Unit Corp

OTC:UNTC

Earnings Call Transcript 2018-Q1

[Operator]

Welcome to the Unit Corporation's First Quarter 2018 Earnings Call. My name is Jason, and I will be your operator. [Operator Instructions] Also please note, this conference is being recorded. During the course of the conference call today, the speakers may make statements that constitute projections, expectations, beliefs or similar forward-looking statements. The company's actual results could differ materially from those results anticipated or projected in any such forward-looking statements. Additional detailed information concerning the important factors that could cause actual results to differ materially from those in the information given today is readily available in today's press release under the heading forward-looking statements.

Additionally, during the conference, the company will be discussing certain non-GAAP financial measures. The reconciliation of those non-GAAP measures to GAAP measures can be found in today's press release. This document is available on the company's website. I will now turn the call over to Larry Pinkston, President and CEO. Mr. Pinkston, please begin.

[Larry Pinkston, executive]

Thank you, Jason. Good morning, everyone. We want to thank you, this morning for joining us. With me today are David Merrill, Les Austin, Frank Young, John Cromling and Bob Parks. Each of these gentlemen will be providing you with updates concerning their segments. We will then take questions at the end of the call.

For the last several years and through changing economic conditions, we have pursued a disciplined path to grow all 3 of our business segments while maintaining annual capital expenditure budgets largely in line with our anticipated cash flow.

While it is our belief that the segments work very well together, we continue to grow each segment with the object of reaching a scale of self-sufficiency.

As previously communicated in the earlier press release, we completed the sale of 50% of our ownership interest in our midstream subsidiary, Superior Pipeline Company, for $300 million, highlighting that segment's current value. While Unit retains day-to-day operational control, we and our new partners are focused on the continued growth of that business to further increase its value. Proceeds from this sale were partially used to pay off the outstanding balance of Unit's revolving line of credit. The remainder will be used to accelerate growth within our oil and natural gas segment, the midstream segment and for general working capital purposes.

Overall, the transaction provides substantial new liquidity to Unit as we focus on continuing the growth of all 3 segments. With the successful completion of our Superior transaction, we have elected to terminate our at-the-market offering of our common stock. That program, announced in February of 2017, resulted in the issuance of approximately 787,000 shares during the first half of 2017, generating proceeds of approximately $18.6 million.

Despite the company's strong liquidity position, our plan is to remain disciplined with our capital expenditures. We will spend our money where we believe it will result in the best return for the company.

I now would like to turn the call over to David Merrill.

[David Merrill, executive]

Thank you, Larry. Good morning, everyone. With WTI recently reaching multiyear highs, natural gas storage levels well below the 5-year average and the lingering effects of cooler weather and an improving outlook for NGL prices, we are optimistic about our business outlook. We had a solid quarter. In the midstream segment, it experienced per-day quarter-over-quarter gas processing volume growth, and the transaction that Larry just discussed positioned our company very well to continue to execute on our growth plans for all 3 business segments.

In our oil and natural gas segment, we expect year-over-year production growth of 7% to 9%, however, we expect production growth to be uneven on a monthly and quarterly basis due to timing associated with multiwell pad development program in the Buffalo Wallow area.

Individual well results continue to be promising in all of our 4 plays. We are pleased that our contract drilling segment was successful in securing the long-term contract for our 11th BOSS drilling rig, and we continue to have discussions with other operators about additional opportunities for growth of our BOSS rig fleet.

I'll now turn the call over to Les Austin.

[George Austin, executive]

Thanks, David. We reported net income for the first quarter of $7.9 million or $0.15 per diluted share. Adjusted net income for the quarter, which excludes the effect of noncash derivatives was $11.1 million or $0.21 per diluted share. Our non-GAAP financial measures, reconciliation is included in our press release. For the oil and natural gas segment, revenue for the first quarter increased 2% over the fourth quarter of last year with higher oil and natural gas prices being offset by lower production and NGL prices. Average daily production decreased primarily because of delays in the completion of new wells drilled. Operating costs for the first quarter increased 3% over the fourth quarter of last year because of higher lease operating expenses primarily due to increased workover expenses, saltwater disposal expenses and gross production taxes.

For the contract drilling segment, revenue for the first quarter decreased 1% from the fourth quarter of last year due to decreased mobilization and other revenue partially offset by increased utilization and day rigs. Operating costs for the first quarter increased 1% over the fourth quarter of last year because of more drilling rigs operating. For the midstream segment, revenues for the first quarter decreased 1% from the fourth quarter of last year primarily due to lower gas gathering and liquids sold volumes per day offset slightly by higher daily gas processed volumes. Operating costs for the first quarter decreased 5% from the fourth quarter of last year because of lower cost of gas purchased.

We ended the first quarter of 2018 with total long-term debt of $790.5 million, a reduction of $29.8 million from the end of the fourth quarter of 2017. Long-term debt consists of $642.8 million of senior subordinated notes, net of unamortized discounts and debt issuance costs, and $147.7 million of borrowings under our credit agreement. On April 2, Unit signed its fourth amendment to its credit agreement in connection with its sale of the 50% ownership interest in Superior. One condition of the sale was the release of Superior from the credit agreement. The fourth amendment also provides for, among other things, a maximum credit amount, a borrowing base and an elected commitment, all in the amount of $425 million.

The sales transaction closed on April 3, and the outstanding borrowings on the credit facility were paid that same day, bringing our current bank debt to 0. Our senior leverage ratio was 0.45x at the end of the first quarter, and the maximum senior leverage covenant is to be no greater than 2.7x our EBITDA. Pro forma for the sales transaction, our net leverage ratio would have been 1.63x at the end of the first quarter.

At this time, I will turn the call over to Frank for our oil and natural gas segment update.

[Frank Young, executive]

Good morning. For the quarter, per-day equivalent production was 46,500 barrels of oil equivalent, a decrease of just under 1% from the fourth quarter of 2017. Production for the quarter was in line with our expectations that it would be near unchanged compared to the fourth quarter of 2017 because of anticipated late first quarter timing of production from 2 multiwell pads at our Granite Wash play.

The slight drop in daily production from fourth quarter '17 to first quarter '18 was due to delays bringing 1 well online following fracture stimulation and a 2-week delay in beginning drilling operations in the Gulf Coast area. Despite these delays, the forecast for 2018 production remains unchanged at 17.1 million to 17.4 million barrels of oil equivalent, which is a 7% to 9% increase over 2017. In the Gulf Coast area, we continued our development, exploration and recompletion programs during the quarter. The Wing #18 located in the Wing lease near the Gilly Field in Polk County, Texas, was drilled and completed in the BPPC sand with the well flowing at rates of 6.3 million cubic feet per day and 75 barrels of oil per day. This was a successful discovery of a new interval in the Wing lease, and we are currently drilling the Wing #20 to further delineate this discovery.

In the Cherry Creek prospect, we plan to drill the [ Wolf Pastor ] #1, which is the delineation well for the Trinity #1, in the second quarter. In the Brandt prospect, the first exploration well, the Engel #1, continues to flow at rates of 7 million to 8 million cubic feet per day, and we plan to pick up an additional rig in the second or early third quarter to drill delineation wells in this prospect.

Also there were 8 recompletions and 2 workovers completed in the quarter. Our plan for 2018 is for 13 to 15 recompletions and 10 new wells, 8 of which will be vertical and 2 horizontal. Additional wells may be drilled depending successful delineation of our pre-exploration prospects.

In the Texas Panhandle Granite Wash area, we continue to drill extended lateral Granite Wash wells in the Buffalo Wallow field. We recently reached total depth from pre-extended laterals: the Carr #1H, the Carr #2H and the Carr #3H. These wells are now cleaning up after fracture -- after being fracture-stimulated in late March.

Our longest extend lateral wells, which are between 8,700 feet and 9,700 feet -- the Francis 1H, Francis 2H and the Francis 3H -- all had first sales in February. These wells were also cleaning up after fracking. Our plan is to continuously operate at least 1 drilling rig in the Granite Wash during 2018, which should result in 11 new extended-length lateral wells for the year.

In our Southern Oklahoma Hoxbar Oil Trend, or SOHOT, area, during the quarter, we completed 3 new Marchand horizontal wells. In January, we completed our first extended lateral Marchand well, the Schenk Trust #1-17HXL, with an IP30 of 2,318 barrels of oil equivalent per day. In February, we completed the McConnell #1-11H with an IP30 of 1,426 barrels of oil equivalent per day. The second extended lateral, the Livingston Land #1-33, has been drilled and is cleaning up after recently being fracture-stimulated in late March. During 2018, our plan is to continue with the 1-rig drilling program, which should result in a total of 9 new wells with 6 being extended lateral wells.

In Western Oklahoma, we spud our initial well, the Irwin #1-4H, in the STACK play located in Dewey County, Oklahoma, during March. Following the Irwin, we plan to drill a second STACK well off the same pad and then move the rig to drill 2 additional wells in Western Oklahoma.

At our last conference call, we said we plan for these 2 wells to target the dry gas area of the STACK reservoir in Custer County. However, gas takeaway capacity constraints in this area of the STACK have led to the potential for lower realized gas prices and/or constrained gas production rates. Consequently, the value of the large amount of gas resource, we feel our acreage position holds may be best optimized by delaying development until realized gas prices improve. Since our acreage in the STACK play is largely held by production and we have the option of delaying development, we may choose to target other reservoirs or other areas of the STACK play within our acreage holdings that offer less gas, marketing risk and better returns. During the quarter, we participated in a total of 7 nonoperated wells completed in the STACK play, and overall, we have participated in over 50 nonoperated wells in the play with an average working interest of about 5%. Results from this nonoperated program have been good, and we expect to continue to participate in 5 to 10 wells per quarter during the remainder of 2018. First quarter activity has set Unit Petroleum up for an exciting second quarter. During the second quarter, we will be ramping up production from 6 Granite Wash wells that will result in quarter-over-quarter production growth and more gas going to Superior's Hemphill plant, and in the Gulf Coast area, we will drill delineation wells in our 3 exploration prospects giving us a better idea of the size of the prospects and future development potential. We will continue to follow our strategy of spending within cash flow of our growing production and reserves, utilizing Unit drilling rigs and Superior midstream services for possible to capture more of the value chain, and augmenting our drilling inventory in areas that have relatively low play and acquisition costs but still offer competitive full-cycle economic returns.

At this time, I will now turn the call over to John for the Drilling Company update.

[John Cromling, executive]

Good morning. The contract drilling segment had a good first quarter with rig count remaining steady, revenue increasing as well as securing a long-term contract for our newest BOSS rig. Average day rate for the quarter was $17,038, an increase of $393 per day over the fourth quarter. The average total daily revenue with no elimination of intercompany profit was $17,223, an increase of $250 over the fourth quarter. Our total daily operating cost before intercompany eliminations increased by $622 for the first quarter as compared to the fourth. This increase was primarily due to our crew wage increase from the Mid-Continent and Permian rigs and an increase in payroll taxes resetting at the beginning of the year. The average per-day operating margin for the first quarter, before elimination of intercompany profits, was $5,179, which is a decrease of $371 from the fourth quarter. The majority of this decrease was due to higher-than-usual mobilization cost associated with 3 long-rig moves and a slight increase in rig cost. Our non-GAAP reconciliation can be found in today's press release. Our rig utilization remained constant throughout the quarter at 32 rigs. Currently, all 10 of our BOSS rigs are operating with 5 of them under current contract. We recently negotiated a long-term contract for our 11th BOSS rig. [indiscernible] of this rig has begun, and we expect it to be operating by July in the Permian. We also upgraded mud systems on 2 of our 1,500-horsepower SCR rigs during the quarter. We have several additional SCR rigs, which are excellent candidates for refurbishment as the market dictates. We do remain optimistic of our opportunity to grow during the next quarter.

At this time, I'll turn the call over to Bob for the Superior pipeline update.

[Robert H. Parks, executive]

Thank you, John. The midstream segment continued to produce solid financial results for the first quarter of 2018. Our operating profit before depreciation is $14.4 million for the first quarter 2018, which is an 11% increase over the fourth quarter of 2017. This increase is partially due to higher volume on our higher-margin cash and processing system and additional [ counter save ] at our Southeast Texas Segno gathering system. I will now focus on several key midstream assets. At our Hemphill facility in the Granite Wash area, our total throughput volume averaged approximately 67.5 million cubic feet per day for the first quarter of 2018, and we produced approximately 171,000 gallons per day of natural gas liquids. We had not connected any new wells to the system in the first quarter as are several recently drilled wells scheduled to be connected in the second quarter from the Buffalo Wallow area. Construction of laterals to connect these wells have been completed, and we expect to receive cash from these wells in the second quarter. Additionally, we started a compression expansion project that will increase the compression capacity in the Buffalo Wallow area in order to handle the expected increased production expected from this area. At our cash and processing facility located in Central Oklahoma, the average throughput volume for the first quarter of 2018 was approximately 42.6 million cubic feet per day. Our total processing capacity at this facility remained at approximately 45 million cubic feet per day. At this facility, we complete construction of our pipeline expansion that allowed us to gather and process gas from a new area in which the producer is actively drilling. We continue to construct lateral lines in this area to connect new wells as they are drilled.

During the first quarter, we connected 3 new wells from this area. Also, during the first quarter, we continued to receive gas from a producer who is committed to deliver volumes to us for a 5-year period. If they fail to deliver the required volume, he will pay shortfall fee, which will be settled annually. At our Pittsburgh Mills gathering facility located in the Appalachian region, during the first quarter of 2018, our total gathered volume averaged [ 5,106 million ] cubic feet per day. We are continuing construction of the pipeline to connect the next scheduled well pad. This new well pad is to include 7 wells and would be connected to our compressor station located on the southern portion of our gathering system. We expect to complete construction and begin gathering the production from this well pad by the end of 2018. Additionally, we're preparing to receive production from 7 infill wells that we drilled on 2 of our existing pads. These wells are expected to come online in the second quarter of 2018. In summary, we are pleased with our financial results from the first quarter of 2018. Total throughput volumes, while down slightly, are still better than budgeted for the first quarter. Gas processed volume and operating profit continues to increase, and we are positioned well for the remainder -- remaining part of 2018. Finally, I want to emphasize how excited we are about the recently announced 50% ownership of Superior by our new financial partners. With the financial resources now available to us, we are ready to take advantage of accretive opportunities that will accelerate the growth of our midstream segment.

This time, I'll now turn the call back over to Larry.

[Larry Pinkston, executive]

Thank you, Bob. As you can tell, we had a very good quarter -- first quarter of 2018. We feel very good about how the company is positioned to continue to pursue its growth strategies. We believe that the sale of the partial ownership interest in Superior provides a valuable data point in the valuation of that segment. Further, we are positioned to accelerate the growth of that part of our business with our new capital partners onboard. We also would accelerate the growth in Unit Petroleum as we move forward as we're adding an additional rig measure during this year and, of course, that in turn helps growth of both the midstream and the drilling segments as well.

We currently have the best inventory of highly economic well prospects than we have ever had. Frank and his team are working diligently to facilitate the best of these prospects possible. We are fortunate that our STACK division is largely held by production so that we can develop the asset in the best economic environment possible rather than being forced to do so while differentials are so lopsided in a constrained market.

Our BOSS rigs continue to perform exceptionally well. We're building #11. We're having discussions with operators about the next BOSS rig. The midstream partial interest sale resulted in a sharp reduction in Unit's leverage. Having new partners also intent to see the business grow should help facilitate cash flow expansion. Additionally, the cash received from the sale has resulted in a substantial amount of liquidity on our balance sheet. Finally, as always, we will remain focused on capital discipline.

I now would like to turn the call over for questions.

[Operator]

[Operator Instructions] Our first question comes from Marshall Adkins from Raymond James.

[J. Marshall Adkins, analyst]

I'm curious -- so the realized prices, at least for oil this quarter -- or this past quarter, were roughly $10 lower than the WTI price, maybe $15 lower than Brent. A lot of moving parts going forward. You gave us a detailed view of your hedging position. But there's geographical differences. I presume your Wilcox gets better pricing than the Panhandle, for example. You've got differentials bouncing around. When we think of where we should model that realized oil price going forward, give us some help with that progression.

[Frank Young, executive]

Marshall, this is Frank Young. Approximately, about 20% of our oil production comes from the Gulf Coast area, and there we get LLS oil prices, which are currently, what, $2.80 or $3 above WTI, and then our oil transportation fees coming off of that are around $3 a barrel-or-so, $2 a barrel. So we get close to WTI realized prices for the Houston area. The remaining oil that we have as oil in -- is mainly in either the Texas Panhandle or Western Oklahoma, and there we generally get WTI prices minus about $2 to $3 a barrel for transportation, and so those are our realized prices, and then, of course, you have to figure our hedging positions into the price after that.

[J. Marshall Adkins, analyst]

Right. That's my point, a lot of moving parts. But it seems like your realized price of $55-ish or whatever it was this last quarter ought to be drifting higher over the next several quarters as those hedges start to roll off by -- assuming oil stays where it is, maybe a year from now, we're $10 higher? Is that fair?

[David Merrill, executive]

Yes, Marshall, that's fair. We're about -- of our Q1 volumes, we're about 73% hedged for the remainder of the year. And as oil production comes up, obviously, we're going to be getting -- building out hedge price for that. But we're about 73% hedged at around $50 or just a little bit above that. So that's kind of keeping the cap on a good portion of it.

[J. Marshall Adkins, analyst]

Yes. Near term, and those roll off of over time.

[David Merrill, executive]

Right. And we don't have any -- we have a small amount of hedges for '19 on the credit side, not much.

[J. Marshall Adkins, analyst]

Right. So let's just assume for now prices stay where they are, never mind, I obviously think they keep going higher. Let's say they stay where they are. How do you see your full cycle returns in $65 or, h***, $68 WTI environment? I'm asking this because, obviously, you're going to put more money in the E&P. I just want to get some sense of what kind of returns you think you'll realize, not just on the next well but full cycle, including all the stuff.

[Frank Young, executive]

So it depends on the play that you're talking about. But if you're looking at, for instance, our SOHOT play, which is about 70% oil production, at that oil price, our full cycle returns will be up above 80% rate of return in that play, including our land cost, everything thrown in there along with the drilling and completion cost. Our other plays, the Granite Wash, STACK and Wilcox, will depend more on natural gas liquids prices than oil prices.

[J. Marshall Adkins, analyst]

Right. But let's say those prices hold more or less where they are here. Is it reasonable to assume you're looking kind of average 50% IRR for the other stuff?

[Frank Young, executive]

That would be close. Our Wilcox area is probably a little better than that, and our Granite Wash area is a little lower than that.

[J. Marshall Adkins, analyst]

Okay, great. Since you all are putting more money into that, I'm just trying to get a sense in terms of the modeling and the free cash flow generation. Last question from me. Your BOSS rigs are sold out. We're hearing from most of the drilling guys that -- those high STACK rigs are getting kind of low 20 to mid-20 stay rates and $7,000, $8,000 margins. What are your SCR leading edge getting since -- it seems like 2/3 of your active rigs are SCRs? What are the leading edge on those and the margins as well?

[John Cromling, executive]

First of all, I hear that same story, Marshall, a lot about the mid-20s for the high-tech rigs, but we're not seeing that yet. I'm just not seeing those kind of numbers yet. On the SCR rates, those prices are gradually coming up. I don't know if you're asking what do you think our day rates will be on that as much as what you're asking about the margins. But in many cases, when you look at the margins over a longer period than 1 quarter, those margins will continue to increase probably by 10% or 15%. And the reason I say you have to look at it longer because, as I mentioned earlier, we suffered some cost early on this year by making some long moves and, over the course of the year, those moves paid investment and those moves continue to pay back, and so our margins will increase because of that. And also, our margins are increasing because, for the type of rigs that the customer wants and that we can provide, there's not a future abundance of those right now that are high.

[J. Marshall Adkins, analyst]

Right. Well, let me ask a different way. What -- your last few SCRs you put out, what kind of rates are those getting just -- what I would call leading edge?

[John Cromling, executive]

Well, we actually haven't added any additional ones since back in late summer. We've maintained that same number that we've had -- I'm sorry.

[Robert H. Parks, executive]

New contracts.

[J. Marshall Adkins, analyst]

Yes, new -- exactly, the new contracts. Have they repriced recently?

[Frank Young, executive]

Okay. You want a number?

[J. Marshall Adkins, analyst]

Yes. Just -- is it $18,000 [indiscernible]

[John Cromling, executive]

$18,000 to $19,000, but they're [indiscernible] what we provide.

[Operator]

Next, we have Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

Question maybe first one just for Frank. Frank, I know in the prepared remarks you discussed this a little bit about the initial well test in the STACK play that Irwin well. Could you talk about what just -- I guess, what's the timing on that one when we might have a flow rate on that? And then your thoughts on, I forget if you said, sort of the plan for the remainder of the year on how active you'll be in that area.

[Frank Young, executive]

So on the Irwin pad, we plan on drilling 2 wells that were currently around 3 weeks away from TD-ing the first well. And then we'll skid the rig and drill the second well at that same pad. So the 2 wells will have to wait to be fracture-stimulated till both of them are drilled. And so likely first production is not going to be available until sometime in the third quarter, maybe the late second quarter, yes -- or maybe early third quarter, sometime or in that time frame.

[Neal Dingmann, analyst]

Very good. And then moving over to John on the rig side. I think I've asked you this before, it sounds like at least on the -- what is it, the 11th BOSS now, discussions are -- what -- it seems like every time you bring one of those out, you get it under -- I think you have 5 or [ 5 the 11 ] or [ 5 the 10 ] under very solid contracts, and even the other 5 seem to be going very well on a day-rate basis. Your thoughts on, are you having discussions on anything beyond this 11th rig? I just wondered what the -- sort of the bids are out there right now. How it looks versus quarters or 2 ago?

[John Cromling, executive]

Yes, we continue to discuss additional BOSS rigs all the time. We have take people, engineers, management from other companies to go visit our rigs for them to see them first hand. So we're fully expecting to be able to continue with our program. We just hope that we can accelerate it, but that continues all the time.

[Operator]

And next we have Charles Robertson from Cowen and Company.

[Charles Robertson, analyst]

All right. A little bit of follow-up for you, John, on that question. Sort of on the BOSS rig fleet moving to 11. What do you think is sort of an optimal size over the next 2 or 3 years for your BOSS rigs?

[John Cromling, executive]

That's a very hard question, Charles, because we've batted that around a lot. We see places for the BOSS rigs as they are right now to continue, but we also see the opportunities for wells that are not only longer laterals, but deeper from the kickoff point, wells that could be measured depth of 25,000 to 28,000 feet, and we're working on plans on how to accommodate those kind of -- the amount of pipe frac and just the loads that we would contend with. So my guess right now is that's the direction that we will change to as we go forward, but it doesn't -- it won't eliminate necessarily the rigs as they are either.

[Larry Pinkston, executive]

Charles, this is Larry. We'll continue kind of with our one at a time kind of program for a while. If it was -- unless we see demand picking up substantially. We're always looking at the market and what we think we can work in our market area. We don't want to overbuild, but we want to be able to take care of the customers that we have that will make one of BOSS rigs that we could deliver to. So is there a magic number? No, not -- that's going to be market-dictated, basically.

[Charles Robertson, analyst]

All right. And the question here for Frank on the Wilcox and the Wing prospect, the new interval. Can you go into a little more detail what you see there or...?

[Frank Young, executive]

Sure, the Wing #18 drill -- that well was drilled to a deeper depth and tested another sand in that fault block. The fault block from the sands have produced already and are currently producing will probably recover somewhere in the range of 60 Bcf-or-so, maybe even a little more than that. And this additional deeper sand will add on to that. Because we don't have a second well producing from that sand yet, we're unsure of where the gas-water contact is in that interval. And so at this point, I can't really say how big that could be. All I can say is that the Wing #18 has been a really pleasant surprise because we were concerned that, that deeper sand was going to be wet when we first tested it. But it's making over $6 million a day and almost 100 barrel of oil a day. So it's been a very nice surprise.

[Charles Robertson, analyst]

Very good. And then in the SOHOT area, obviously, very nice well results. Where do you think you are in just the completion design here? Are you still in the early stages?

[Frank Young, executive]

No. We always keep our eye on how other people are fracking their wells. At this point, the evolution of completion technology, in my opinion, is far down the learning curve. There's still a few things that are going on that are new on the divergent side and maybe how you pump and some things like that, but not anything monumental. And so we're pretty far down on the learning curve at SOHOT on the completion side.

[Charles Robertson, analyst]

Okay. And I guess, one final question if I can sneak it in here on having the additional rig, any thoughts -- it looks most likely into the Buffalo Wallow area. Would any other areas be considered?

[Frank Young, executive]

Sure. We could add -- we will add an additional rig. Well, we have the fourth rig running into STACK now. That fourth rig could end up drilling in Buffalo Wallow. Later on, it could also end up drilling more wells in Western Oklahoma in other areas of the STACK play. And we also have a -- the chance or the possibility to run a second rig on the Wilcox. So we have several different places we can run additional rigs, but we're currently just going through our economics, updating all those and showing Dave and Larry kind of the different economics, and we'll come up with a plan going forward here before too long in terms of exactly where we're going to run our additional rigs.

[Operator]

[Operator Instructions] We have no further questions at this time.

[Larry Pinkston, executive]

Thank you, Jason. Again, I want to thank everyone for joining us this morning. We will be out on the road over the next couple months and hope to see many of you then. But if not, well, have a good late spring. Thanks. Bye.

[Operator]

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating, and you may now disconnect.