CHK
#Good morning, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2018 first quarter.
Hopefully, you've had a chance to review our press release and the updated investor presentation that we posted to our website this morning.
During this morning's call, we will be making forward-looking statements, which consist of statements that cannot be confirmed by reference to existing information, including statements regarding our beliefs, goals, expectations, forecasts, projections and future performance and the assumptions underlying such statements.
Please note that there are a number of factors that will cause actual results to differ materially from our forward-looking statements, including the factors identified and discussed in our earnings release today and 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 <UNK>, Nick Dell'Osso, <UNK> <UNK> and <UNK> <UNK>.
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, <UNK>, and good morning.
We're pleased to release our first quarter earnings and provide an update today on our financial and operational performance.
Our strategic priorities remain unchanged, and our foundational progress in transforming Chesapeake into a top-quartile E&P company is evident in our systematic sequential improvements in all aspects of our business.
In the first quarter, we recognized material progress in enhancing our margins, achieving positive free cash flow and reducing our net debt.
The underlying strength of our operations, coupled with higher realized prices, resulted in our best financial performance since before the downturn in 2014.
For the second consecutive quarter, we posted stronger-than-expected results on production that grew 11% after adjusting for asset sales.
We reported adjusted EBITDA of $733 million or $14.70 per barrel of oil equivalent.
Importantly, this is a 33% improvement over our EBITDA per BOE from the first quarter of 2017 despite only a 13% increase in oil and gas revenue per BOE.
I'm very excited about this greater rate of acceleration of EBITDA than revenue as it demonstrates the greater trajectory of our value growth and not just increasing commodity prices.
As noted last quarter, much of the improvement in the underlying fundamentals of our business has not been able to accrue to equity holders over the last several periods due to the need to address a variety of financial obligations and other uses of cash.
Those cash obligations have been dramatically reduced.
As a result, we are showing higher margins and returns.
We see this developing trend continuing on the strength of our talented employees, high-quality assets, capital efficiency and cash cost discipline.
Our operating and technical expertise continues to yield positive results across all of our operating areas.
We remain encouraged by our growing operating momentum in the Powder River Basin where we recently added a fourth rig.
All 4 rigs are concentrated on the Turner formation where we are currently conducting spacing tests.
In April, we placed 6 new Turner wells on production, and we are excited about the initial results.
After 18 days of production, flowing pressures and early flowback results from the first 3-well, 1,980-foot spacing tests are very encouraging, flowing tubing pressures ranging from 2,700 psi to 3,000 psi while the wells are still cleaning up.
We will be sharing more information in the coming weeks as we anticipate peak rates will be achieved within 50 or 60 days of initial production.
Field development planning for the Turner sand is fairly conservative at this stage through well spacing and disciplined choke management.
Our approach is unique compared to what you'll hear from other operators as we seek to maximize ultimate recovery and capital efficiency, both of which drive greater profitability.
As a reminder, we drilled our first Turner test, the Sundquist 9, more than 1 year ago.
Today, after roughly 400 days of production, the Sundquist 9 continues to deliver strong results, averaging more than 500 barrels of oil and 1.5 million cubic feet of gas per day for the month of April 2018.
This is important because there are very few wells in the United States that produce 500 barrels of oil 1 year after coming online.
Current cumulative gross production from this well is approximately 345,000 barrels of oil and 622 million cubic feet of gas or almost 500,000 barrels of oil equivalent, generating revenue to date of approximately 122% compared with total completed well cost.
So as you'd expect, we plan to prudently develop this outstanding Cretaceous marine sand.
The Powder River Basin will continue to play a key role in our future oil growth.
In our gas plays, we continue to test new drilling and completion technologies in new and existing stratigraphic horizons.
We placed an Upper Marcellus well online in January that has produced at an average 90 day-rate of approximately 18 million cubic feet of gas per day.
In the Bossier Shale in Louisiana, our first 10,000-foot lateral has cumulative production of 4 billion cubic feet in its first 150 days production, averaging more than 27 million cubic feet per day and making it the best Bossier well per foot of lateral drill.
In the Haynesville, we successfully drilled and completed our first 15,000-foot lateral well and placed that well on production yesterday.
In the Utica, we are also improving our results through improved completion designs.
We are pleased with the significant operational efficiency improvements achieved in recent years.
Our relentless drive to be the most efficient operator continues to generate differential performance, as demonstrated by the fact that today, a 4-rig program in the Eagle Ford will maintain a flat production profile compared to the 7 to 10 rigs we historically needed to deploy.
This progress is indicative of our capital discipline as we focus on increasing our margins.
To close and prior to handing the call to Nick, the sequential improvements in our operational and financial performance are clear, and our shareholders will benefit from our foundational transformation and continued progress.
Our commitment to our shareholders remains the same: to efficiently grow our cash flow, expand our margins and further reduce our debt.
We look forward to demonstrating further progress across all aspects of our business.
I'll now pass the call to Nick.
Thank you, Doug, and good morning, everyone.
This quarter's results are outstanding, and our confidence in delivering improved margins, greater cash flow from our operations and increased return on capital is getting stronger with each quarter.
We recorded free cash flow after capital spending of approximately $609 million, including net proceeds from asset sales for the quarter, again, the highest in over 3 years, allowing us to reduce the principal balance of our debt by $581 million from the end of 2017.
For the remainder of the year, we expect to be free cash flow positive in 2018 at current strip prices after our planned capital spending and net proceeds from asset sales.
Our results are primarily driven by stronger oil production and higher commodity prices, with better differentials for both oil and gas.
We continue to see these strong differentials in oil today, with average LOS differentials for our Eagle Ford volumes at a positive $2.32 per barrel for the month of April.
We've also locked in approximately 80% of our summer and fall exposure to TGP Zone 4 in-basin Marcellus gas exposure at a differential of $0.73, which includes both financial hedges and firm sales contracts to end users.
This represents a significant improvement to prices for this location compared to last year.
In total, for 2018, we currently have approximately 63% of our remaining projected gas production hedged at a NYMEX price of $2.96 per Mcf, and approximately 78% of our remaining projected oil production hedged at $50 ---+ $53.78 per barrel, using the midpoints of our production guidance.
We've also taken advantage of recent runup in oil and hedged over 11 million barrels of our 2019 oil production at over $57 per barrel.
We have added to our oil hedges for 2019 and will continue to watch for opportunities to project additional gas and oil volumes throughout the year.
Our 2018 outlook, provided as Appendix A to our earnings release this morning, remains unchanged.
Our guidance implies a modest total adjusted production growth for the year, driven by our investment in our oil properties.
In previous discussions, we highlighted for investors that our low point for production for the year would be during Q2, following the stabilization of flush production from our significant Q4 2017 turn-in-line program in the Eagle Ford and the reduction in volumes from the Mid-Continent asset sales.
From this point forward, we forecast a modest decline in gas volumes, replaced in the total, with oil volume growth accelerating as we approach the end of the year.
Again, as I noted before, our investments are focused on increased margins and returns.
This production profile highlights that we are seeing our capital allocation process deliver the results intended in the current commodity price environment.
We are encouraged by our current oil volume growth.
As noted previously, we produced 92,000 barrels of oil per day in Q1 of 2018, including 5,000 barrels from assets sold at the end of the quarter, resulting in 87,000 barrels per day of Q1 production as a go-forward comparison point.
Following the close of those asset sales, we averaged 90,000 barrels of oil per day in April or growth of 3.4% in the first month of the second quarter.
We expect to turn in line 100 wells in the second quarter compared to less than 60 in the first quarter.
Half of those wells will be in the Eagle Ford.
As a result of the Mid-Continent sales, we expect our LOE expense per BOE to improve significantly for the remainder of the year.
At this time, we are projecting our LOE expense per BOE of production to fall through at the lower end of our guidance range for the remainder of the year.
Our efforts on A&D continue, and we remain in active discussions on multiple large and small transactions.
The proceeds from asset sales when realized will be directed toward debt reduction as previously noted.
To close, we remain committed to generating greater returns and growing our cash flow.
The performance track record we have established through our improved cost structure, capital efficiency, oil production and margin growth is evident.
We believe these improvements have not been recognized in our stock price to date, and we are excited to build further upon this transformation to create value for our shareholders.
That concludes my comments.
I will now turn the call over to the operator for questions.
Yes.
The ---+ what we're really excited about, and this is what we've tried to highlight here just recently, is that the reduction in the financial obligations at Chesapeake has really put us in a very good position, that operationally, the quality of our assets, the talented employees that we have, the technologies that we're driving, we are very encouraged about what we're going to be able to deliver and how that'll accrue to the common shareholder in the coming quarters and in the future, looking out 2019 and beyond.
And while we have not provided the guidance yet for those outer years, what you can expect at this company is we're going to continue to deliver on this sequential performance that we've highlighted.
And while we started in a different ditch, we continue to drive sequential improvements that have not been recognized.
And we're excited about doing the right thing to Chesapeake, and we are very motivated to capture that for our shareholders.
So I think that your question is very good and that you can expect that trajectory to continue in the future.
<UNK>, this is <UNK> <UNK>.
Yes, thanks for the question.
I think we're pretty excited about Powder.
Just to give you an idea of where we're headed, our initial thought was we would ---+ we might go to 5 rigs here for the Turner.
We're kind of leaning towards 4 rigs as really a good rig count for the Turner because we're drilling these wells much, much faster.
The drilling team is knocking it out of the park.
We're down in the low 20s from spud to rig release, and I think that's fantastic.
Our completion teams are continuing to come up with faster and more cost-effective completion styles.
So we think maybe 4 rigs is the right number for the Turner.
We still are anticipating, thinking about a fifth rig later this year.
As we've been drilling these Turner wells, we've been going through the Parkman.
We've taken Parkman cores.
Parkman looks really attractive to us.
We're working up a Parkman program.
The Nio completion styles that we adopted last year [on some of the DUCs], some of those Nios that were completed with the new style are some of the best Nios in the basin.
So we think we will be moving forward with a Parkman and a Nio program.
The Sussex is still good, but we just don't have a lot of Sussex locations.
So if we bring in a fifth rig.
I think that's going to be focused on other zones outside of the Turner, 4 rigs focused very much on the Turner because it's the best economics in the basin.
And once we get the spacing tests completed, we'll have a better handle on what our running rim is in the Turner.
It could expand substantially.
And to the ---+ your last point, we told you at Analyst Day that we could be rivaling the production out of the Eagle Ford relatively quickly, and we're on track with that.
Actually, we're just a tad ahead of where we said we were going to be, and we're pretty happy with that.
Yes.
<UNK>, thank you.
So let me just kind of walk you through our philosophy here.
We've entered the Turner and looked at all the Turner data available within the entire basin.
Our first pass said it should be 2 wells per drilling section.
Of course, we're basically tying up 2 sections with longer laterals.
But basically, 2,300- to 2,600-foot spacing was our initial assessment.
We have watched the industry test down to 4.
Our analysis of that data says 4 is probably too tight, but we're ---+ we don't know if 3 will work.
So we put together this spacing test.
It's basically a back-to-back pad, 3 wells to the north, 3 wells to the south.
The 3 wells to the south are drilled at 2,300-foot spacing, which is kind of our standard.
The wells to the north, the center well will be bounded on both sides by 1,980.
We also have adopted the philosophy here from all of our analysis of the fluids and the pressures in the wells, that we are going to basically tube these wells up and not flow up casing because we don't want to rip the reservoir part and destroy value by trying to get a high IP, which these wells can get high IPs, there's no question.
So we're being very cautious on all of our wells, managing our chokes.
In this case, what we're doing is we've got all 6 wells on now.
The wells are flowing at really nice flowing pressures on small chokes, 20 to 22/64-inch choke, and the flowing tubing pressures are between 2,750 and 3,000 pounds.
We have downhole gauges.
We've basically put tracers in the wells to look at how the wells are behaving against each other.
And so we are monitoring this.
We will open these wells slowly and monitor the pressure as we go.
Going forward, I think the question would be ---+ I don't want to get too excited with 90 days or 100 days of production.
When we get out 200, 300 days on that 1,980, if it is behaving the way it is now, that tells us we can probably go to 1,980 spacing, and that increases our footprint in the Turner substantially.
So we're just going to be prudent.
We're going to manage this reservoir for the optimum economics for the life of the field.
You bet.
Yes, we're excited about that opportunity.
And as we highlighted in many of our areas, the completion technologies and drilling technologies have resulted in a lot of operational and profitability improvements.
We want to make sure we highlight what other stratigraphic intervals also provide material upside to the company as we go forward in our development program.
So specific to the Bossier, I'll turn that to <UNK> and <UNK> to comment on some of the details there.
Yes.
This is <UNK>.
I mean, the Bossier well is on the south side of the field there, I mean, we go from Haynesville, strong in the north, to the Bossier picks up as we go towards the south there.
So that's a unique test there.
We're just trying to prove up that we pumped a very large frac on that.
I think it was 4,000 pounds per foot or something.
It was a big frac just to try to get the maximum productivity out of the Bossier that we can.
So we're excited about that.
We're equally excited, we've just TD-ed and about to put online our first 15,000-foot Haynesville well to the north.
So that's something that we're really proud of the technical capabilities of our teams and what they can accomplish there.
As some operators struggle to get to 10,000 feet, that's become the normal for us.
And we've now tested or about to put online our first 15,000-foot well.
So lots of great things still going on in the Haynesville and trying to continue to optimize and improve our economics and the value of that asset every day.
<UNK>, this is <UNK> <UNK> again.
The Turner is a discrete reservoir.
We landed kind of in the center of the reservoir, and we think we're effectively draining maybe 120-, 150-foot thick interval.
The Turner probably does not have benches like some of the other zones.
We do see the potential in the ---+ our acreage footprint of multiple benches in Niobrara being productive.
And the industry is testing that concept for us now, and we will move out and test that concept later on.
The Parkman, we have 4 to 5 different discrete intervals that look to be productive in our area relative to the north where the Parkman is really about 2 intervals.
So yes, we see a lot of opportunity for stacking within the reservoir.
But I think the big picture in the ---+ in our Powder footprint is that when you look at the stacking and where the majority of our acreage resides, and we basically are blocked up on our acreage, we have Parkman, Sussex, Turner, Niobrara, Mowry all stacked on top of each other.
So the stacking potential of this basin is phenomenal, and we have a ton of it.
Yes.
Thanks for the question.
I'll start it, and then I'll let <UNK> talk about the completion.
We are ---+ we've gone back and basically reinvented the Utica.
I mean, we were well into this program.
Everything we've learned in Eagle Ford, Haynesville and the other plays, we're moving all of that knowledge to all of our plays as fast as we possibly can.
We are looking and we have changed some of the landing within the Utica.
We are drilling longer laterals in the Utica.
We have upspaced in the Utica because we believe that we are effectively stimulating more rock and don't need the tight spacing.
So it's all of the above.
And yes, you're right, it is moving over towards the oilier portion of the field.
And we think that is a real positive for our acreage position.
That expands our available well count.
And then we are changing some of the completion styles, and I'll let <UNK> talk about that.
But we're really excited about what it's doing.
It's a substantial uptick to what we've seen historically, and I think it's going to bode well for the future.
Yes.
Thanks, <UNK>.
This ---+ we're really excited on the completion side of what we're able to accomplish out there.
And it's actually a good combination effort between our drilling and completion teams.
We had to completely redesign the wells from the casing string onwards, but we've started changing the fluids that we pump, and we've also increased the sand concentrations, like it was successful in other plays like the Haynesville.
So sand is up 33% per well.
So that's something again that's easy for us to do across the board going forward, but took some operational adjustments to get us there to be able to make these high-producing wells.
So we're really excited about the future in Utica as well.
And <UNK>, one of the things that we're looking at, can we ---+ is this a refrac opportunity as well to go back into the older portion of the field and maybe restimulate.
So there is expandable opportunity with technology.
We are still in the process of reevaluating how the wet and the dry window should behave.
So it's a little premature to say because as I said, we've upspaced but that upspacing ---+ with that upspacing comes also an increased EUR per given wellbore.
So we're not working necessarily locations in any of our fields.
That's not our driving ---+ driver.
Our driver in every field is, how do we maximize the value of every well we put in the ground.
So our well count could go down.
It could go up in a given field, depending on spacing.
But what we're trying to do is get the economics at every single well that we drill to the highest it can be.
And <UNK>, just on top of <UNK>'s comments there, that keep in mind that one of the competitive positions that Chesapeake has today is that, in essentially all of our fields, we still remain about 30% developed.
So when you start asking about specific well locations and the technical improvements in this company, the answer is we've got a bunch of them.
We've got a bunch of opportunity and significant number of locations in every asset.
It only gets better with the improvements we're recognizing.
This is <UNK> again.
What we've done is basically, in all the fields, one of the lessons learned is that trying to align the drilling rigs with the completion crews to create the most efficient logistics stream we can possibly create.
So that's just a situation where we're running 3 rigs.
We're running basically a completion crew, 2 completion crews right now following those rigs.
We've also tried to align in most of our gas fields because the price of gas has dropped, as you're very aware, with our firm transportation.
And so we're just lining that out.
We will see the asset basically running at about our firm transportation rate.
And that's an asset where if gas price reacts, that's where we can react and drive more gas into the system as needed.
And <UNK>, this is Nick.
Just to add on to that.
We only turned in line 4 wells in the Haynesville in the quarter as we aligned those operational efforts and get our logistics revised to reduce costs as much as possible and be as efficient as possible.
So as we work through our capital allocation process, as I noted in my notes ---+ my prepared notes for the call this morning, we are driving for an optimal allocation to gas, which in today's commodity price environment is not terribly high.
And we are going to be as efficient with our capital as possible.
And so again, that's a bit of lumpiness there in the turn-in-line schedule.
There'll be more wells turned in line in the Haynesville as we move throughout the year.
But it's about capital efficiency, and it's about allocating capital across the portfolio where we, frankly, don't have a need to invest as much in gas with the gas strip where it is today.
Yes, it was all Mid-Continent.
And then there was another $60 million sold on effectively the first day of April, so it's all right at the end of the quarter.
It's all Mid-Continent, and it aggregated 5,000 barrels of oil ---+ of oil, not equivalent during the quarter.
So again, adjusting down our production for that in the first quarter would be 87,000 barrels.
So it's really why we're excited about our production trajectory going forward, we've replaced most of what was sold in the first quarter just with our turn-in-lines in April alone.
This is <UNK>.
I think maybe look at it in a different way.
The first quarter was running a little bit high.
We basically front-end loaded a lot of our capital.
We've talked about we have 5 rigs in South Texas today.
The reason we're doing that is we have one ranch that's very congested.
It's a very deep ranch, and it has a 20-mile-an-hour speed limit, so it's like an hour drive plus from the highway to the rig site.
So we basically put a rig in there to knock out all the wells.
So that rig is not contributing volume right now.
We'll move that rig off the ranch and drop to 4 rigs running forward, so we'll see a drop in capital associated with South Texas.
We're front-end loaded on quite a few of our completions.
I mean, that's why you're going to see a lot of [tills] going into the second quarter.
So what you're going to see is we're going to start dropping our capital slightly.
And towards the end of the year, we can always ramp up, ramp down depending on what we see the commodity curve and what ---+ how we want to manage '19.
So no, I think first quarter is hot.
I don't think you use that as the trajectory for the rest of the year.
Yes.
We left our guidance range the same intentionally.
Go ahead, Doug.
Yes.
Thank you.
So we appreciate everyone's time this morning.
And as we noted, we're very pleased with the quarter.
Look forward to updating you on further progress, particularly in the Turner as well as other areas of our business.
And we appreciate the interest in the company.
And as noted, we have a significant amount of work to do, but we have significant opportunity, and we're very encouraged by the results to date.
And we'll look forward to sharing you ---+ sharing further progress in the coming quarters.
