Welcome to the Range Resources Third Quarter 2019 Earnings Conference Call. [Operator Instructions]. Statements made during this conference call that are not historical facts are forward-looking statements.

Such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in the forward-looking statements. After the speakers' remarks, there will be a question-and-answer period. At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, Investor Relations at Range Resources.

Please go ahead, sir..

Thank you, Operator. Good morning, everyone, and thank you for joining Range's third quarter earnings call. Speakers on today's call are Jeff Ventura, Chief Executive Officer; Dennis Degner, Chief Operating Officer; and Mark Scucchi, Chief Financial Officer.

Hopefully you've had a chance to review the press release and updated investor presentation that we posted on our website. We also filed our 10-Q with the SEC yesterday. It's available on our website under the Investors tab or you can access it using the SEC's EDGAR system.

Please note that we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures. For additional information, we posted supplemental tables on our website to assist in the calculation of EBITDAX, cash margins and other non-GAAP measures.

With that, let me turn the call over to Jeff..

we've paid down over $1 billion in debt, we've lowered our unit cost substantially and we've delivered on our operational plans for $20 million less than originally budgeted. The entire Range team and the Board remain committed and focused on keeping this momentum going into 2020 as we position the company for success through the cycles.

Dennis?.

Thank you, Jeff. Capital spending for the third quarter came in at approximately $160 million with our capital spend for the first three quarters totaling $576 million.

Based on our current activity forecast, fourth quarter capital spending is projected to be at a similar level of $160 million resulting in a total capital spend of $736 million for the year.

This is a $20 million below our capital budget spend set at the beginning of the year and is a direct result of the operational and technical teams' efforts to find and implement innovative operational efficiencies and ability to capture service cost reductions in the current environment.

Similar to last year, the initiatives driving our capital underspend are primarily attributed to the continued success of our water-sharing program, improved drilling and completion efficiencies associated with long lateral development and service cost reductions.

Utilizing other producers' water in the third quarter or, as we call it, water sharing, totaled 750,000 barrels and represents an over 80% increase compared to the same time period a year ago. And similar to our update for the second quarter, this translated into an approximate $2 million reduction in completion cost for the quarter.

Production for the third quarter closed out above 2.24 Bcf equivalent per day, exceeding our revised guidance for the quarter. The Sunoco maintenance that reduced the amount of ethane we produced in the third quarter has returned to normal operations in early October and will result in more efficient transportation to Marcus Hook going forward.

Better-than-expected field run time in our production operations and continued strong well performance from both new and existing wells across Southwest PA helped to offset a portion of the maintenance-related impact to ethane production in September.

Fourth quarter production guidance is being set at 2.33 to 2.35 Bcf equivalent per day as we expect to finish out the year with 28 wells being turned to sales or 29% of our annual 2019 turn-in-line number. Please note that our fourth quarter production guidance accounts for the recently announced royalty sales.

Looking back on some of the third quarter operational highlights. In Appalachia, the team turned to sales 22 wells on six pads during the quarter from an average lateral length of over 10,800 feet.

The new wells were spread across all three areas of the field covering our dry, wet and super-rich acreage and generated some of our top-producing wells for the year. I'd like to take a minute and cover some of the exceptional pads from each of these areas.

In the wet gas area, we turned to sales a strong pad that generated the top three producing wells for the year thus far. This pad is in the heart of the field with a per well average initial production of more than 40 million cubic feet equivalent per day.

This average initial rate also includes over 3,800 barrels per day of combined NGL and condensate production on a per-well basis. In the super-rich portion of the field, we continue to see results consistent with wells turned to sales in the first half of 2019. In the third quarter, eight wells across three different pads were turned to sales.

One pad produced over 2,500 barrels of condensate per day from just three wells and after two months continues to produce more than 1,500 barrels a day. And lastly, in the dry gas area, we brought online our second highest producing pad of 2019 where our six well pad generated an average initial production of more than 35 million cubic feet per well.

This dry gas pad continues to be a strong performer, producing over 100 million cubic feet per day after three months under constrained conditions. Each of these examples add to our growing list of strong performing, repeatable producing pads, as mentioned on previous calls.

As we look into the fourth quarter, we are scheduled to turn in line approximately 28 wells to finish out the year. These wells represent approximately 1/3 of the wells and nearly 40% of the total lateral footage to go into production this year, putting us on solid footing as we enter 2020.

In conjunction with our annual plan, the drilling team saw a reduction in activity during the third quarter as we moved to two rigs in Appalachia.

Even in the environment of a reduction in activity, the Appalachia drilling team was able to achieve gains in operational efficiencies while our daily lateral footage drilled increasing approximately 35% in the third quarter compared to the first half of 2019.

This substantial increase in daily footage drill can be directly attributed to utilizing new, directional drilling technologies for both curve and lateral applications. With initiatives like these, the team has been able to reduce the drilling cost per lateral foot by 5% in 2019 versus last year.

In addition to drilling wells quicker, lateral lengths to continue to increase year-over-year. Comparing to last year, the 2019 year-to-date average drilled lateral length is approximately 11,700 feet, which is a 13% increase over the average drilled lateral length in 2018.

And the increased drilled footage supports our early plans for 2020 to turn to sales wells with an average horizontal length of over 11,000 feet. Similar to our drilling operations, our completions team has continued to build upon their prior success by executing more frac stages in the third quarter with fewer frac fleets needed.

The efficiencies mentioned above, coupled with our innovative water handling, are keeping Range at the leading edge of well cost per foot and F&D cost per Mcfe. As part of that effort to stay a step ahead, I'd like to provide an update on two areas showcasing the creativity of our teams.

The first initiative is related to the electric fracturing fleet test that was mentioned on our second quarter call. The team has since completed our second pad with this fleet, which was located in our dry gas acreage in Southwestern PA.

Over 400 frac stages were completed on this pad while averaging almost nine stages per day, all while the team continued to refine procedures and processes during the operation. Efficiencies of over 10 frac stages per day were achieved multiple times with the peak level observed to 14 stages per day.

During the three month test run, the team captured fuel savings of over $1.2 million while also reducing emissions and noise levels. Looking at the early results, coupled with our unique, contiguous acreage position and regular ability to move back to pads with existing production, we see exciting potential with this technology.

We are currently preparing to utilize this electric fleet into year-end and are evaluating its potential versus conventional fleets for our 2020 program. The second initiative involves our production and facilities teams taking the next step in reducing emissions during flowback operations.

During the past few months, our teams have been able to update the equipment and processes used during flowback, which is resulting in further reduced emissions in our wet and super-rich operations in Southwest Pennsylvania.

The enhanced flowback process has been tested across seven pad sites, generating an estimated emissions reduction of over 80% during the flowback phase with essentially no impact to cost. The team is encouraged by the early results and plans to follow up with a test in our dry gas acreage early next year.

Given our team's dedication, hard work and creativity, we're optimistic the team will advance this initiative as we strive to reach our ultimate goal of zero net emissions. Similar to our commitment to the environment, our team strives to operate in a manner that protects the safety of our employees, contractors and the public.

Our focus on safety performance improvements this year has paid off by generating a 30% reduction in employee and contractor workforce OSHA recordables compared to the same time period last year.

In addition to our worksite focus, we have built upon the success of our vehicle safety program this year by expanding the use of vehicle monitoring system, and it's showing encouraging results by further reducing our preventable vehicle incidents.

We realize that we must continue improving our day-to-day safety and environmental performance to consider ourselves successful on all fronts of our operation. Now turning briefly to NGL marketing.

As we mentioned earlier, the Mariner East 1 pipeline was returned to service during the second week of October, allowing Range to resume transportation and exports of 20,000 barrels per day of ethane via the Marcus Hook terminal.

Propane and butane export arbs extended second quarter gains on continued strong demand and curtailments in supply from various regions. In particular, September Saudi oil disruption resulted in a sharp appreciation of export values for LPG.

With this occurrence, Range maximized the LPG exports during the third quarter using both pipeline and rail access to export terminals. Propane export values at the dock remain elevated and are currently estimated at $0.10 per gallon versus Mont Belvieu index.

The combination of ethane rejection during the quarter and access to international markets for propane and butane led to the best differential to Mont Belvieu that Range has realized in recent history.

Looking forward into 2020, Range plans to maintain a strong NGL differential as additional pipeline capacity becomes available next summer, enhancing margins through improved logistics and additional international exposure.

As I get ready to hand it over to Mark to discuss the financials, I'd like to close out by expressing our thanks to our teams for delivering on another strong quarter through creative initiatives, allowing us to deliver on our operational, safety and environmental goals, all below our planned capital budget resulting in our best operational program yet.

I'll now turn it over to Mark..

Thanks, Dennis. As we continue to execute on our strategy to navigate this commodity price cycle, third quarter activity focused on enhancing financial strength, increasing liquidity, reducing debt, reducing costs and maximizing cash flow generated by judicious capital investment. Pricing during the third quarter continued to be challenging.

Nevertheless, Range successfully closed several material transactions that bolster the company's financial foundation and continue to extend the visible runway and flexibility available to support our long-term strategy while mitigating near-term risks.

With operations tracking planned results, Range generated year-to-date cash flow from operations of approximately $550 million. Year-to-date capital investment is trending below the annual budget of $756 million. And as Dennis mentioned, we intend to finish the year with capital spending below budget.

In addition to capital conservation while executing operationally, Range has focused on operating and overhead costs with the benefit of this year's efforts evident in third quarter unit costs. During the third quarter, we delivered on plans discussed previously with cash unit costs better than guidance.

The quarter-over-quarter improvement of $0.06 per unit and $0.16 per unit compared to the fourth quarter of last year are the results of efficiency across the board led by improvements in gathering, processing and transport.

As a reminder, recall that Range guided to a $0.30 improvement over the course of the five year outlook, whereas year-to-date, we've already achieved over 50% of that goal.

In total, this puts current cash unit costs at $2.02 with expected further improvement to cash unit costs to below $2 and aggregate unit cost reductions in excess of the $0.30 improvement over time. On recent calls, we described gathering, processing, transport expense in some detail given its importance as the largest individual line item.

For the third quarter, GP&T was reduced to $1.43 per Mcfe compared to $1.51 in the fourth quarter last year. Consistent with our guidance, this line item peaked at the end of 2018 as our last contracted gas transport capacity came online. As planned, full utilization of infrastructure is driving down this cost on a unit basis.

Going forward, even in a maintenance capital scenario, there are reductions in absolute spend that can extend this improving trend in per unit GP&T costs near, medium and long term.

Range's lease operating costs, excluding workovers, have declined in absolute and on a per unit of production basis compared to the third quarter last year and compared to the preceding quarter this year with third quarter costs declining to $0.13 per Mcfe.

Incremental workover costs of $0.02 per Mcfe during the third quarter related to specific projects designed to optimize existing production. These were low-cost quick payback investments to make the most of existing infrastructure and production.

Continued strong performance is driven by diligent operations in the field with specific savings related to water handling. Cash G&A expense is an important figure during the third quarter as it is the first quarter reflective of a wide range of cost management initiatives.

Last quarter, I mentioned the target of achieving a 10% reduction in absolute spend on an annualized basis with third quarter cash G&A expense of approximately $33 million. This represents approximately a 15% decline from the preceding quarter and annualized, a similar decline from prior year.

While quarterly expenses do fluctuate, we expect the majority of this decrease to be sustainable and indicative of ongoing cost management. During the quarter, we closed on the sale of royalty interest for gross proceeds of $750 million.

This brings divestiture proceeds over the past year to approximately $1.1 billion, which has directly gone to reduce debt. On the topic of further balance sheet improvement, we are currently marketing several additional opportunities. These processes are in various stages.

And as we've consistently done in the past, we will announce results, but we'll not establish a public dollar threshold or definitive time line. Suffice it to say, we have a deep inventory projects that we believe we can divest at reasonable values, particularly in comparison to the value of our common equity.

Divestiture proceeds were used to reduce borrowings with the bank line of credit declining to $328 million at the end of the third quarter. The balance of the revolving line of credit also reflects the results of open-market repurchases of approximately $94 million in face value of bonds with maturities in 2021 and 2022.

During the quarter, we began opportunistically repurchasing this near-term maturities at a modest discount. It is our intention to continue strengthening the balance sheet through debt reduction and through proactively addressing near-term maturities.

Repurchasing these bonds and any future bond repurchases serve to facilitate refinancing in a cost-effective manner. Liquidity was improved with divestiture proceeds, but as recently announced, we also increased liquidity to the expansion of lender commitments under the revolver by 20%, an incremental $400 million to a total of $2.4 billion.

This brings available liquidity after borrowings and letters of credit to $1.8 billion. It should also be noted that Range's borrowing base remains at $3 billion with asset coverage potential above that figure providing additional cushion.

While there is time before the first bond maturity in June 2021, this incremental liquidity serves as a potential backstop to help manage maturities. We remain focused on reducing debt, reducing borrowing costs and maintaining a thoughtful maturity ladder.

Another component of our recent announcement was the initiation of a share repurchase program sized at $100 million. The size, timing and framework for deploying capital through this repurchase program was carefully considered. It is Range's first priority to maintain and strengthen its financial foundation.

With $1.1 billion in divestiture proceeds and an incremental $400 million in availability under the revolver, substantial progress has been made. Meanwhile, Range's stock price has suffered given commodity prices and leverage concerns.

However, when viewed from a variety of valuation perspectives, be it net asset value per share, cash flow per share, production per share or reserves per share, we believe the value acquired via shares at these price levels is compelling. Consequently, a share repurchase program equating to greater than 10% of current market cap has been approved.

While debt reduction remains our priority in light of the substantial reduction in debt and enhanced liquidity achieved, combined with our ongoing efforts, the potential allocation of less than 10% of recent divestiture proceeds for future opportunistic repurchases is a carefully balanced strategy.

As we look at the progress made in 2019 in terms of operating efficiently, safely, managing costs and the balance sheet, tangible achievements have been delivered against our strategic objectives.

As we work through plans for 2020, it remains our priority to fund the business organically from cash flow to further strengthen the financial position and continue to protect and grow margins through ongoing cost management.

In summary, we remain focused on continuous improvement to position Range to effectively navigate commodity price cycles and to create long-term value while prudently managing risk. Jeff, back to you..

Operator, let's open it up for Q&A..

[Operator Instructions]. The first question is from Arun Jayaram of JPMorgan..

Jeff, my first question regards the sustaining CapEx number. You cited $650 million for 2020. I was wondering if you could maybe give us a sense of what kind of rig count activity, TIL activity do you need to keep production flat from 2019 levels.

We haven't seen a little bit of a reduction in the rig count looking at some of the publicly available data, so I just want you to give a sense of what the 2020 program could look like on a maintenance or sustaining basis..

Okay. Yes. I'll start and then I'll turn it over to Dennis for a little more detail. But I think when you look at the capital spend that we had this year and you look at the rig cadence and going up and down a little bit, rigs are important. I think lateral footage drilled is really a critical way to look at it.

When you look at our wells carried in from '18 into '19 and '19 into '20 and what we're projecting from '20 to '21, that -- the lateral footage is pretty consistent. So again, we have an advantage in that we have a relatively low decline rate relative to our peers in high-quality wells and peer-leading PNC.

But Dennis, do you want to put a little more color on that?.

You betcha. Yes. Good morning. It looks like as we look forward -- I mean first of all, our planning group puts a lot of diligence in not only looking at what the upcoming year will present, but also the next couple of years that follow. So inventory management is something that we keep on the forefront in line with our activity.

What we've learned clearly over the last several years is that rig activity and rig count isn't always the best proxy for what kind of inventory that's going to be generated. So back to Jeff's point, it really comes down to lateral foot that we're going to generate. In the call, we touched on it.

But our drilling team has really done a phenomenal job just not only over the last 24 months, but just even also in the last quarter by drilling 35% faster in the lateral section compared to what we did on average in the first half of the year. So as we've been able to reduce down in rig count, a, it's been in line with our plan for the year.

We were -- we're always playing to be front-end loaded. But we also see that we're generating more lateral footage for the same number of rigs based upon the efficiencies our service providers and our operating and technical teams on the drilling side have been able to generate.

So we feel really comfortable with the inventory that's being generated here as we end off 2019 and get ready to go into 2020 and also see that being sustainable for a -- I mean this capital perspective for the years that follow.

To put some other framework around it, it's probably a couple of rigs as you look at the current efficiencies, and that's probably somewhere in the neighborhood of a couple of frac crews, 1 to 2 as well..

Great. Mark, a follow-up for you. You talked about -- in the prepared remarks about proactively addressing some of the near-term maturities. I believe you have a $500 million maturity or so in 2021 and just under $1 billion in 2022.

Could you talk about kind of your strategy for dealing with those maturities? You do have, I think you mentioned, $1.8 billion of liquidity, but give us kind of your action plan to addressing those maturities..

Sure, Arun. I think a very fair question. And what I would point to is the proactive steps, the preventative nature of our activities historically of addressing maturities well in advance in this particular environment, whether it's through asset sales and just the absolute debt reduction.

So far, obviously, as we discussed, over $1 billion of absolute debt reduction. The expansion of the bank credit facility provides again a backstop. So there is one alternative. But clearly, we will monitor the market and the conditions of the market for potential refinancing and move as soon as reasonably practical to push those maturities out.

We're, of course, cost-sensitive. But on a risk-adjusted basis, we just want to make sure, as I mentioned during my prepared remarks, that we have a nice, thoughtful, safe maturity ladder with no imminent maturities. So I know that's a generic answer.

But again, it's our approach to have multiple options, multiple ways of dealing with our financial and operational matters and decisions that need to be made. And I think we've kind of laid the groundwork for that on a financial front as well in terms of refinancing and having a backstop alternative..

The next question comes from Brad Heffern of RBC Capital Markets..

On 2020, I was wondering if we saw the flat price for gas stay similar to where it is now, around $2.30 or so.

Is there a chance that you could let production decline in order to keep from outspending cash flow? Or is maintenance CapEx sort of the floor on what a capital program could be?.

Brad, this is Mark. I'll start with that, and we may each chime in. So I think the framework we've outlined, the first priority is operating the business with organically generated cash flow. So that will be the premise that we base our 2020 plans on. We are seeing significant cost savings.

We're seeing improved operations, as Dennis just described a moment ago. So there is tremendous flexibility in our business model that overlays the asset base as well given the fact that all of our infrastructure is fully utilized. There are no drilling obligations that would require us to spend.

There's no competing force that necessitates kind of abnormal growth in this commodity price environment. So we have the flexibility of doing a maintenance capital. And to -- more directly to your question, there is a scenario where you could allow modest production declines, and we maintain our unit cost or unit cost levels.

So it is possible to allow production go into a modest decline..

Okay. And then I guess if you could give a little more color on the repurchase and just the priorities of that versus debt. Obviously, you guys like the share -- well, you don't like the share price where it is right now, but you'd like to acquire the shares where they are right now.

So if the stock stays at the current level, is it a program that could go relatively quickly? Or is it going to be balanced more delicately between repurchasing debt?.

Yes. I think first and foremost, you can see our priorities in terms of how we've deployed asset sale proceeds thus far. $1.1 billion in gross proceeds, and we've just now earmarked $100 million for share repurchase program. So looking at those two figures, you can see where we're placing the priorities.

That being said, we do see tremendous value potential in the shares and the resource potential, the production and the cash flow that can be acquired via a share repurchase program. So we are not going to provide a specific framework, a quantitative framework by which we're going to deploy that $100 million.

We're just going to be opportunistic and judicious with, again, protecting the balance sheet as a priority, but also deploying that $100 million program to create long-term value for our long-term shareholders..

The next question is from Karl Blunden of Goldman Sachs..

I appreciate the sensitivity around the explicit guidance on potential asset sale and royalty sales size. To some extent, it's important though when thinking about the size of the maturity wall to think about how much you could potentially do and then still have the result in NRI be acceptable for yourselves and relative to industry standards.

Is there any way to quantify it in that way?.

Well, I think just looking at the last 12 months is a good indicator. We've sold 3.5% overwriting royalty interest and some modest noncore acreage for gross proceeds of over $1.1 billion. If we look at other basis with NRIs averaging around 75%, we are still substantially above that.

There's obviously a host of options we have in our portfolio that we could seek to divest and generate proceeds; royalties are certainly among those.

So if we're trying to draw a larger box around it, I think, for lack of a better example, I would just look at what we've accomplished over the last 12 months and say that there's really a possibility of replicating something like that..

Got you. That makes sense. And I have noted of course that the valuations you received have been pretty much constant over the last 12 months. That speaks to some debts in the market.

Just with regard to some comments around potentially considering revolver drawings to pay down bonds, I understand that decision is to be made at a later point in time, we've seen some periods in oilier basins, I mean covenants to allow for in excess of, for example, 700 million of drawings to do that.

Is that -- how should we think about the size and how much liquidity you'd use on your revolver to do that versus sitting down and making a tough decision as to is this the time to extend maturities using secured debt, for example?.

So we are not in a position any time in the near future to have to really begin seriously exploring layering the existing senior notes.

The revolving credit agreement allows us to repurchase debt, which we've already begun that program, as I mentioned, and the details are disclosed in the 10-Q, but we've repurchased face value of $94 million between the '21 and '22 notes already at a modest discount.

So there's an opportunity here that we can continue opportunistically repurchasing those near-term maturities, '21s and '22s. So it just helps facilitate a refinancing when that becomes appropriate in time line. So there is a modest limitation in the credit agreement.

But as long as we have 15% availability under the commitments, we can repurchase up to that amount under the revolver. Clearly not our intention to just pull all of that in and use bank debt to do it. But just as frame of reference, that's the level and extent of the liquidity we have available to us..

The next question is from David Deckelbaum of Cowen..

I just have maybe just one broad question, just about the buyback. Just curious on the timing that you're introducing it now. You guys have highlighted the discounted PDP for some time.

Was this sort of the discount one you over -- just the prolonged duration of that, was this an external demand? Is it something that internally you all had devised? Just curious around the timing had come up now, particularly in light of the endeavors to delever the balance sheet..

It's a culmination of the efforts that had been under the way this year, first and foremost, being debt reduction is the short answer. Valuation certainly plays a part in that. But first and foremost, it was repositioning the balance sheet with $1 billion in debt reduction..

Okay. And then just to ask on the maintenance capital going into next year. I think you all have delineated the $650 million or so all-in and then around $550 million or so just on D&C side.

One, I guess, is that sort of the broad level to think about beyond '20 in that five year plan, that sort of $100 million of other capital? Does that inflect lower at all? And then I guess, two, I suppose it doesn't -- that wouldn't necessarily benefit from any tailwinds of -- you're not necessarily including savings on the water side in those numbers because I'd like to get a better sense of what we see drilling activity being lower in Appalachia over time if there's just a greater upside then on water savings from water sharing..

David, this is Dennis. Yes. I think in the last call, one of the things is we started to touch on the capital required for maintenance capital. I think we may have said at one point in time, the numbers you're framing of $550 million to a $600 million kind of assessment, that was also earlier in the year, end of 2018 kind of view.

But once the program for 2019 then took shape, front-end loaded activity had a stronger ramp in production for Q4, it's what started to fluctuate, if you will, to maybe be more closer to that $650-million-type number. I don't think we're viewing $100 million in non-D&C capital as a part of that right now. It should be something significantly less.

And I think a lot of it has to do with when you look at our responsible land capital spending, as an example, a lot of our acreage is held by production.

So land spending has reduced year-over-year not only as we've seen the land get held through our activity, but also through just those strategic leases that need to be picked up then start to get smaller and smaller. So we would estimate that delta between the non-D&C capital and D&C to be much lower than what you've reflected here..

Okay. All right. Understood. And then just to -- if you could, any color on just the water savings you're experiencing.

Is this just a function of just lower activity in the basin and less demand for water?.

A few years ago, I'm going to say this was probably the 2014-2015 time frame. We've -- we had been on at that point about a three to four year run of recycling 100% of our produced water in Southwest PA. So good initiative there, very creative by our local team there in Pennsylvania.

What they then saw was an opportunity to expand that through water sharing with other operators. Clearly, as their program started to slow in activity, we had the ability to utilize more of their water. Though we're at 100% recycling in those years, it still makes up about 40% to 45% of our total water use.

So there's an opportunity to take other people's water. So we view it as a win-win. We view it in line with our ESG reporting that we announced earlier this year, which we're excited about. And we see this as savings not only that we're capturing this year, but we also captured it similarly last year.

Will we be able to continue this? We're optimistic that we can. And a lot of it has to do with those partnerships and the relationships we develop with those other operators. With our contiguous acreage position, it really lends itself to the ability to capitalize on those savings year-over-year depending upon the program..

[Operator Instructions]. We will go to Kevin Cunane with Citi for our final question..

I just had a quick question on your unit cost assumptions under your maintenance CapEx scenario. You mentioned transportation coming down despite moving to maintenance.

So is that just your Louisiana contract pulling off? Or is there something else there as well?.

There are variety of pieces to it. Just continuing to optimize the existing transport, there's a processing contract rolling off. There's some other more modest local gas transport contracts that we can rearrange and/or allow to expire. So it comes in a variety of forms, including perhaps moving NGL transport off of rail on to pipeline.

So there's a number of forms that help drive a reduction in spend even in maintenance CapEx-type scenarios..

Got it. Understood. And then I guess just on your DUC count.

Do you guys have an active drill down fleet that you've owned through the end of year and into next?.

Yes. I would say -- yes. Kevin, we have a very consistent -- I would say, a lot of it's really fairly just in time based upon the activity level that we have. So rarely have we carried a strong DUC inventory.

And a lot of that has to do with the fact that once we're moving in to do that activity, we have a pipeline in the ground in most cases and we're ready to produce those wells. So we're carrying a very consistent DUC inventory from 2019 into 2020 that you would see within a small bandwidth from prior years as well..

This concludes today's question-and-answer session. I'd like to turn the call back over to Mr. Ventura for his concluding remarks..

I just want to thank everyone for participating on this morning's call. Thanks and feel free to follow up with additional questions with our team..

Thank you for your participation in today's conference. You may disconnect at this time..