Chesapeake Energy Corp (CHK) 2017 Q1 法說會逐字稿

Good day, and welcome to the Chesapeake Energy Corporation First Quarter 2017 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, and thank you for joining our call today to discuss Chesapeake's financial and operational results for the 2017 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 should help facilitate comparisons across periods and with peers.

For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure may 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 call over for Q&A.

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

Thank you, Brad, and good morning.

We're pleased with our first quarter results, and we are confident in our ability to deliver our strategy and 2017 priorities of: first, increasing EBITDA through oil production growth, superior capital efficiency and cash cost leadership; and second, further improving our balance sheet through debt reduction.

The first quarter reflects continued progress on these priorities.

And of note, our performance is consistent with our Analyst Day guidance provided back in October of last year.

Chesapeake has reached an important and pivotal point in our transformation.

The company is now returning to production growth from our portfolio of high-quality assets.

Importantly, our oil production will be increasing in the second half of the year at a meaningful pace.

From a first quarter 2017 level of roughly 84,000 barrels of oil per day, we are on track to achieve our target of 100,000 barrels of oil per day by year-end 2017.

As a result, we raised the lower end of our oil guidance range for 2017 along with our gas and NGL guidance.

The significant increase in our oil volumes will also provide an accelerated rate of change to our EBITDA and margins.

The oil growth rate will be driven from 3 assets: the Eagle Ford, the Powder River Basin and the Mid-Continent, which are all poised to deliver stronger volumes as the year progresses.

In the Eagle Ford Shale, we set a daily oil production record from a new well with a peak rate of 2,800 barrels of oil per day or roughly 3,200 barrels of oil equivalent per day.

This is one of our longer lateral wells that was also completed with more sand per foot and tighter cluster spacing compared to our standard design.

We plan to place more wells on production with these enhanced completion methods, and we believe the enhanced completions can generate both a production and economic uplift to our program.

We also drilled our first Upper Eagle Ford Shale well with an 11,300-foot lateral.

This well was placed online yesterday, so we should have a peak production rate to report in a few weeks.

Our South Texas assets will be the major driver of our oil volume growth through 2018.

And we expect continued strong results through our long lateral drilling program, improved base optimization and shorter cycle times.

In the Powder River Basin, we announced our first operated Turner well in March that reached a peak rate of 2,560 barrels of oil equivalent per day with a 78% oil cut or 2,000 barrels of oil per day.

This well continues to display strong performance, with gross cumulative oil production of approximately 36,000 barrels during its first 30 days of production.

Our second Turner well, the Rankin, is expected to be placed on production next week.

And we anticipate this well will deliver equivalent or better production on a per-foot basis than the first well.

Although Rankin has a shorter lateral, approximately 4,500 foot compared to 7,100 foot in the first well, the Rankin has higher pressure at a shallower depth.

The higher pressure and an impressive 45-foot flare while drilling the lateral is expected to translate into greater deliverability on a per-foot basis.

Finally, we cored the Turner and the Rankin well, and they were saturated with oil.

It looks really great.

We'll have a good sense of the production from this well in a couple of weeks after it's turned in line.

And dependent upon these results, we may elect to move another rig to the Powder River Basin to focus exclusively on the Turner.

We also drilled our first 2 Parkman wells in the Powder River Basin this year -- our first of 2 Parkman wells in the Powder River Basin.

While production is constrained, the first well has already reached a peak rate of 714 barrels of oil per day or 763 barrels equivalent per day.

We have also placed 3 notable Niobrara DUCs on production this year, which had peak rates of approximately 750, 1,200 and 1,215 barrels of oil per day.

In the third quarter, we plan to put to sales approximately 9 to 12 Sussex wells, and we'll begin to flow back our first deep Mowry test.

The Powder River Basin is revving up at Chesapeake, and we expect a substantial rate of change in our oil production from this asset over the next several years.

In the Mid-Continent, we drilled our first extended lateral well targeting the St.

Genevieve formation in Major County, Oklahoma.

This well was put online recently and is still cleaning up, so we plan to release these results soon.

We plan to drill up to 20 additional extended-lateral wells in the St.

Genevieve formation in 2017.

We will also be testing additional formations in the Mid-Continent later this year, including the Chester limestone and sandstone formations.

We control approximately 230,000 net acres that we believe are prospective for the Chester, and we have taken 2 full cores to help us optimize our completion designs.

We are looking forward to our first test results from the Chester in the third and fourth quarters.

Our turn-in-line count of 76 wells in the 2017 first quarter is expected to increase to around 120 wells in the second quarter, then range between 120 and 140 wells in the third and fourth quarters.

The turn-in-line rate should be a strong indicator of the [path for] momentum we are building in the latter part of 2017 and as we enter 2018.

The combined results from these oil-directed investments are delivering.

The average oil rate for April is more than 1,000 barrels of oil per day above our first quarter average oil rate.

And current daily field estimates are approaching 90,000 barrels of oil a day.

We are on the ramp.

Our strategic focus and near-term priorities will result in continued incremental positive improvements in our operations and financial position.

I believe the strength of our portfolio, determination of our employees and relentless pursuit of improvement will drive competitive, differential value for Chesapeake shareholders, leading with superior capital efficiency, cash cost management, strong oil growth and financial flexibility.

I'll now pass the call to Nick for further details regarding our first quarter performance.

Thank you, Doug, and good morning, everyone.

We're pleased with our earnings and cash flow results for the first quarter.

Our production exceeded the midpoint of our projections based on strong gas performance in the Appalachian region and strong oil production from new wells drilled in the PRB, Mid-Con and Eagle Ford.

Looking ahead, we believe we've seen the low in our oil production in February, and our production ramp in the second half of the year looks very strong, fueled by a significant increase in wells placed online over the next 3 quarters.

On the cost side, we've continued to reduce our production expenses sequentially from the fourth quarter and expect those to decline even further in 2017 on a boe and production basis.

We're forecasting that our G&A will increase slightly throughout 2017, primarily as a result of costs moving from LOE to G&A due to last year's asset sales.

Given the movement between LOE and G&A, it's important to measure the combined trend.

And together, LOE and G&A per boe decreased by 2% sequentially, indicating a drop in the absolute spend.

Our gathering, processing and transportation expenses also improved sequentially on a boe basis, and we look for these to move lower throughout the year.

We reduced our GP&T guidance along with our basis guidance on all 3 -- our oil GP&T guidance along with our basis guidance on all 3 products.

Basis has improved considerably, and the reduction in our forecasted basis differentials is meaningful.

We continue to work on improving our realized prices by moving our crude and NGL production to better price points by accessing new markets for these barrels and optimizing our point of sale for all 3 products further downstream.

As a reminder, we noted on our fourth quarter earnings call that we bought down a couple of midstream commitments at favorable economics during the first quarter for roughly $390 million in cash.

The results of these buy-downs will show up beginning in our April financials.

All of these cost improvements, LOE, G&A, gathering and transport and marketing, have led to a 10% improvement in our margin per boe, excluding the increase in commodity prices.

Many of these operating cost improvements are a result of refining the assets in our portfolio around our most profitable basins and properties.

This gives us confidence in the sustainability of the margin increases as prices recover.

And in fact, as we see volume growth of new wells and base production increases, we look for economies of scale to provide further opportunities for improvements.

As we noted before, our cost structure is becoming a competitive advantage for the company and one that we are very focused on maintaining and growing as prices recover.

On the A&D front, we closed our 2 Haynesville asset packages in the first quarter and continue to work smaller asset packages, particularly in the Mid-Continent area.

We will continue to optimize our portfolios and work toward our goal of removing another $2 billion to $3 billion of debt off our books.

Following the end of the quarter, we satisfied the judgment of $441 million related to our 2019 notes litigation on April 28, which also relieved the associated letter of credit.

Our liquidity following this payment and the pending release of the LC is approximately $3.3 billion.

As a reminder, this had no impact on our liquidity as the posted LC had already removed the amount from our liquidity.

It's certainly worth noting that inclusive of this payment and the opportunistic buy-down of certain midstream contracts we completed during the quarter and open-market purchases of debt, we are seeing higher-than-expected available liquidity for the company due to strong performance of our underlying business.

Finally, for 2017, we currently have approximately 75% of our remaining projected gas production hedged at $3.05 per Mcf and approximately 64% of our remaining projected oil production hedged at $50.25 per barrel.

Using the midpoints of our production guidance, we have also started to hedge a portion of our 2018 gas production at a little over $3 per Mcf and a small portion of our 2018 oil production over $51 per barrel so far.

To close, we believe that the next 18 months are going to be very exciting for Chesapeake as we start to see significant earnings and cash flow growth and margin expansion due to greater oil volumes, larger producing wells across our portfolio and new plays like the PRB that, combined with our leading operating cost structure and capital efficiency, will start to make a meaningful difference in the financial performance of the company.

That concludes my comments.

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

(Operator Instructions) Our first question comes from Neal Dingmann with SunTrust.

Say, Doug, a question -- to question the great results in the Eagle Ford on those enhancements, I guess my question is pertaining to the Eagle Ford.

Do you see that enhancement potentially working in the entire 270 -- I guess, I would say the enhancements and Upper Eagle Ford potential, do you see that in most of your 270,000 acres there?

Sure.

I'm going to ask Frank to follow on.

I would just make a quick comment.

As you recall back when we did our Analyst Day, we're roughly 25% developed in the Eagle Ford.

And so as we apply those longer laterals and those completion technologies, we do see additional opportunity for improved rates.

And I'll just ask Frank to just chime in there with our further development program.

Yes.

Neal, we're working through enhancing the completions on all the future wells, also looking at changing our targeting to maximize the value of each of these wells.

The -- that's an ongoing opportunity we have.

And as we move forward, I don't know that all wells are going to react to that level, but we've seen -- we think we're going to be able to improve all the wells going forward.

So we think it's going to be a step change in our development plan.

The Upper Eagle Ford, that will be over a portion of our acreage, and we're going to just wait and see what this Upper Eagle Ford test looks like before we commit to what that means to us.

Very good.

And then just one follow-up, Doug.

Obviously, you don't -- with the liquidity that Nick laid out, certainly, there's not an immediate need for further sales, and I think there was some confusion on what you guys have maybe laid out for the year.

Could you just talk about potential noncore sales as it pertains to the rest of the year?

Sure.

We have not put a specific target sale number out there for 2017.

I will tell you, we are actively continuing to evaluate the portfolio.

Noncore, non-operated, lower-EBITDA, lower-production properties are our first target.

We are still very focused on the guidance we provided to the investment community back in October of achieving $2 billion to $3 billion of additional asset sales over the next few years.

The strength and quality of the portfolio, the size of our acreage position, we're very confident in our ability to deliver that.

And we will continue to update you and provide you further information as we progress.

But the keynote is that we are actively continuing to evaluate and look for further asset sales.

We'll go next to Doug Leggate with Bank of America Merrill Lynch.

Doug, the Powder River is obviously gaining a lot of traction here.

I think a number of your peers have also talked about it with some of the highest returns in their portfolio.

So I understand you're talking about maybe moving some rigs over there.

But can you talk about the running room that you see at this point?

Because I guess inventory life is still being established on how this would stack up relative -- pardon the pun, how it would stack up relative to some of the other plays as it relates to incremental capital allocation.

Sure.

This is Frank.

I would like you to just kind of go -- look back at the October data that we gave you.

We are on track there.

We have a large number of Sussex wells that we're going to be pushing through the system because at the time, that was the best economics in the portfolio for the Powder and some of the best economics in the company.

We've now tested the Turner on one side, and we're waiting on turning the second Turner well in line.

Honestly, we've had that well drilled and ready to turn in for several weeks.

It was a tight location, and we could not do what we've been doing, which is building our facilities ahead of time, so we had to build our facilities after the rig left.

That well will be turned in line here in the next week or so.

And when we get that well online, I think that's going to open up the Turner as a really good position to run with.

And that's several hundred wells that we can drill there.

They're going to have outstanding economics, probably, as we see it today, better than the Sussex.

So that's going to jump to the top of the list, and that's why Doug and we've talked about, in that instance, we're going to move -- probably move another rig into focus on the Turner.

The big question, the next big question is going to be the Mowry.

We've now [PD-ed] the first Mowry well.

We'll be putting it online here in the second -- into the third quarter, and that will open up additional running room.

So we see really strong running room in the Sussex, which we define by that big sandbar that we've been chasing, the Turner across a majority of our acreage.

Niobrara now with the new enhanced completions look much better than we had anticipated.

So that's going to open up.

We see this as several thousand locations available to us, and that, remember, is on relatively broad spacing.

If we see an opportunity to down space here, that's just going to increase our opportunity set.

That's what you needed, Doug?

It kind of is, but it's really a segue to a second question, Doug, if I may, which is that -- and Frank, thanks for the answer -- that -- so we look at the way your portfolio is evolving.

Northwest STACK seems to be moving up the relative priority list as it relates to, again, your opportunity set.

And I guess I really just wanted to ask the monetization question slightly differently because the only thing that really seems to be holding you back from getting recognition for some of this stuff is there's still high leverage of -- or a high level of debt and leverage obviously.

So I guess what I'm really asking is that, as you evolve the portfolio towards these more oily areas, higher-rate areas, more economic areas, how do you think about the relative reset in your portfolio?

I'm thinking specifically Marcellus and whether you would ever consider accelerating asset sales across some of your more pure-play gas names -- gas positions.

Sure.

It's a great question, Doug.

And as we evaluate the portfolio constantly, the churn in evaluation consists of, what is the EBITDA generation?

What is the future potential?

What is the competitive investment thesis in our portfolio of great assets going forward?

The key in my mind and across the company is that we're going to continue to improve our operations and continue to improve our balance sheet and look for opportunities to reduce our debt further as quickly as possible.

I'd just draw your attention back to what the investment community's view of the Haynesville was a few years ago and to the significant value that our operating expertise and experiences, what that's done and the uplift there that we've recognized and the value of that asset in the past few years as we continue to drill and produce just big boomer wells there in the Haynesville Shale.

That same transfer of technology and operating capability, we've pushed to the Powder River, and we have that excitement there.

And as you look at the Marcellus and the Utica in the Northeast, these are very, very strong cash-generating assets, some of the best rock -- shale gas rock in the world.

When you can spend $100 million and keep an asset flat at 2 Bcf a day for the next 5-plus years, it's a tremendous asset to have in our portfolio.

What I'm getting at there is that if we can accelerate the value, we will absolutely do that and consider bigger asset sales, broader asset sales to accelerate the value to our shareholders.

But make no mistake, along the way, as we evaluate the portfolio and continue with our investment thesis, we're driving the greatest value in a very disciplined capital program, pursuing that free cash flow neutrality.

Essentially, if it weren't for some of the extraneous items the past several quarters, we have -- our spending has been in line, capital spending for drilling and completion CapEx within our EBITDA.

And we're going to continue those asset sales and look for opportunities to add the value.

But make no mistake, across the portfolio, we're making meaningful improvements that will generate value for our shareholders in the future.

We'll go next to Brian Singer with Goldman Sachs.

Similar-type question with regards to capital allocation.

You talked a number of times about liquidity, and wondered if you could talk to your priorities on liquidity versus leverage.

As you see the good results that you've highlighted here in the Eagle Ford and the PRB and allocate more capital to drilling and then potentially another rig in the PRB, what are the key metrics that guide you?

Is it more liquidity driven, as you've mentioned?

Or is it leverage, particularly as we think about in an environment if oil prices don't go up as much from here?

It's Nick.

I'll take that.

The primary financial focus of the company is going to continue to be to drive our debt balance lower and meet our long-term debt targets.

If you think about the excess liquidity that we generated through strong operational performance, I commented in my prepared notes this morning that we have diverted some funds to reducing some burdensome contracts.

Those were done at favorable economics, and I can assure you that as we think about doing something like that, we compare it to the relative benefit of retiring debt and think about the yield on doing so and found that retiring those contracts was more attractive.

So when you think about the excess liquidity that we generated above plan, we apply it back to a cost improvement, effective leverage reduction, and we will always be focused on reducing our leverage until we hit our goal.

When Doug talks about reallocating some capital to the Powder River, think about the fact that, that may very well be just that: a reallocation, not a net increase in rigs.

And as we get into the second half of the year and we see what kind of commodity price environment we're heading into in '18 and we determine what our proper total capital spend going into next year should be, given the market environment, given the cash flow we expect to generate, that's when you would make a decision about whether or not that's a net add or it's a shift.

So the focus remains debt reduction.

Liquidity, we protect, but I think we are comfortable with the liquidity we have.

We don't want to see it eroded to grow production, grow cash flow unless it's doing so in a really high rate-of-return way that is additive to our overall efforts of reducing leverage and rating -- putting the company in a position to generate free cash flow.

So none of these things can happen overnight unless you're willing to destroy value, and we're not.

So we're getting there.

And the previous question about asset sales is still very, very much front of mind for us, and that will continue to drive the majority of our leverage reduction.

That's great.

And my follow-up is with regards to the Haynesville.

Could you give us the latest on what you're seeing from a well performance perspective?

And then I think you mentioned the 3 rigs there with gas prices, at least on a [front-month] basis, above 3, but also other opportunities in the portfolio, how you're thinking about the direction of the rig count, up or down, as we go forward?

This is Jason.

I can speak to the well performance.

Again, we think we've got a good recipe out there for our frac designs.

We've gone from a high end of wells that had 50 million pounds of sand with a starting point of wells with 30 million pounds of sand.

So we've settled somewhere in between.

We're planning to test the high end of it, but I was -- I went out to the field the other day, and I stood on a location making 41 million cubic feet a day.

So we're still making some really large wells out there, and the team has actually got some wells, looking out on the schedule, that could be 15,000 feet compared to the 10,000-feet wells we have been drilling.

So those will be a step change in productivity as well.

So we're really happy with the performance in the Haynesville.

It's one of our, I'd say, more consistent plays with respect to well performance, and we think we've got a good recipe there that works for us.

Great.

And rig count trending up, down, stay flat through the end of the year?

We're planning to stay flat at 3 rigs right now.

But again, as we think about reallocating to oil locations, this could be one of those areas that see the shift.

But for now, the plan's 3 rigs to stay flat.

We'll go next to Charles Meade with Johnson Rice.

I'd like to ask a question on your PRB Turner well, the Sundquist well, and I'm looking specifically at Slide 5. Is -- I wondered if you could talk a little bit about how that well is performing.

And one of the things that I'm looking at is that -- the cumulative graph is pretty straight, so just some very little decline there.

And can you talk about that, what you're seeing either on the decline rate or the pressure trends you had there?

This is Frank.

We're really not seeing decline right now.

Remember, these -- the Sussex and the Turner are actually silty sandstones, so they react a little bit differently than, say, your unconventional plays that are the shales or something much, much tighter.

There is actually some permeability in this rock, so it's going to behave a little bit differently.

We will start seeing pressure and production decline, but right now, the well is really just kind of cleaning up and getting its horsepower behind it.

So that's why we're pretty excited about this.

If you remember the way the map was when we laid it out in October, this well is over on the very western edge of what we thought the play was.

It was kind of a well that we needed to drill on a federal unit to maintain the federal unit.

And we also had a good Parkman over there, so we decided to drill it and take a core.

The core was better than we expected, and the productivity of the well is much better than we expected.

Then we moved basically 17 miles to the east, the other well that we're waiting to turn on.

It's in a much -- probably a better part of the rock.

That well is a shorter lateral, but we carried a pretty big flare with high mud weight while we were drilling that.

And that well is just ready to turn online as soon as we get the facilities hooked up.

So this Turner is -- looks like it's on the upper end of what we expected.

So we're pretty excited about it, and that's why we're talking about if both of these work the way they look like they're going to work, we're going to have to start focusing some serious effort on the Turner here.

And the beauty of it is we can develop Turner off of Sussex pads.

We can develop Niobrara and Turner off the same pads.

I mean, this is a STACK play where we're going to be able to develop a lot of production off of smaller footprints.

We have to manage that, though, because we don't want to tie up a bunch of drilling and completion capital and not get the volume.

So we're working through a field development plan right now to put all this in play.

That's great color, Frank.

And then if I could go back to the Haynesville, there's some smaller competitors out there that have the -- elevated the Bossier, I guess, really, the middle Bossier as an important target for them.

And I know you guys haven't talked about that a whole lot recently.

But if I go back, you guys had delivered some really impressive Bossier results in the southern half of DeSoto County.

So -- or DeSoto Parish, I should get that part right.

Can you talk about where that Bossier is as a target for you guys?

Yes.

It's definitely -- I mean, that's -- it's different quality across the field.

We've got it in the more southern half of our acreage.

We are -- we've got some plans to test it with some of these enhanced completion techniques.

So we'll do that.

But it's -- for us, it's still second tier to the core Haynesville play.

So we've got some tests.

We can provide more information.

We haven't tried one of these really big jobs on those wells yet, but we've got one coming up this year, so we'll provide more information on that.

But we stick with our bread and butter, which is the Haynesville right now, for the bulk of our development.

Yes.

Charles, this is Frank.

I think we've got a Bossier well coming up in the next quarter.

So we will have some results towards the end of the year.

Is it third quarter?

Third quarter, okay.

We'll go next to David Heikkinen with Heikkinen Energy Advisors.

I had a quick question just thinking about your October Investor Day where really the Wedge play played a long-term driver for your growth, and you spent a lot of time highlighting details in other regions.

Can you kind of categorize and help us understand the diversity of what you're testing, what you're exploring and what's in development with the current rig count and kind of wells that are turned online this year?

Yes.

This is Frank again.

In the Wedge play, specifically as we described it, the Wedge basically was -- from the bottom up was basically the Hunton, the Woodford and then the Osage, the Meramec and the Chester.

What we've focused on initially is we've had a few wells testing different concepts.

But we've kind of honed in right now on the Meramec for the time being because it has high productivity.

We have a really good footprint.

We've been able to put together a really nice acreage position on top of what we already had.

One of the reasons we haven't talked about a lot of results is because we're continuing to add to our acreage position out there and coring up.

And then we knew the Chester was something that we were really interested in, and no one had really chased it much.

But when you look at the map, the reason it hasn't been chased much is because we own about 230,000 acres of it, and we own the core of it.

So we needed more data on that.

We've now drilled 2 wells and taking core, and we're laying one of those wells out horizontally and will be doing some completion testing.

The thing about the Chester, it's -- they're thinner reservoirs.

They do produce vertically, they're oil prone, but there's 4 to 5 STACK reservoirs on our acreage position.

So we're really interested in that play, but we want to do the science and get it right both on the geo side and on the completion side.

Okay.

So with the leasing program, I guess by the end of the year, you might have a better idea of how that -- that big Wedge of '18 forward.

I guess what the Wedge does is what it sounds like.

That's why you have this Powder discussion now.

Yes.

What we're seeing -- we are seeing good productivity out of the wells.

We just haven't had a chance to really ramp it up.

We are now move -- we've now moved another rig into the play that -- to accelerate the Meramec side of that.

We are just being cautiously optimistic on the Chester right now until we get some more data.

But what we've seen so far in the core is pretty attractive.

We've got to design some completions, though, to make that really hum.

So outside the Meramec, everything else is testing and exploring.

The Meramec really is in full development mode.

Yes.

I think if you would talk to the team, we're moving into more of the development mode in the Meramec, and we're still in the testing phase on all the other horizons.

We have not drilled the Hunton well yet.

That's way down the road.

Our final question comes from Jason Wangler with Wunderlich.

I just was curious, as you talked about the activity in the Powder River, how you see the infrastructure that you have now up there and where that could go as you kind of look to ramp it up a little bit more across all the formations.

Jason, this is Frank again.

Really good question.

We have to get in front of the infrastructure here.

We're looking at water pipelines for both supply and disposal.

We have -- our water disposal system is fine right now for what we're doing.

The bigger issue is going to be, should we start laying oil gathering lines and go to a large central facility?

That's being worked today.

As I stated previously, the pieces being worked right now is that field development plan.

What's it going to look like at the end of the day?

And how can we maximize the infrastructure around that and limit the infrastructure that we have to put in the ground?

On the gas side, we have plenty of gas takeaway at the plant, but if the Mowry works, we're going to have to look at expanding that capacity.

And we have -- we're working with our gas gathering partner there to work through that problem.

We'll have more information on that by the end of the year as we get the Mowry tested.

Okay.

Well, that concludes our comments and questions.

Thank you, operator.

I would just like to reiterate the confidence that we have in our program and highlight that we continue to deliver exactly what we said we would.

And that's exactly what we will be doing going forward, focusing on increasing our EBITDA through our oil production growth, utilizing our operating efficiencies and cash cost leadership, capital efficiency and continuing to improve our balance sheet through further debt reduction.

Thank you, operator.

That concludes our call.

That concludes today's conference.

We thank you for your participation.