates of 1,015 barrels oil equivalent per day with over 80% oil cuts, delivering a 50% rate of return.

With the pending sale of the Utica, our gas assets are now even more competitive.

Perhaps nowhere in Chesapeake's portfolio has our drilling and completions excellence yielded greater results than in our Gulf Coast asset.

While we are pleased with our progress, we continue to push for greater results, driving innovation and operational excellence to unlock additional value.

This starts with our drilling program.

We successfully drilled the first 15,000-foot lateral ever drilled in the basin, helping us grow 2018 second quarter production by approximately 15% year-over-year with the exact same number of rigs.

We are repeating that same success in Pennsylvania, where we believe enhanced completions and longer laterals have began to scratch the surface of unlocking greater value from both the Lower and Upper Marcellus formations and, eventually, the deeper Utica formation.

We have just drilled the longest lateral to date in the Lower Marcellus at approximately 13,380 feet and are drilling an even longer plant lateral of approximately 14,500 feet.

We expect to place both wells on production before year-end 2018.

In total, we anticipate that Marcellus will generate approximately $300 million in free cash flow in 2018 as the asset continues to define capital efficiency.

I continue to be extremely confident in our future, thanks to our improved balance sheet, higher profitability and simpler overall path to creating shareholder value.

We have emerged from our transformation stronger than at any point in our history.

We expect to further build on our performance track record in the months and quarters ahead as we continue our relentless drive to achieve our strategic objectives of 2x net debt to EBITDA, enhanced margins and reaching cash flow neutrality.

As I have previously stated, I'm very pleased with our progress, and we look forward to driving differential shareholder value from our high-quality assets.

Please go to our website and access our updated asset slide deck for additional detail regarding our operating performance.

We now want to take a few minutes to share more information regarding the balance sheet and our plan of action with the proceeds from the Utica divestiture.

Thank you, Doug, and good morning, everyone.

We're pleased with our results this quarter as we continue to see the benefits of our improved cost structure, realized prices and improved asset portfolio profile.

This morning, I'd like to focus my comments on the recently announced Utica sale transaction and the positive impact we expect on our balance sheet as we moved toward closing on the deal.

We expect our proceeds at closing to approximate $2 billion in cash before effective date adjustments, and we intend to use the proceeds to retire our outstanding debt and intend to focus on our secured debt.

Our 1.5 lien term loan becomes callable this month at a price of 104.25, and our second lien notes become callable at 104 in December.

Additionally, in May, we purchased existing overriding royalty interest on our Utica-operated wells as well as our obligation to deliver future overriding royalty interests in the Utica from third parties.

The value of the producing overrides of $77 million was passed directly through to the buyer in the purchase, while the retirement of the future liability for $122 million resulted in a decrease of current and long-term liabilities on our balance sheet of $183 million, so we retired it at a discount of $61 million.

This anticipated decrease in secured debt and liabilities is a significant improvement to the overall capital structure and will result in a meaningfully reduced interest expense drag on our cash flow of up to $150 million per year as we move toward achieving a sustainable free cash flow profile.

We've also begun working with our bank group to renew our revolving credit facility that would otherwise mature in 2019.

As we noted in our release last week, excluding our Utica properties, we have an excess of $7 billion collateral available for the borrowing base, and we expect to successfully close on a new facility during the third quarter.

Lastly, we will likely look to access the high-yield market to opportunistically refinance any remaining secured debt and other near-term maturities in the second half of the year, provided market conditions remain attractive to do so.

At that point, we believe we will have reduced our total outstanding debt and interest burden materially, renewed our access to liquidity and meaningfully increased the average tenure of our remaining outstanding debt.

This will be a fundamental shift in the financial risk of our company.

We will remain focused on the goal of improving our leverage ratio to 2x debt to EBITDA, but we'll pivot our strategy to reach that goal by being more growth-oriented.

While we will still actively manage our portfolio and we will likely sell some amount of assets every year with proceeds available to further reduce debt, asset sales will no longer be our primary financial strategy.

We look forward to continuing to deliver operational results similar to this quarter with increasing oil volumes and cash flow into next year that will drive significantly increased shareholder value with substantially reduced financial risk.

With that, I'd like to turn the call over to the operator for questions.

(Operator Instructions) We shall take our first question from Neal Dingmann of SunTrust.

Doug, my first questions were in the PRB.

You obviously have seen some recent success.

Just a question for you or Frank.

The recent success you've seen in the down spacing, your thoughts as you progress forward.

Is that something you'll do in other areas there?

Or maybe just talk about the spacing, in general, on the play.

This is Frank Patterson.

Yes, we are in the midst of a 6-well down spacing test.

We've talked about it.

We now have 100 days of performance.

We actually put a slide in the deck to kind of give you an update on that.

What we're seeing, totally, is really no effect to down spacing to 1,980.

If we are able to down space to 1,980 with confidence across the field, that would give us probably another 80 wells plus, so that's pretty powerful.

We've already run spacing tests in the Niobrara, and we have a pretty good feel for what the Parkman is going to look like in the -- and the Sussex.

So once we get this information, we will be able to develop the field in the proper spacing from the onset, and that will allow us to create a lot of synergies off the pads.

We'll have a significant number of multi-well pads across the field.

It certainly sounds encouraging.

And just one last follow-up (inaudible) for Nick or Doug.

Just on CapEx, a question, overall -- so that overall CapEx was about 2.3 billion.

What does that include for the Utica?

I guess, does that include bringing a couple of those Utica rigs back?

Or how much of that is going to be factored into that overall CapEx?

And maybe, Doug, as an aside on that, maybe just talk about free cash flow, how you guys, you or Nick, sort of see that going forward.

Sure, Neal.

This is Nick.

I'll answer that.

So the CapEx, we increased our range last week.

Keep in mind that we are now running 5 rigs in the Powder.

And based on the success we've seen this year, we're really pleased with that level.

It's generating great cash flow growth and will be the driver of our cash flow growth in '19 versus '18, as we have a pretty significant turn-in-line program in the second half of this year.

When we originally put our budget together, we had 3 rigs in the Powder.

So our outlook, our initial outlook was based on lower activity there.

We have shifted some dollars around, so that's not all just a net add from the Powder.

We've pulled some activity down in other places and just generally been able to optimize moving some dollars around, really largely based on the efficiencies we've seen working faster in each of our plays.

We continue to see that in the Powder as well.

It's a theme across the portfolio.

We're getting more done every day in the field with the same dollars, and that's been a big help to the growth profile.

As we look at the Utica, though, we did add some dollars back into our program this summer.

We have front-load -- front-end-loaded our drilling program in the southern portion of our Appalachian region.

Remember, we think of our Appalachian region historically as being both the Utica and the Marcellus.

So we had rigs in Ohio in the first half of the year.

We had planned to move those rigs to Pennsylvania in the second half of the year with frac crews and drilling out in Ohio behind them.

They were actually going to finish up during this quarter.

So what we've done now is we've shifted.

We have rigs staying in Ohio through the closing of the transaction, and then they'll stay there.

Post the closing of the transaction, we'll operate them under our transition services agreement.

But as soon as the transaction closes, the CapEx moves off of our books and onto the buyer.

So there is some there for the transaction.

There is -- a good bit of it is just overall activity, accelerated activity in the Powder.

And again, you see it in our results; our growth rates are showing the benefit of it.

I'm just going to add there, just if you don't mind I'll interject with the last comment around the free cash flow.

Just to remind you that each of the assets, with exception of the Powder River Basin, are free cash flow positive today.

We anticipate, in 2019, with the increased oil production there and the efficiencies we're seeing that the Powder River will be close to free cash flow positive, and the team is targeting to achieve that.

And so the assets are performing outstanding and then as we just look at the larger balance sheet and how we continue to attack that, through further growth exploration and acquisition opportunities is how we'll continue to further delever.

And I'll build on that just one step further as well, Neal, which is that as we think about being free cash flow positive, it has to be at a sustainable level of cash flow.

And post this sale, what we've said is that we will replace the EBITDA from the sale of any year.

So that will certainly put a little bit of pressure on being free cash flow positive in '19, but we're doing so with a significantly reduced balance sheet.

And then as we replace that cash flow, it becomes a place where you see the leverage start to move lower very quickly.

So we could be free cash flow positive anytime we choose, right?

You can just drop your CapEx, but it's got to be at a sustainable level and one in which we know, from that point forward, we can add shareholder value every day while maintaining that free cash flow profile.

We're pretty close.

We're going to get there very soon, and we're going to now do it with a lot less leverage, so it all feels pretty good to us.

We shall take our next question from Charles Meade of Johnson Rice.

Your last conference, you actually really teed up, I guess, the question I wanted to ask well is that you made this comment about the asset sales being no longer the primary way of deleveraging, and I wonder if you can talk about 2019 and what the broad parameters of how that is going to look.

I think, Nick, you just alluded to it a bit.

It sounds like you guys are planning to stop the outspending versus cash flow and now spend within cash flow, and is that the right read on 2019?

And what's the kind of commodity price at which we should think about that being a valid read?

And how are you -- I know it's early, but how are you projecting oil volumes to grow or overall volumes to grow?

Sure, Charles.

Well, happy to provide a little more clarity with that.

And as we've stated, we anticipate our 2019 oil volumes to grow by 10%, and this recognition of our ability with the remaining assets post Utica divestiture of being able to replace that EBITDA within a year speaks to the capital efficiency and the cash flow generating capability of our assets.

As we look forward to 2019, the reduction in our interest expense, it will help us as we pay down some of the -- some of our debt.

But we anticipate that free cash flow neutrality is -- as a primary target, will be something that we have to continue to look at.

And as Nick noted, in 2019, we aren't forecasting any major asset sales.

But through our own operations from our existing assets, we expect the production growth that will help us in reducing any outspend.

Nick's point on the sustainable free cash flow at this point, when you look at 2019, we will accomplish that principally through our organic production growth, but we will also have and continue to look at smaller asset sales and other opportunities for us to generate cash.

What we're excited about is that, as I noted, each of the assets are free cash flow positive today with the exception of the Powder, and the oil's growth strength there, we clearly will achieve that in 2020, but targeting with the team to try to achieve that in 2019.

So our objective to be free cash flow positive is very strong.

And from an operating cash flow basis, we are there.

When you look at all the other corporate liabilities that we have, we're making excellent progress on that and expect to share good results with you as we progress.

Got it, Doug.

It kind of seems like a phase change taking place for you guys.

But picking up and maybe going a step further there, you've mentioned acquisitions a couple of times, and that seems like a really intriguing possibility for you guys, especially since there's a lot of -- it seems like there's a lot of assets for sale in the marketplace.

But you also mentioned deleveraging through acquisitions.

Should we interpret that as meaning that equity is one of the currencies that's on the table for acquisitions?

And could you give us an idea, are you just looking at kind of small tuck-ins on existing plays or is it really kind of wide open on the field for you guys?

Sure, Charles.

This is Nick.

It's -- that's something that we always look at.

We are more mindful than ever of the opportunity for acquisitions in the marketplace because there are a lot of assets for sale, and many of the assets that are for sale are in basins where we operate where we have a high degree of confidence, where we have a great cost structure and where there would be real synergies, so it's something we always pay attention to.

There's nothing in front of us.

We're not ready to execute on anything today.

It is just prudent for us to be cognizant of it.

We recognize the power that it can have to our financial performance over time if you can check all the boxes with an acquisition.

That being that it's the right value that you will add incremental value to it with synergies and that you can finance it appropriately.

And so as we think about how you finance an acquisition appropriately, I couldn't tell you today whether it would be something that would justify the use of equity or not unless we're talking about a specific deal.

But if you're going to look at an acquisition, I think you look at what makes sense for the deal and where you are as a company and what value your currency has in the marketplace.

So those are just all considerations you think about as you approach transactions like that.

We get called a lot to look at stuff, and we will continue to get called a lot to look at stuff as people recognize that our balance sheet is improving, we're in a healthier position and that we are an operator of choice in many of the basins in which we operate.

Let me just add further to that, Charles, that Chesapeake's experience and expertise and the fact that we are the leader in unconventional shale development in the United States gives us tremendous optionality.

We are capable of absorbing additional assets, bolt-on assets.

And so as Nick noted, the opportunity to where we can utilize and lever our core strengths, we will always be looking for those opportunities.

We shall take our next question from Doug Leggate of Bank of America Merrill Lynch.

Doug or Nick, I hate to beat on the CapEx question, but I just wondered if you could just help us with the moving parts a little bit.

What was the Utica spending in the budget for this year, including the 2 additional rigs, which I presume you will get by incremental capital at close.

But if you could just give us that and then help us walk through how the deltas with the additional rigs in the Powder leave the year-over-year outlook going into '19?

Yes.

So Doug, our spending in the Utica this year was intended to be about $450 million.

It will go a little bit higher as we go into the third quarter here and have this incremental activity.

The increase that we guided to last week is the same number we're talking about this morning.

There is no difference there.

And again, that's a mix of that incremental as well as the Powder River Basin incremental activity where, in our original outlook for the year, we were targeting 3 rigs based on success and confidence in that program, sustained good oil pricing and continued hedging of those oil prices into '19.

We've gone from 3 to 5 rigs.

That rate of return is solid, and that incremental CapEx is doing very, very well for us across the board, including encouraging sale of the Utica asset.

So it's all those things combined, and it's generating very good return for us.

So to be clear, do the 2 additional rigs for full year in the Powder offset the -- fully the $450 million drop in the Utica?

Whoa, wait a minute.

We're talking about '18 CapEx here, so the Utica CapEx (inaudible) is for 3 quarters.

Yes, certainly, going into '19 -- as we into '19.

No, no, no.

Two rigs in the Powder does not equate to $450 million, no.

So to be clear, net-net, we should expect spending trend to be lower next year?

Yes.

Great.

My follow-up, if I may, is for Frank.

Frank, obviously, the Powder is getting a lot of attention, and I think you first flagged this to me personally about 2 years ago.

So a tremendous success and congratulations on that.

However, my question is that the 2016 type curve you gave is obviously now stale.

And I'm guessing, the inventory is pretty stale as well, particularly when you look at Niobrara and Parkland opportunities.

So can you just speak to the depth of inventory that you see today and what trend type curve we should be using for development as we look forward on this?

Yes, Doug, we are updating type curves as we speak.

We have a couple of type curves in the Turner.

The big change in the Turner is we have learned through going through this process that we want to manage the chokes a little bit more than what we had anticipated, so we're not going to see as high IP.

What we're seeing is a lower decline rate.

So we're seeing that the wells performed actually pretty spectacular.

If you look at the graph that's in the presentation, every well that we turned on in the Turner has been in the upper quartile in the basin, so I think that speaks for itself.

We've seen a lot of operators in the Turner flow up casing and flow up unconstrained.

It looks really, really sexy the first 30 days.

But around 60 or 65 days they cross over the wells that we're actually flowing up tubing and managing the choke.

On the Niobrara, the big difference -- we still have some work to do, but the big difference is the historical Niobrara wells were severely understimulated and, quite frankly, drilled probably too tight a spacing.

So we're going to up-space that, put longer wells in the ground and put bigger fracs on the wells.

The 3 wells that we have that we have had larger fracs on, we had a historical well called the Barton out to the East that had -- was a 10,000-foot lateral and a larger frac.

It's the best Nio well in the country as we can see it from the data that we can pull.

We've now done 3 DUCs with larger stimulations that were shorter wells, and those wells are performing in the upper quartile of the Niobrara as well.

So we think the Niobrara needs to be up-spaced, larger completions and longer wells, and that's the way we're going to head.

We only have, I think, 3 wells in the Parkman.

The Parkman is basically a sandstone.

It's going to be drilled kind of in a -- very similar to what we're doing in the Turner.

We'll have pretty light stimulations on that.

It's not overpressured, so we'll have to put it on submersible lift, but those wells will be fine economically because they're shallower and we can knock them out quicker.

The other zones, the Sussex, we know that, that zone has really good transmissibility.

So we've up-spaced that so we'll have less inventory than we spoke of before in the Sussex.

So the inventory is long and deep.

We still have the Mowry that we have to get out and drill a well in the oil window to see what it'll do.

We drilled a well in the gas window, pretty short well, and it performed well, but it was a gas well so, really, the economics were not outstanding.

We need to get out and drill a narrow well.

So as we're seeing this play evolve, we're getting the spacing right.

I believe we are seeing opportunities to STACK on almost every single section we operate.

There is a slide in the deck on Page 11 that shows you how many potential wells we could have in a given section for the play.

We're pretty excited about the play.

We're just getting started.

So things are going to change.

The big thing, and I'd like kind of Jason to maybe mention a couple of things, but we've seen huge improvements in the drilling side and the completion side, and that is driving the economics as well.

Yes.

Thanks, Frank.

In addition to the productivity gains we've seen within this phenomenal work done on the completion and drilling efficiency, we've cut 10 days off our drilling time over the last year, so it's just phenomenal.

We've had -- averaged 24 days for the quarter, but we've had several wells hit the sub-20 day mark.

So they're killing it there.

We're doing innovative things like drilling with produced water, which can cut one of our bigger expenses, which is mud cost.

Some of the cluster spacing tests they've got can cut cost on the completion side up to $200 per foot as well.

So in addition to the productivity, again, efficiency gains, capital costs are going to come down in the area and we're going to get faster and better every month.

Ladies and gentlemen, this concludes our question-and-answer session.

Therefore, I'd like to hand the call back to Doug Lawler for any closing statements or remarks.

Yes.

Thank you, operator.

Just in closing, I just would like to further highlight the confidence we have in our continued progression.

Chesapeake is already a top-quartile performer at capital efficiency and the way we run our cash cost and all associated costs in the business.

And what we're seeing is continued incremental steps of improvement.

And I think the investment community can expect nothing but continued performance.

And our excitement and our confidence in things that we're doing is very high.

And this is what we consider to believe a very attractive opportunity and our equity as we continue to build on the Utica divestiture and other transformative events that will put us in a position to further round out being a top quartile company in every aspect of our business.

So thank you all for your time today, and we'll talk to you all soon.

Thank you.

Ladies and gentlemen, this concludes today's conference call.

Thank you, for your participation.

You may now disconnect.