Unit Corp

OTC:UNTC

Earnings Call Transcript 2018-Q2

[Operator]

Welcome to the Unit Corporation Second Quarter 2018 Earnings Call. My name is Eric, and I'll be your operator for today's call. [Operator Instructions] Please note that 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 the 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 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 also 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. Larry Pinkston, you may begin.

[Larry Pinkston, executive]

Thank you, Eric. Good morning, everyone. Thank you for joining us this morning. With me today are David Merrill, Les Austin, Frank Young, John Cromling and Bob Parks. These gentlemen will be providing you with the updates about their areas of responsibility. We will take questions then at the end of the call.

We continue to face volatility in the overall energy industry, which is driven by questions over the expanded production from OPEC, possible demand loss due to tariffs or increased prices. But despite these questions, we still see improvement in crude and natural gas liquids pricing. Recent EIA monthly data reflected a slight reduction in daily U.S. production and continued withdrawals in U.S. inventories. Both factors are very supportive of these prices. Also, natural gas liquids pricing is supported by export levels and the new petrochemical demand as evidenced by Exxon's Baytown plant commissioned during the last few weeks. Ethane pricing at Mont Belvieu has improved to a point it now makes ethane recovery economically viable.

On the natural gas side, we saw a very cold end to winter and a quick entry of hot weather this spring. Natural gas storage levels are near the bottom of the 5-year average. While there appears to be plenty of production supply, pipeline constraints have limited the full impact of that supply on the market. Our view for natural gas is that we may not see the return to $2 level, but we do not expect them to get too high either. Overall, commodity pricing provides us with some comfort that we're positioned well to carry out our growth plans going forward.

Finally, as we have previously discussed, we completed the sale of a 50% equity interest in Superior Pipeline, effective April 1, 2018. Partners Group and OPTrust have proven to be valued partners in this new endeavor. Together, we are focused on identifying opportunities to accelerate the growth of our midstream business.

I'd now like to turn the call over to David.

[David Merrill, executive]

Thank you, Larry. Good morning, everyone. Before we get to the segment reports, I would like to say that we had a very good quarter, one that sets up the rest of the year and beyond for a very solid growth. Our oil and natural gas segment posted slight quarter-over-quarter production growth, but more important, we have laid the groundwork for continued success in our Wilcox play. Our Brandt and Wing prospects have provided very encouraging results. And in the Granite Wash at our Buffalo Wallow field, we are making progress to further improve efficiency and well economics from well cost reductions. We look forward to seeing further results. Our contract drilling segment has had a great quarter, placing our 11th and newest BOSS drilling rig and 2 SCR rigs into service. And we stand at 35 rigs operating. As a testament to the performance of the BOSS rig, we have received contracts to build 2 additional BOSS rigs, and we recently had an operator sign 2-year contracts for 2 of our existing BOSS rigs. With the recent joint venture transaction of the midstream business that Larry was referring to, we are well placed to accelerate growth in this segment. While we are actively seeking bolt-on or other acquisition targets, we continue to capitalize on organic growth opportunities. Those opportunities, if realized, can improve liquids pricing, to accelerate the growth of this business segment. While we pursue growth of all 3 segments by accelerating our drilling program in the oil and natural gas segment, adding new BOSS rigs in the contract drilling segment and adding plant capacity at the Cashion facility in the midstream segment, we maintained our customary disciplined approach to capital spending.

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

[George Austin, executive]

Thanks, David. We reported net income attributable to Unit for the second quarter of $5.8 million or $0.11 per diluted share. Adjusted net income attributable to Unit for the quarter, which excludes the effect of noncash derivatives, was $11.3 million or $0.21 per diluted share. Our non-GAAP financial measure reconciliation is included in our press release.

For the oil and natural gas segment, revenue for the second quarter decreased 1% from the first quarter of this year with higher oil and NGL prices and increased NGL and natural gas volumes being offset by lower oil production and natural gas prices. Operating cost for the second quarter decreased 10% from the first quarter of this year because of lower lease operating expense, saltwater disposal expense and gross production taxes. For the contract drilling segment, revenues for the second quarter increased 2% over the first quarter of this year due to increased utilization, day rates and mobilization revenues. Operating cost for the second quarter increased 1% over the first quarter of this year because of more drilling rigs operating. For the midstream segment, revenues for the second quarter decreased 4% from the first quarter of this year primarily due to lower gas sold prices, somewhat offset by higher liquids sold volumes per day. The operating cost for the second quarter decreased 5% from the first quarter this year because of the lower cost of gas purchased.

We ended the second quarter of 2018 with total cash and cash equivalents of $104.3 million and long-term debt of $643.4 million, a long-term debt reduction of $147.2 million from the end of our first quarter of 2018. Long-term debt consists entirely of our senior subordinated notes, net of unamortized discounts and debt issuance costs. Our net leverage ratio was 1.6x at the end of the second quarter. On May 9, Superior signed a new 5-year $200 million senior secured revolving credit facility with an option to increase the credit amount to up to $215 million, subject to certain conditions. At our June Board of Directors meeting, an increase in our annual capital expenditures budget was approved. Our capital expenditures budget was increased by $69 million from $322 million to $391 million as follows: oil and natural gas segment increased $28 million from $272 million to $300 million; contract drilling increased $23 million from $47 million to $70 million; and the midstream segment increased $18 million from $32 million to $50 million, of which 50% is attributable to Unit. Each of the respective segment leaders will discuss the planned changes.

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

[Frank Young, executive]

Good morning, everyone. Total production for the second quarter was 4.21 million barrels of oil equivalent, a 1% increase over first quarter production. On a per day basis, second quarter production was 46,300 barrels of oil equivalent or 0.3% lower than the first quarter and approximately 1% lower than our expectations going into the quarter. During the quarter, production from our SOHOT area was significantly curtailed due to high line pressures experienced when Enable, our primary midstream gas gatherer and processor, tied in and commissioned their Wildcat Pipeline that takes rich gas from Western Oklahoma to a processing plant in North Texas. Production loss from this event, coupled with much smaller losses due to downtime at processing plants in our Houston and Texas Panhandle areas, was approximately 90,000 barrels of oil equivalent for the quarter. Without these losses, second quarter daily production would have totaled 47,300 barrels of oil equivalent or 2% higher than the first quarter. Further significant curtailments, while possible, are not anticipated. Despite these curtailments in the second quarter, the forecast for 2018 production remains unchanged at 17.1 to 17.4 million barrels of oil equivalent, a 7% to 9% increase over 2017.

Today, I will give an update on our 4 core areas. However, I want to spotlight and spend the most time on our Gulf Coast Wilcox play, which has grown to become Unit's largest producing area. While the production growth and success we have had from the Gilly Field has been impressive, I will focus on the exploration success we are having. First, in our Wing prospect, we drilled and completed the Wing #18 during April in the BP Fee "C" sand, which lies just beneath the BP Fee and BP Fee "A" sand intervals, which to date, have been the primary producing intervals in the Wing prospect. The Wing #18 initially flowed at rates of 6 million cubic feet per day and 75 barrels of oil per day with pressure of 5,000 pounds per square inch. After over 3 months of production, the well was flowing at rates of 6.5 million cubic feet per day and 55 barrels of oil per day with over 2,700 pounds per square inch pressure. Following the Wing #18, we drilled and completed the Wing #20. Besides the BP Fee "C" sand found in the Wing #18, the Wing #20 found pay in the deeper BP Fee "D" and BP Fee "E" sands, and all 3 intervals were fracture-stimulated in June flowing a 7.5 million cubic feet per day and 80 barrels of oil per day with 3,000 pounds per square inch of flowing pressure. After 6 weeks of production, the well is flowing at rates of 5 million cubic feet per day and 45 barrels of oil per day with 1,200 pounds per square inch pressure. A production log is planned for the Wing #20 to determine how much each of the 3 completed intervals is contributing to the total flow rate before deciding on where and how many additional wells to drill. Both the Wing #18 and Wing #20 encountered pay intervals in the shallower BP Fee "A", BP Fee and [ gray zone ] sand intervals, which provide excellent future recompletion opportunities.

Unit has 2 additional exploration prospects adjacent to the Wing prospect that we will drill and test over the next year, and we will collect 3-D seismic data to prove out a third prospect in the next 12 months. As an additional economic advantage, Superior gathers the gas produced from the Wing area, and Unit drilling rigs are used to drill the wells. In our Brandt prospect near Goliad, Texas, the Engel #1, our successful discovery well which was completed in December of 2017, has flow rates of 6 million cubic feet per day with 1,000 pounds per square inch pressure after 7 months of production. We spud the Engel #2 with the Unit drilling rigs to delineate this discovery in early June and are now in the final stages of the completion. Following the Engel #2, we spud the second delineation well that will be completed in the third quarter. 4 pay intervals are present in each of these 3 wellbores and like the Wing prospect, offer excellent future recompletion targets or horizontal drilling options. Once we see production from the 2 delineation wells, we will have the data to plan additional development wells for the Brandt prospect. Development drilling would likely begin in the fourth quarter of this year or first quarter of 2019.

Beyond the Brandt prospect, we have identified 10 additional prospects in the Goliad area in various stages of maturation. The first of these prospects will likely be drilled in the next year. In the Cherry Creek prospect, which is located approximately 7 miles southwest of the Gilly Field, we continue to pursue our pipeline permit from the Army Corps of Engineers for the [ Wolf Pasture #1 ], a delineation well to the Trinity #1 successful exploration well. However, bald eagle habitat was in the originally planned pipeline path, resulting in our having to use a secondary path, which will delay our required permit approval until late in 2018. Consequently then, anticipated spud date for the [ Wolf Pasture #1 ] has slipped to either the fourth quarter this year or first quarter of 2019. Production from the Trinity #1, which appears to have stacked pay intervals, continues to be encouraging, and we remain cautiously optimistic about the potential size of the Cherry Creek prospect.

The Gulf Coast receives premium commodity pricing and like our other 4 plays is an area where Unit drilling and when possible, Superior allow Unit Corporation to capture more of the value chain. Unit's Gulf Coast team has worked hard over the last 2 years to build upon the success in Gilly Field and develop a deep inventory of overpressured stacked pay prospects in the prolific Wilcox trend. The Wing, Brandt and Cherry Creek prospects are just the first fruits of this effort. Beyond these prospects, the team has over 30 additional prospects along the Gulf Coast in various stages of maturation. Over the next 18 months, we likely will drill and test 3 to 5 of these additional prospects, which we believe will allow us to keep the momentum that Gilly Field has provided and continue growing.

Gilly Field was a home run. Our goal is to hit another one or a bunch of singles and doubles. In the Texas Panhandle, we continue to drill extended lateral Granite Wash wells in the Buffalo Wallow field. We are bringing 4 wells online after recently drilling out the frac plugs. And we have 2 more wells drilled and awaiting completion. We plan to continuously operate at least one drilling rig in the Granite Wash during 2018. Also, we brought in a second Unit rig during July to drill 2 Granite Wash G extended lateral delineation wells, offsetting our initial Granite Wash G normal length horizontal well that we completed in 2014 and that has been a prolific producer. Results from these 2 Granite Wash G tests will be available before year-end.

On the cost front, dissolvable frac plugs are being tested, which may reduce or even eliminate the need to drill out frac plugs. Our current expected cost to drill and complete a Granite Wash extended lateral well is in the $6.2 million to $6.5 million range. If the dissolvable frac plugs technology proves successful, our well cost would be reduced by $300,000 to $500,000. In our SOHOT area in Grady County, we completed the McGuffin #2-19H at initial rate of 700 barrels of oil equivalent per day. We also drilled 2 extended laterals, which are now being fracture-stimulated. Our first extended lateral well, the Schenk Trust #1-17H, which was brought online in January with an IP30 of over 2,300 barrels of oil equivalent per day, continues to perform impressively at over 600 barrels of oil equivalent per day, 75% of that being oil. Our rates of return on this play exceed 100%, and we will continue running one rig to drill extended lateral Marchand wells for the foreseeable future. Our goal in the SOHOT area is to add sufficient acreage to pick up a second rig. We added over 800 net acres during the first 2 quarters of 2018 and have identified additional prospective acreage we are attempting to acquire via purchase or trade.

In Western Oklahoma, Unit's initial well on the STACK extension, the Irwin #1-4H, and Osage horizontal reached total depth in late May. We have since drilled the Irwin #2-4H, a Meramec horizontal, in the same section utilizing the same well pad. Both wells have recently been fracture-stimulated and are in the early stages of testing. The STACK rig will drill 2 additional horizontal wells during the third quarter before likely being released while we observe the well's performance. Unit's nonoperated STACK activity or average working interest is about 5%, has exceeded our expectations, and our results continue to be very good. To date in 2018, Unit has participated in 11 wells that are producing, 32 wells that are in some state of being drilled or completed and 28 wells that have not spud yet.

Unit Petroleum's capital budget for full year 2018 has increased $28 million from the original budget. 35% of this increase is to fund the high level of nonoperated STACK activity. Most of the remaining increase in 2018 capital is to fund incremental drilling, primarily focused on testing the Granite Wash G in Buffalo Wallow field and delineating the Brandt prospect in the Wilcox trend. While this additional drilling won't impact 2018 production significantly because the production will not come online until late in the year, this drilling will allow Unit to prove up more reserves and bring more clarity to our drilling program in 2019.

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 very good second quarter with rig count steadily increasing, cash flow increasing and securing long-term contracts for 2 additional BOSS rigs. The average day rate for the second quarter was $17,330, an increase of $292 per day over the first quarter. The average total daily revenue with no elimination of intercompany profit was $17,465, an increase of $242 over the first quarter. Our total daily operating cost before intercompany eliminations were relatively flat for the second quarter as compared to the first. The average per day operating margin for the second quarter before elimination of intercompany profits was $5,412, which is an increase of $233 over the previous quarter. Our non-GAAP reconciliation can be found in today's press release.

Our rig utilization increased throughout the quarter from 32 to 34 rigs, and there are now 35 rigs operating. All 11 of our BOSS rigs are operating with 7 under term contracts. Fabrication of our 11th BOSS rig was completed, and it is now operating in the Permian Basin. We recently negotiated 2 long-term contracts for our 12th and 13th BOSS rigs. The first of these 2 rigs will be completed in the first quarter of 2019 and will operate in Wyoming. The operator for this rig also extended the contracts on 2 other BOSS rigs currently drilling for them for an additional 2 years. The second newbuild will be completed in early 2019 and operate in Oklahoma. Performance of the BOSS rigs and the crews continue to impress the operators, which allows us to continue building this series of rigs. We're completing the upgrade of another of our SCR rigs. This rig is under contract and will begin operating during the third quarter in Oklahoma. We have several additional SCR rigs, which are excellent candidates for refurbishment and upgrade as the market dictates.

We increased our CapEx budget by $23 million to $70 million, which is primarily associated with the 2 new BOSS rigs. It is important to note that all of the above projects are being financed by operating cash flow. We continue to be optimistic about our opportunity to grow during the next quarter and into next year.

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

[Robert H. Parks, executive]

Thank you, John. For the first half of the year, having completed the sale of 50% interest in the midstream business to outside investors, Superior continued to produce strong financial and operational results. Total throughput volume increased 5% to 391 million cubic feet per day compared to the first quarter of 2018 and increased 2% compared to the same period last year. These increases were mainly due to increased activity around our Cashion facility and from connecting 7 new infill wells to our Pittsburgh Mills gathering system in the Appalachian area. Operating profit before depreciation and amortization was $14.4 million for the second quarter of 2018, which was essentially unchanged compared to the first quarter this year and a 19% increase over the second quarter of 2017. This increase over the second quarter of 2017 is primarily due to higher processed volumes from several of our processing systems and additional condensate collected at our Southeast Texas Segno gathering system, along with [ forecasted ] volume in the Appalachian area at our Pittsburgh Mills facility. Per day gas processed volume increased 6% to 161 million cubic feet per day compared to the first quarter of 2018 and increased 19% compared to the second quarter of last year. This increase was primarily due to the higher processed volume at our Cashion facility from new wells connects and additional offload volumes. We invested approximately $13.8 million in capital projects in the first half of 2018, mainly for the Cashion expansion project and a pipeline extension project to connect the new well pad at our Pittsburgh Mills system. Our capital expenditure budget approved at the June board meeting increased $18 million to $50 million, of which 50% is attributable to Unit.

I will now focus on several key midstream assets. In the Appalachian area at our Pittsburgh Mills gathering facility, our total gathered volume averaged approximately 116 million cubic feet per day during the second quarter of 2018. This was due to connecting 7 new infill wells late in the second quarter. We're constructing a new pipeline that connects the next scheduled well pad on this system. This new well pad will include 7 wells and will be connected to our [ Quincy ] compressor station on the southern portion of our gathering system. We anticipate completing construction and gathering the production from this well pad by the end of 2018. We will have connected 14 new wells at Pittsburgh Mills by year-end 2018. At our Hemphill facility in the Granite Wash area, our total throughput volume averaged approximately 73 million cubic feet per day for the second quarter of 2018, and total production of natural gas liquids increased to approximately 269,000 gallons per day. During the second quarter, we continued to connect wells in the Buffalo Wallow area. We connected 4 new Buffalo Wallow wells in the second quarter, which contributed to our increased throughput volume. As Unit Petroleum continues to operate a rig in the area, we're completing a compression station expansion project that will increase compression capacity in the Buffalo Wallow area to accommodate additional volumes. At our Cashion processing facility in Central Oklahoma, the average throughput volume for the second quarter of 2018 was approximately 44 million cubic feet per day, and natural gas liquids production increased to approximately 231,700 gallons per day.

Total processing capacity at this facility remains at approximately 45 million cubic feet per day. Due to being near plant capacity and to the high volume of stacked formation drilling on dedicated acreage around this facility, we have begun adding a 60 million cubic foot per day processing plant to be named the Reeding plant in the Cashion area. This $17 million plant construction project is getting underway and will increase the total processing capacity to approximately 105 million cubic feet per day. This project is expected to be completed and operational during the first quarter of 2019.

During the first half of this year, we connected 6 new wells to the system and expect to connect several more in the second half of this year. At our Minco processing facility in Central Oklahoma, our average throughput volume for the second quarter was approximately 12 million cubic feet per day, and natural gas liquids sold averaged approximately 31,200 gallons per day. Total processing capacity at our Minco facility is slightly more than 12 million cubic feet per day. Due to the high-volume of projected drilling on dedicated acreage in the Merge play around our Minco facility, we are evaluating the economics of moving the existing 25 million cubic feet per day processing [ skid ] to the Minco plant site.

In summary, we are pleased with the sale of 50% interest in our midstream business and look forward to being in a position to continue to grow the midstream segment. Financial results for the second quarter of 2018 showed positive increases in several areas. Our operating profit continues to improve, and we are well positioned for the second half of 2018.

I'll now turn the call back over to Larry for his final comments.

[Larry Pinkston, executive]

Thank you, Bob. Eric, I think now we'd like to turn call over to questions please.

[Operator]

[Operator Instructions] And our first question comes from Neal Dingmann from SunTrust.

[Neal Dingmann, analyst]

Frank, I think my first question is for you. You had a bit of curtailment there at SOHOT with obviously the Wildcat Pipeline, just my thoughts going forward with the remainder of the year, what's -- how do you see that in that same area as well as would there be potentially any other curtails that you're thinking about?

[Frank Young, executive]

We think that the Wildcat Pipeline has been fully commissioned. We don't anticipate any further curtailments from that pipeline commissioning. Currently, our line pressures are similar to what they were before the Wildcat Pipeline was commissioned. However, having said that, the stacked area had water rigs running in it. Production -- gas production there continues to grow. And so there's a possibility that we could see some areas that would be curtailed in the future although we don't expect to see that. As far as our deep gas drilling that we have, we're continuing to watch the gas basis, the differentials between NYMEX and what gas price we get in that area before deciding to pick up a rig there. Those basis differentials have shrunk somewhat, so that's good. And we're continuing to see exceptional deep gas well results especially from -- mainly from Continental in that area. And so we still have -- we have high hopes for that area. We have a lot of reserves there. We're just waiting for the optimal time to start drilling as our acreage mostly is filled by production.

[Neal Dingmann, analyst]

Okay. And then just one over for John on the rig side. John, can you just talk a bit about -- day rates and even margins continue to see a nice little move up second quarter. Can you just talk a bit about how you see those sort of trending today? Are you seeing any cost pressures, maybe just on the day rate side as well?

[John Cromling, executive]

We are seeing rates continue to increase, even though our second quarter rates didn't increase very much, but the addition of rigs that we added additional equipment to and are refurbished and then the BOSS rigs, those new rates are much better than where we have been. So we continue -- we think that will continue. We're encouraged by the new BOSS rigs we have under contract. The rates they're going to work for were also with a rig that I mentioned that's being refurbished right now, that will go to work next month. We're happy with the rates there. So we're seeing the more significant increases on those kinds of rigs, on the BOSS rigs and the refurbished SCR rigs. We see less of an increase on the 1,000-horsepower SCR rigs that are working.

[Operator]

And our next question comes from Marshall Adkins from Raymond James.

[J. Marshall Adkins, analyst]

Frank, let's start with you. The costs on the E&P side were a lot lower than we've been modeling. Can you give me some thoughts as to what drove this? And are they sustainable as a greater throughput? Or were we just modeling it wrong?

[Frank Young, executive]

Yes. So our operating cost, you're talking about our operated [ property ]?

[J. Marshall Adkins, analyst]

Yes, and your overall margin is just a lot better in that segment too.

[Frank Young, executive]

Right. So we saw 3 reductions in kind of our operating cost there. One was from a production tax standpoint, we had some -- a refund come in. That was a credit that we received from drilling high-cost gas wells, in what they term high-cost gas wells in Texas. And that came in during the quarter better than we had expected. We continue to get refunds going into the future, but the timing of those is not something that's easy to estimate. And so while we project some of those in our financials, so far, they've come in a little better than what our projections were. Also, we had lower saltwater disposal expense. We continue to just become more and more efficient at disposing of water because of the capital that we've spent on the infrastructure -- saltwater disposal infrastructure side. And then finally, we saw some reductions in our lease operating expense because we did fewer workovers in the second quarter than we did in the first quarter.

[J. Marshall Adkins, analyst]

So it sounds like part of that is certainly sustainable?

[Frank Young, executive]

Some of it is sustainable. But some of it -- depending on our workover activity, that can swing from quarter-to-quarter.

[J. Marshall Adkins, analyst]

Right, okay. That's helpful. Larry, let's switch to you. Pretty meaningful increase in CapEx across the board on all the segments. Walk me through your thought process there. Are you just more confident in the sustainability of commodity prices? Or is it you anticipate your cash flows being higher so there's more money to spend, or better returns? What's going through your mind when we're -- I mean that's a pretty meaningful improvement in capital spending.

[Larry Pinkston, executive]

Most of it, Marshall, is driven by the economics of the opportunity piece that we're seeing. We're -- for instance, the rigs, I mean, you don't get a chance to get long-term contracts on rigs, on BOSS rigs every day. When you have those opportunities, you need to be in a position to be able to capitalize on those very economic opportunities. And as you know, it's very, very hard to forecast when you're going to be able to get contracts. And typically, we've never started -- or we've never brought a rig to the field ready to go without it being contracted. So that drove part of it. That's going to drive some of that in this year, some of it into next year. The economics of drilling on the E&P opportunities with the new fracking, with extended laterals just continues to get better and better. So to that question, with our capital position, where it is today, we do have more capital available. But we've never let having capital available drive our capital decisions. So it's the efficiencies. It's the economics of the opportunities that are driving decisions, and of course, it looks like cash flow this year is going to be higher than what we expected when we originally put the budget together last November.

[J. Marshall Adkins, analyst]

All right. Last one for me. On the new BOSS rigs, can you give us some sense of the contract duration you're now signing and kind of pricing that you're -- that's implied there? And lastly, when you roll over those -- the other ones, I'm assuming those will roll to a higher price. Just give us some color on that.

[Larry Pinkston, executive]

So I'll let John answer. But we hesitate about getting very specific on the day rates on individual rigs, Marshall. So we'll give you some guidelines here on them but not...

[J. Marshall Adkins, analyst]

Yes. Just generically, what are leading edge? And then what's -- the duration of the contract would be helpful too.

[John Cromling, executive]

Yes. Marshall, this is John. One of those -- the first of the 2 BOSS rigs, that's a 3-year contract. And that also is with the same operator that we presently have 2 BOSS rigs operating for in Wyoming. And consecutive with that contract, they extended 2 of our other contracts by 2 years, which is a real plus. The other BOSS rig is going to go to work in Oklahoma. That's a 2-year contract. So 3 years, 2 years is where we are on those. Of the rigs that are presently under contract and meaning we're negotiating the extension of those contracts as they come due, those will have increases of somewhere between 5% to 15%. It varies, of course, on where they are right now because we have made some incremental changes as we go. So I think we're going to be very competitive with that type rig with the day rates.

[J. Marshall Adkins, analyst]

And leading edge now in the 23 range maybe?

[John Cromling, executive]

I think that's close.

[Operator]

And our next question comes from Charles Robertson from Cowen.

[Charles Robertson, analyst]

My question is for Frank to start. Over in the Granite Wash, beyond the disposable plugs, are you changing any other completion or drilling in the well to lower the cost there?

[Frank Young, executive]

We are on the frac stage. We increased our -- the amount of perf clusters we're perforating with in each stage and decreased the number of stages we're doing, and we've been able to do that by adding diverters to our frac. So we feel confident now that we can frac a stage that is longer length than what we have before with more perf clusters and still get the frac we want in each perf cluster because we are able to divert fluid between the perf clusters as that stage is pumped. Our overall job size has not changed. We still do the same job size, but by cutting down on stages, it reduces the number of plugs we have to drill out and also reduces the time that we take to frac a well, which reduces our cost.

[Charles Robertson, analyst]

And then, I guess, turning to the Wilcox, what are you sort of seeing in the Wing and Brandt areas that you really like? And where do you see the potential for that to go in the number of prospects?

[Frank Young, executive]

Well, the Wing area, what I really like is we have 2 wells there that are making in excess of 10 million cubic feet of gas a day. So I really like that, and so I want more of that. But what we're shooting for, what makes that happen is when we drill a good prospect there, we have targets. We have multiple stack pay targets, and we have overpressure. And that allows us to have the opportunity to have these high rates. The Wing prospect that I talked about will have some additional drilling in it, although it won't be a huge number of wells. We're talking about probably something less than 5 wells or so for that Wing prospect. But surrounding that prospect and adjacent to it, we have 3 other prospects that will provide additional drilling and hopefully, we'll continue -- allow us to continue drilling that area. In the Brandt prospect, we've had success in our initial well. And again, we found 4 stacked pay intervals there that are -- that have overpressured. And we have identified 10 additional prospects surrounding Brandt, near Brandt, and we'll be drilling to test those. So the Wing and the Brandt prospects are examples of areas that are growing, that will help offset the -- as we produce Gilly Field, we will see declines there. And so we will need these additional prospects to create additional production to allow us to continue growing. And then beyond those prospects, we've had this concerted effort to expand beyond the Gilly area. We still have the Cherry Creek prospect to delineate. And then we have another, in total, including the Brandt and Wing prospect areas, we have 30 prospects that we are currently in the process of working on. Some of those will end up being drilled. Some will end up falling by the wayside as we collect more data. But I feel very confident that we have a pipeline of ideas and prospects in place that will allow us to continue to drill successful exploration wells going forward. Not all of our exploration wells will be successful. We'll drill some dry holes. That's the nature of the beast in that area. But we have a big enough inventory that I feel good about being able to continue the success we've had at Gilly.

[Charles Robertson, analyst]

All right. And on the BOSS side, how long is the lead time for a 14th rig if you had a customer come in now, and sort of the thought process of when we should see it? Is there any particular component that is starting to take any additional time to fabricate?

[John Cromling, executive]

There are just 3 major components that really dictate the lead time, Charles. Derrick and substructure, VFD house, those are the 3 things that will take the longest. If we had a contract today, our best expectation going forward would be about 6 months based upon what we are seeing with the last 2.

[Operator]

And our next question comes from [ George Gaspar ], a private investor.

[Unknown Attendee]

Some technical questions, if you could. How has your distance changed in your -- extent of your horizontal sections? And how has the amount of sand that you're injecting changed in terms of tonnage going on a per well basis?

[Frank Young, executive]

In the Granite Wash area, we drill either 70 -- we've changed from drilling 4,500-foot laterals, oh, 3 years ago to now, we drill either 7,500-foot laterals or 10,000-foot laterals. Our other primary horizontal drilling area in Oklahoma, we can only drill 4,500-foot laterals until the recent -- until the law was changed back in 2017. Since that time, we began drilling extended laterals there as well. Those laterals will vary -- depending on the deposition of the sand, we can have wells that will be as long as 9,000 feet or 10,000 feet. Other wells that may -- an extended lateral, may only be 6,000 feet. But wherever we can, we will -- we see the value of drilling extended laterals. On the frac side, we've drilled -- in the Granite Wash, we drilled over 150 horizontal wells. We feel like as far as the size of our jobs, we've optimized that at around 1,000 to 1,200 pounds per foot of sand, for the intervals that we've drilled so far. We have -- our Granite Wash G interval is a very thick interval. It's possible we would need to increase the sand amount in that interval. In the other Oklahoma area, the SOHOT area, again, we drilled numerous horizontal wells there. We've optimized our frac design at 1,000 to 1,200 pounds per foot of sand. And STACK extensions, those wells require more sand because the Meramec and Osage intervals are thicker, and we see sand loadings in the 2,000 to 3,000 pounds per foot range.

[Unknown Attendee]

Okay. And now I got on the call late so you may have answered this or it came up. The decline curves. What are you experiencing in wells that have been completed, let's say, in the past 6 to 12 months? Is there any changes in decline curve percentages relative to what you've experienced, let's say, 1 or 2 years previous?

[Frank Young, executive]

It depends on the play you're talking about. But we have -- in our plays, we have drilled a significant number of wells. And so from those wells, we construct a type curve. Each individual well will vary some from that type curve and have different decline rates. But we still have the decline curves that you can see in our investor presentation, our latest investor presentation show those decline curves.

[Unknown Attendee]

Okay. All right. And then in terms of your hedging, maybe you answered this earlier. Can you just relay it again? How much of your production has been hedged? And what are your terminations on current hedges going forward?

[David Merrill, executive]

Hedges, for the balance of '18, we're -- on the gas side, for Q3, we're around 60% hedged. Q4, we're around 30% hedged. And for 2019 on the gas side, we've just started layering some things in. We're about 10% hedged based on our anticipated 2018 production. We haven't given any guidance to production for 2019 yet. And on the crude side, we're around 75% to 80% hedged for '18 for the balance of the year. And then for 2019, we've been layering on some hedges to the tune of about 25% of our current forecasted production for 2018. That was it, George.

[Unknown Attendee]

All right. A question on the hedging. What's the -- what's your average hedge on oil side right now?

[David Merrill, executive]

Well, for 2018, it's around -- they're primarily -- it's around $50. For 2019, we primarily use 3 ways that have a ceiling around $70 to $75.

[Unknown Attendee]

Yes, okay. All right. Well, that's very encouraging. I was thinking that there possibly could be a big uplift going into the new year in terms of your revenue generation. And in terms of the saltwater or your watering expense, you mentioned about saltwater expenses declining. Are you utilizing any new approaches in terms of water utilization? Or have you come up with anything that allows you to reuse water that's coming back out of the production streams?

[Frank Young, executive]

Yes, we are doing that. And our biggest saltwater-producing areas are Buffalo Wallow field in Hemphill County, Texas. And there, we have an integrated water recycling and disposal system. We have about 1 million barrels of pit capacity there, water recycling pit capacity. So we keep those 2 water recycling pits full of water, and that's the water that we use to frac with. So we use 100% of produced water. Our frac water is 100% produced water. The remaining water that we have there is moved to disposal system. So we can either -- our disposal system can either be filling up the water recycling pit, awaiting a fracture treatment, or they can be disposing into 1 of 5 disposal wells we have hooked to that system.

[Operator]

And we have no further questions at this time.

[Larry Pinkston, executive]

Well, in closing, I appreciate everybody staying with us during the call. We will be at EnerCom in 2 weeks. I think we present on Wednesday. We have a board meeting on Tuesday, so we're presenting on Wednesday at the conference, and hope to see many of you all there. Thank you again for listening in.

[Operator]

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