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JAGGED PEAK ENERGY (NYSE:JAG)
Q4 2017 Earnings Conference Call
March 23, 2018 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Thank you for standing by. This is the conference operator. Welcome to the Jagged Peak Energy Fourth-Quarter and Year-End 2017 Conference Call. As a reminder, all participants are in listen-only mode and the conference is being recorded.

[Operator instructions] I would now like to turn the conference over to Bob Howard, executive vice president and chief financial officer. Please go ahead.

Robert W. Howard -- Executive Vice President and Chief Financial Officer

Thanks, Ariel. Good morning, and welcome to Jagged Peak Energy's conference call to discuss year-end and fourth-quarter 2017 earnings and provide an operations update. Yesterday, we issued our earnings news release, and our 2017 Form 10-K has been submitted to the SEC. Both of these documents are available on our website at www.jaggedpeakenergy.com.

During our discussion, we'll refer to an earnings call presentation that can be found on the Presentations page under the Investor Relations section of our website. During this call, we will make certain forward-looking statements about the company's financial condition, results of operation, plans, objectives, future performance, and business activities. We caution you that our actual results could differ materially from the results that are indicated in these forward-looking statements due to a variety of factors. Information about these factors can be found on the company's SEC filings and on Slide 2 of today's earnings call presentation.

We'll also refer to certain non-GAAP financial measures such as adjusted EBITDAX, adjusted net income and adjusted EBITDAX margin. We believe these non-GAAP measures provide a comparison across the periods of activity and with other oil and gas operators. The reconciliation of the appropriate GAAP financial measures to the non-GAAP financial measures can be found on the last page of the earnings release and the last page of the earnings call presentation. I'll now turn the call over to Joe Jaggers, our chairman, CEO, and president, and return later for a financial update.

Joe?

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you, Bob, and good morning, everyone. Thank you for joining us on my final Jagged Peak earnings call. I would like to introduce the rest of the team. In addition to Bob and I, we have Mark Petry, our EVP of land and acquisitions; our VP of finance and corporate planning, Ian Piper; Chris Bairrington, our VP of operations; and John Roesink, VP of development planning and geoscience.

We also have Jim Kleckner with us. Jim will soon be our president and CEO upon my retirement next week. Turning to Slide 2 in the online presentation. I'll highlight a few key points related to our Q4 and full-year 2017 results.

Our acreage has increased to approximately 75,200 net acres, up 14% through the year. We increased our inventory of locations to some 2,090 as a result of our efforts to prove new zones and our success adding acreage. All of these locations are based on our original 880-foot spacings. Because of our contiguous land position, we're able to drill some of the longest lateral wells in the basin.

Our proportion of 1 1/2 and two-section lateral locations has increased to 93% of our inventory, with accompanying high working interest and high proportion of operated wells. We continue to add surface acreage to support our infrastructure efforts and now stand at approximately 4,500 total surface acres. Our 2017 production tripled from 2016, while we maintained the leading LOE cost structure. And to support our development and maintain our cost advantage, we continue to increase our water infrastructure.

We now have sufficient water to source up to five continuous frac fleets and are able to dispose of more than twice our current daily produced water volume, both at very attractive costs. 2017 was a year of aggressive delineation of additional targets, with new targets established in the second Bone Spring, the Wolfcamp C, and the Woodford. We now produce from a total of eight targets in the acreage. Reserve replacement of production was strong at over 800%, and total reserves increased to 82.4 million BOEs, up 118%.

On Page 3, we illustrate performance relative to peers. Our oil content, highest among our peers, drove very high unit revenue and, coupled with leading LOE cost structure, resulted in the highest EBITDAX margin of our peers, all while continuing to maintain attractive leverage ratios. Turning to Page 4. You can see that our production grew just over 200%, all organically.

Our Q1 production, with just a week or so left in the quarter, is estimated at 27,300. Quarter to date, we brought on 11 wells and are currently completing six wells. Slide 5 addresses our reserve growth during 2017, up 118% to 82.4 million BOEs, with characteristically high liquids, predominantly oil, and now 46% developed. At this point, I'll turn the call over to our soon-to-be president and CEO and current member of our board of directors, Jim Kleckner.

Jim and I have known each other for many years, and I have developed the utmost respect for his leadership, integrity, business acumen, and character. Founding Jagged Peak has been the thing I am most proud of in my 37-year career in the industry, so I've taken the successor choice very seriously. In Jim, I turn over the reins with confidence that he is the right pick and has the leadership and experience to take the company to the next level. Jim?

James J. Kleckner -- Incoming President and Chief Executive Officer

Thank you, Joe. And on behalf of all the employees of Jagged Peak Energy, I want to thank you for your vision, dedication and commitment in building a company that employees and investors alike can be proud of and participate in its exciting future. In five years, you took the initial idea of exploring in the southeast Delaware Basin and successfully created a multibillion-dollar corporation with substantial growth opportunity. Well done, and congratulations to you on your retirement.

And my special thanks for helping me transition in the new role. In 2018, we are focusing on several strategic initiatives that will help improve our overall company performance, as referenced on Slide 6. First, we'll increase our technical understanding of the reservoir system through integration of 3D seismic, core, and other data-gathering initiatives with the goal of drilling longer laterals and optimal target windows. Second, we'll adhere to capital discipline and strict cost control and planning and executing our development program.

Third, we'll focus on generating top-tier operational results by reducing drilling-cycle times and increasing technical efficiencies of our completions by target interval and area. Fourth, we will maintain peer-leading cost structure by expanding our water-handling facilities to support drilling, completion, and production operations. And lastly, we will maintain a strong balance sheet with conservative leverage profile. Turning to Page 7.

Last year, the company licensed a spec 3D seismic survey that covered the Cochise prospect area on the Ward and Winkler County line. Interpretation of this data allowed the subsurface team to gain greater insight into the structure and stratigraphy of the reservoirs in this area, and this improved understanding helped us target higher-quality shale packages and steer our lateral wellbores with greater confidence. Acquisition of data over the Whiskey River was completed in the first quarter of this year, and the processed data will be ready for interpretation and have an impact on the developed effort during the second half of the year. Additionally, seismic crews are permitting and surveying in the Big Tex area, and that data will be available to guide the company's Wolfcamp and Woodford drilling in 2019.

The importance of having 3D to guide the development program can be seen in the two wells illustrated on Slide 8. The Whiskey River 4A and 19.5B were drilled approximately 1 1/2 miles apart and are both 10,000-foot laterals that targeted high-quality Wolfcamp A on the eastern edge of our acreage position. The 4A well achieved 100% of the lateral in target window and has substantially outperformed our type curve. The 19.5B was roughly 63% in the target window and has performed below the type curve.

We believe this underperformance is directly attributable to drilling outside the target window. And 3D across the entire acreage position will allow us to plan wells to achieve maximum percentage of lateral in the optimal target and significantly impact well performance in the future. Turning to Slide 10. The company's total location inventory has increased from 1,265 at the IPO to approximately 2,090 based on the extensive delineation effort in last year's program.

Locations have been added in the second Bone Spring in Big Tex, the Third Bone Spring in Cochise, Whiskey River and Big Tex, and the Wolfcamp B in Whiskey River. Should be noted that 93% of this inventory is long to extra-long laterals on acreage that is 97% company-operated. Turning to 2018 guidance, which is summarized on Page 11. The midpoint of our production guidance is 29,500 barrels of oil-equivalent per day.

That represents a 75 -- or 74% growth rate from the 2017 to 2018. Our activity level is scheduled to provide the organization with the necessary time to complete the acquisition and interpretation of 3D and other data initiatives. We believe that by completing the interpretation and integration, we will more efficiently deploy capital across our portfolio. In 2018, we expect to spud between 40 and 45 gross operated wells and bring 42 to 46 gross operated wells online.

Capital associated with drilling and completing these wells is between $540 million and $590 million. Infrastructure spending associated with the build-out of our water delivery and disposal systems will be between $20 million to $25 million. LOE expense will be $3.25 to $4 per barrel of oil-equivalent has increased over 2017 due to the number of wells will be placed on artificial lift. Cash G&A will range from $42 million to $46 million, and that reflects the growth in our technical and operational teams required to drive value into our development program as we prepare to ramp up activity levels in the future.

And with that, I'll turn the call over to Bob Howard to review 2017 operating results and financials.

Robert W. Howard -- Executive Vice President and Chief Financial Officer

Thank you, Jim. Following up on Jim's update on 2018 guidance, I'll touch on the 2017 financial highlights as we continue to generate excellent financial results with increasing production and continue to generate top-level margins. As shown on Slide 12, we reported net income of $12.8 million for the fourth quarter. Excluding $58.5 million of pre-tax non-cash mark-to-market loss on commodity derivatives, $37.3 million of deferred-tax benefit from the recent tax law legislation, and other non-cash charges, adjusted net income was $20.2 million, or $0.09 per share, which compares to adjusted net income of $15.4 million for the third quarter.

For the full year adjusted income was $55.9 million, or $0.26 per share. Fourth-quarter adjusted EBITDAX was $78.3 million, which is 388% greater than the fourth quarter of 2016, an increase of 39% compared to the third quarter. During the quarter, we generated a peer-leading adjusted EBITDAX margin of over $35 per barrel of oil-equivalent of production. For the year, we generated $203.3 million of adjusted EBITDAX, an increase of 315% from 2016 and nearly $33 per BOE of production.

Our full-year 2017 production was over three times 2016 production at nearly 17,000 BOE per day and continues to be among the highest oil cut in the industry. Fourth-quarter production increased over 24,000 BOE per day, which is an increase of 25% from the third quarter of '17. We continue to see oil cuts of approximately 80% driven by a primary development in the Wolfcamp A formation. During the quarter, capital expenditures for drilling and completion activities was $168.5 million, which includes spudding 14 gross operated wells and completing 14 gross operated wells.

For the year, we invested $567.6 million in drilling and completion activities, including spudding 54 gross operated wells and completing 46 gross operated wells, which is a significant increase from 2016 when we spud 16 gross operated wells and completed 11 gross operated wells for the entire year In addition to our investment in drilling and completion and infrastructure cost, in 2017, we invested $69.1 million to acquire approximately 9,200 net acres of leasehold interests at an average cost of approximately $7,500 per acre, which increases our leasehold position to approximately 75,200 net acres at the end of the year. While we don't provide a budget for the leasehold acquisitions, we will continue to seek strategic leasehold interests at attractive costs and will complete acreage trades at well locations, increase lateral length, increase our ownership in the wells we drill. Slide 13 shows that year-end borrowings of $155 million under our credit facility, which positions us with a debt to last 12 months adjusted EBITDAX ratio of 0.8 times. Earlier this week, we expanded our bank credit facility to add six lenders and increased the borrowing base from $425 million to $540 million.

In addition to the upsizing of the facility, interest margins were increased by 50 basis points to 150 to 250 basis points above the underlying interest rates. Our ability to hedge on the facility was also increased. As of March 21, the outstanding balance under our credit facility is $265 million, which leaves $275 million of borrowing capacity available to supplement operating cash flow to fund our development program. This concludes our prepared remarks, and we'll open up for questions and answers.

Questions and Answers:

Operator

Thank you. [Operator instructions] Our first question comes from Jeanine Wai of Citigroup.

Jeanine Wai -- Citi -- Analyst

Hi, good morning, everyone.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Good morning, Jeanine.

Jeanine Wai -- Citi -- Analyst

Hi, good morning. In terms of the 3D seismic and understanding the potential rate of change in 2018, how many wells in 2017 were drilled using 3D seismic? And given the timing of the survey this year, how many wells do you think will benefit from the 3D seismic this year?

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Jeanine, we're going to turn that over to John Roesink. He's closer to the data.

John Roesink -- Vice President, Development Planning and Geoscience

Jeanine, in 2017, using the Cochise 3D, we drilled approximately six wells that were impacted by our learnings from that well. The drilling schedule is a moving target. But based on current planned activity, I'd say approximately 20 of the wells will be impacted in 2018 by our interpretation of the survey that covers Whiskey River.

Jeanine Wai -- Citi -- Analyst

OK. Great. And my follow-up, just continuing to hit on what can we expect that's going to be different in 2018 versus last year. You've improved your efficiencies by roughly 30% since 3Q '17 on a status-completed-per-day-per-fleet basis.

What stages-per-day level have you assumed for the 2018 outlook? And our understanding is that you do have a monthly stage-count metric wherein -- to some of your services contracts. And we just want to know kind of how that number of stages compares to what you have assumed in your 2018 outlook.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Chris Bairrington, our VP of ops, has those numbers available.

Chris Bairrington -- Vice President, Operations

Jeanine, our current 2018 is scheduled for where we're at right now in the 1Q '18, so we achieved with what we had in the current schedule of the 2.7. Additional efficiency gains can be there, but that's not baked in at this point.

Jeanine Wai -- Citi -- Analyst

And then -- sorry, just how does that compare to whatever agreement you have in your services contract? We're just trying to get a sense of how aligned the budget is with what you have in your contract.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

OK. Our service contracts right now are -- they're based on this 2.7 average. It's a little more complicated than that on the number of hours for the pumping stage. But that's how we're currently priced out is on an hours per stage.

The NPT is a give and take from our side and also on the frac contract side. So there shouldn't be any changes to the frac contract that would impact the capital for us.

Jeanine Wai -- Citi -- Analyst

OK. Great. Thanks for taking my questions.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you, Jeanine.

Operator

Our next question comes from Scott Hanold of RBC Capital Markets

Scott Hanold -- RBC Capital Markets

Morning. Joe, I just thought I'd -- Yeah, good morning, guys. Joe, I just thought I'd say, Joe, congratulations on your long, successful career. Hope you enjoy some downtime in retirement.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you very much, Scott.

Scott Hanold -- RBC Capital Markets

Yeah. On, on -- For 2018, clearly, you guys have slowed down your activity pace, I guess, from what was expected several months ago. And can you just give us some broad and maybe specific data points on what really drove that decision-making process? It sounds like you're going to use more data analytics and want to be more deliberate about how you approach '18, but what were the key triggers that made you go down this path?

James J. Kleckner -- Incoming President and Chief Executive Officer

Scott, this is Jim Kleckner, and let me take a shot at that. First, we did a look back on our 2017 performance and evaluated our technical efficiencies in that program. As Joe mentioned, we really focused on a lot of delineation of additional target zones, but what we saw also was the example I showed you that the ability to penetrate more target window was really amplified with 3D seismic. And so when we think about our 2018 program, we didn't want to outrun our technical-learning curve, and so we wanted to pace that with data acquisition and integration that's coming from the 3D shoots we discussed, coupled with a lot of other data gathering and integration work, whether it be cores, PBT work on fluid properties, and additional pressure information around there.

We believe that not outrunning that technical-learning curve and wasting value in the ground is critical to our program going forward. And so we sequenced our drilling program, coupled with how to bring that data into the organization, digest it and turn it to value growth in our drilling program.

Scott Hanold -- RBC Capital Markets

OK. And so am I right to say -- and I think you had mentioned -- you all had mentioned that there were six wells that you used seismic last year, so it was ultimately actually getting all that data in some time in the back half of the last year and early this year and able to actually take a hard look at it relative to where you are before? Is that a fair kind of a high-level look at it?

James J. Kleckner -- Incoming President and Chief Executive Officer

That's correct, Scott.

Scott Hanold -- RBC Capital Markets

OK. And I think you guys had budgeted or at least mentioned you're budgeting sort of like a $50 environment. And when you step back and think about your learnings that you expect in '18 from this new data and where current money prices are, should we assume that there's not -- even though that we're in a -- it looks like we're, at least for now, in the $60-plus oil world, you all will still again not try to outrun yourselves and maintain this completion and drilling pace you all laid out today?

James J. Kleckner -- Incoming President and Chief Executive Officer

I think when you look at our 2018 program, we're budgeting conservatively at a $50 price. And we're going to adhere to that the first half of the year. If we see that commodity prices remain high and that the results of the 3D survey come in and the results for our wells start improving that we would have the flexibility in the second half of the year to make adjustments. But right now, we're planning on the budget as we just delivered.

Scott Hanold -- RBC Capital Markets

OK. That's great. And one really quick one on -- could you give us a quick update on that Oryx line that was being put in -- I think it's in the Big Tex area. I think it was supposed to go online the first quarter.

What's the status on that? And if you can just give us a general view of what your oil firm takeaway contracts are in at right now? Because obviously with Mid-Cush spreading out, there's a lot of concern about producers being able to get out their oil.

Ian Piper -- Vice President, Finance and Corporate Planning

Yes, Scott, this is Ian Piper. So Big Tex has begun flowing. They started flowing out earlier this year. So potentially, all of our production is down on pipe.

There's a bit down on truck, but not much. And in terms of capacity on the works, they've got Oryx II coming online in June. That's going to bring another 400,000 a day online. So our capacity will step up with that.

We don't see any issues.

Scott Hanold -- RBC Capital Markets

Understood. Appreciate it. Thanks.

Operator

Our next question comes from Mike Scialla of Stifel.

Mike Scialla -- Stifel Financial Corp. -- Managing Director

Good morning, everybody. I'd like to offer my congratulations, Joe, as well on your career, specially the success with Jagged Peak, and I hope you have a great retirement.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you much, Mike.

Mike Scialla -- Stifel Financial Corp. -- Managing Director

I wanted to ask on your spacing test. You've got a fair bit of data there now on the 660-foot spacing in one zone, I guess, lower zone in the Wolfcamp. Your thoughts on is that going to be the appropriate spacing? And any thoughts on how that interplays with the Upper Wolfcamp? Do you see those as two separate reservoirs at this point?

John Roesink -- Vice President, Development Planning and Geoscience

Mike, this is John Roesink again. And we are encouraged by everything we've seen to date on the Lower Wolfcamp base 660 spacing test as well as our staggered 330 offset Upper and Lower Wolfcamp A tests. It's an evolving piece of the story in terms of the timing of integrating all of our data and planning our full field development. And we have to think about the next steps.

We're planning additional tests and thinking about how we make the transition from essentially drilling one or two well pads designed to HBP our entire acreage position to what will be at some point in the future the multizone multiwell pad development of the entire field. So as we move forward, we're incrementally designing new tests to move that understanding forward. And I would say that that will be an integral part of bringing all of the data together, the pressure data, the seismic data, and the development planning both from the full-field economic side to the geoscience and reservoir side. So we're encouraged, but there's a lot of work that my team still needs to do to move to the 660 fieldwide spacing count -- comfort level.

But at this point, we're still moving ahead because we are very encouraged by those results.

Mike Scialla -- Stifel Financial Corp. -- Managing Director

OK. Good. And the Third Bone Spring shale wells that you had data look very good. I think you plan to drill most of this year's wells in the Wolfcamp A.

But what does the inventory in the Third Bone Spring shale look like? And how many wells in that formation do you plan this year?

John Roesink -- Vice President, Development Planning and Geoscience

We're very encouraged by the initial results from the Third Bone Spring. As we look at the development, one of the key pieces is holding leases, holding depths and not creating depleted zones. When you have a result like we've seen in that 73, 74 wells in Whiskey River, you want to be very excited and go out and drill a bunch more of those wells, but the reality is you have to think about things from full-field development perspective. And so we will likely drill additional tests this year, delineation and appraisal test.

And we will have hopefully some more encouraging results to announce this year. But at this point, I don't want to like commit to a specific number. Another piece of those two -- Third Bone Spring wells that encourage us about our acreage position, as they were drilled on 660. And they are performing independently -- excuse me, 660 spacing and -- so that gives us a lot of confidence that we have a Third Bone shale reservoir that it probably performs differently than the classic Third Bone sand reservoir to the west of us.

Mike Scialla -- Stifel Financial Corp. -- Managing Director

Yes, I was going to ask about that as well. That's helpful. Last one from me. Jim, you'd mentioned the importance of the 3D and other data as well.

It looks like -- obviously, scanning zone is making a big difference. When you look at your inventory that you showed on Page 10, it assumes the vast majorities in long or extra-long laterals. How do you -- do you think that -- how do you think the 3D integrates with that? I mean, is there a chance that, that changes as you get more data in? Or how confident, I guess, are you that you're going to be drilling mostly long and extra-long laterals?

Chris Bairrington -- Vice President, Operations

Now I'll take the answer for Jim since we're -- I'm a little closer to that question right now. He'll get that answer next time. We don't anticipate that any of the interpretation from the 3D is going to change our net lateral lengths. The lateral lengths that we published there on Page 10 have taken a very close like at the distribution of the acreage, our understanding of the structure and the changes across there.

And we feel like we can design and plan and execute wellbores that will take advantage of our entire blocked-up acreage position in all of those extended laterals.

Mike Scialla -- Stifel Financial Corp. -- Managing Director

OK, that is fair enough. Appreciate it

Joe Roesink -- Vice President, Development Planning and Geoscience

Thanks, Mike

Operator

Our next question comes from Irene Haas of Imperial Capital.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Good morning, Irene

Irene Haas -- Imperial Capital -- Managing Director

Hey, good morning. So can you give me -- firstly, congratulations to Joe for really having the foresight to land this acreage when nobody really believed that it would work. So five years later, you got a great inventory. And good luck with retirement.

Secondarily, I would like to kind of address a little bit of the fracs fleet evolution from fourth quarter to now. There's been some changing. Can you give us a little color as to, I guess, you're running five rigs. About the completion crew this year, how are they different? How are they incentivized? How do you feel about your current selection?

Chris Bairrington -- Vice President, Operations

Irene, this is Chris Bairrington again. I'll address those. The frac fleets that we have right now are the same ones that we had last year. There are some changes to equipment.

We worked with -- they were currently working with the providers on how the equipment is set up, how we're pumping the jobs in order to get the efficiency gains from the daily jobs that we're pumping. Now that goes a little bit further. There's going to be how you are pumping your sand, how you're pumping your diversion material, and how the stages are laid out, and that's really been a big hit for how we're getting things pumped in the ground and on every single one of the wells. The current completion frac fleet that we have, we have three that are all the way through 2018 that are contracted and the same three again that we started the year with.

Irene Haas -- Imperial Capital -- Managing Director

OK. So you're basically average three completion crews for the five rigs that you're going to deploy this year?

Chris Bairrington -- Vice President, Operations

Yes.

Irene Haas -- Imperial Capital -- Managing Director

OK. And presumably because you've worked with them for a while that a lot of the glitches, hopefully, has been kind of smoothed out perhaps? Any crew change? Are they the same crew that you had before?

Chris Bairrington -- Vice President, Operations

We have identified some of the top performers out there. We've changed some of our well-site supervisors. And we've also put people in leadership roles in order to succeed. Those things have really spoken to the efficiency gains that we've seen on the frac crews at this point.

So yes, there are those efficiency gains that we have taken advantage of at this point of the supervision and also the improvement of the equipment, also the placement and also the jobs.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

And one thing I'd add, Irene, is we have increased our own company supervision here. We're now 24 hours a day on those fleets.

Irene Haas -- Imperial Capital -- Managing Director

OK. That makes a big difference. Thank you.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you, Irene.

Operator

Our next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt & Company.

Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Director

Good morning. Thanks for taking my questions. Just real quick on HBP plans, looking at it at the area level. Know you give the 2019-plus number for just number of HBP wells.

Could you speak more to how many of those by the area are for 2019 specifically? And should we assume those will be drilled as a base case? Or are there other alternatives like lease retention that you can explore?

Mark Petry -- Executive Vice President, Land and Acquisitions

So I'll go to Page 17. It's Mark Petry. So your -- I think your question was Big Tex, right? How many in 2019?

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Every area.

Mark Petry -- Executive Vice President, Land and Acquisitions

So in 2019, we've got 26 -- and this is 2019 and beyond -- we've got 26 wells to hold Cochise. We're currently negotiating to get that extended another three years. Whiskey River we've got 19 in 2018, 38 2019, 2020, and '21. Big Tex, four in 2018 and then 83 in the remaining years, and that works out to about 33 in 2019, about a similar amount in 2020, and the balance in 2021.

Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Director

That's helpful. I appreciate that. And then second question is just on a follow-up to the Third Bone. Just thinking about the strong results there and some of the commentary from earlier in the call.

How should we think about that competing for capital? And as you look out to 2019, is it pretty dependent on how the wells -- potential wells from this year's program look? Just wondering will it pay for that to receive more capital?

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Well, I think those results in the Third Bone are every bit as good or perhaps even better given it's shallower and somewhat less costly to drill than Wolfcamp A out there. I think, as we get the seismic in and determine how we're going to develop on pads and by zones, those will be at the very top of our portfolio, along with Wolfcamp A's.

Operator

Our next question comes from Mike Kelly of Seaport Global.

Mike Kelly -- Seaport Global -- Partner

Hey, guys, good morning. First off, Joe, I want to echo basically everyone's thoughts here. Wish you the best in retirement and give you props on a great career in which you've built at Jagged. Jim, the question is for you.

Bullet 4 of the strategic initiatives slides, you stressed focus on operational execution. And I think you've already mentioned a few things on the call. But I'm curious if there's any other specific changes maybe we can expect to see from you guys and/or that you expect to implement on the ops front to kind of get you as a lock in terms of best-in-class status?

James J. Kleckner -- Incoming President and Chief Executive Officer

Mike, that's a great question, and I appreciate you asking it. I think it really goes into the topic of technical efficiencies throughout our entire business model. And technical efficiencies range from whether it be reservoir characterization and analysis of target path planning, whether it be drilling cycle times, the completion of efficiencies, whether it be logistics and moving manpower and equipment and supplies around, including water delivery and water disposal. So really, it really spans the entire range of our business.

But I think when you achieve these technical efficiencies and they can be surface technical efficiencies around integrated project-management so that there's very little lost time as you sequence through drilling operations or simultaneous operations, that when you start achieving those efficiencies, you drive costs down. And from a subsurface standpoint, as you look at completion technologies and optimizations per zone or by area, you start achieving EUR gains. And so we'll really focus -- and continue on the improvement pace that has been demonstrated here the last couple of years on the chart that you see showing reduction in drilling-cycle times and improvements in frac fleet efficiency. So I think we'll hit on every facet of the business and look for improvements to drive IRRs up on all of our wells.

Mike Kelly -- Seaport Global -- Partner

Great. Appreciate that. Follow-up here just kind of getting granular and specific here, but we have been hearing some recent ramblings that procuring outer-basin sand has become difficult at times due to bottlenecks on the rail lines. I just wanted to check in with you guys to see if you see anything on that front and just give us a sense on how you're prepared to potentially deal with some difficulties there.

Chris Bairrington -- Vice President, Operations

We have seen some issues with that on the procurement of outer -- with outer-basin sand with the rails. So far it hasn't impacted us. We have had a couple of days of downtime, but it's not been any kind of meaningful impact on our efficiencies that we have out there. We also have all the regional sand that we have that we're working toward right now.

We've got the commitments that should be all fully implemented by the first half -- or second half of 2018. And we've put that commitment back over into the frac fleets that we have currently operating for us. So we are fully expecting that, that will be in the second half of '18 to get us out of any of these other rail issues, weather issues for outer-basin sand.

Mike Kelly -- Seaport Global -- Partner

Great. Appreciate it. Thanks, guys.

James J. Kleckner -- Incoming President and Chief Executive Officer

Thanks, Mike.

Operator

Our next question comes from John Silverstein of Wolfe Research.

Josh Silverstein -- Wolfe Research -- Director

[Inaudible] Good morning. Just curious on the 45 wells roughly this year. That's kind of been the pace that you guys have been going at for the past few quarters and have been adding about 4,000 to 5,000 barrels per day -- or BOE per day per quarter. I know it's slowing down a little bit this quarter, but do you expect the production trajectory to get back on that pace as we look out into 2Q to 4Q?

James J. Kleckner -- Incoming President and Chief Executive Officer

John, that's another good question. I think that it's going to be dependent on the cadence of our completion programs as we move through the year. And we'll plan on having a pretty smooth cadence quarter to quarter, but we will have some blockiness to it because we are incorporating pads and the timing of those pads may affect what that production increase is quarter on quarter. But throughout the year, we hope to be very consistent on that cadence.

Josh Silverstein -- Wolfe Research -- Director

Got it. And I know you mentioned before that you're still kind of waiting to see the results on the seismic and commodity pricing were to accelerate. But I was curious if there's any other constraints to grind as well, whether it's needed infrastructure out there or anything else that may keep the pace a little bit slower?

James J. Kleckner -- Incoming President and Chief Executive Officer

There are really no constraints that we see right now. Obviously, we want to -- we focus on technical efficiencies and capital returns. We don't want to run faster than what we can either efficiently accomplish from the surface sector side or our capabilities internally. So this pace is measured against that.

As we get into the second half of the year, as I mentioned earlier, and we see the results of our program and how rapidly we integrate the data that we're going to be acquiring this year, we will have the flexibility. And we don't see any constraints with looking at growth in the second half of the year or the out-years from thereon.

Josh Silverstein -- Wolfe Research -- Director

That's helpful. Then last one for me, just on the financing side. Bob, you increased the credit facility, but you guys are basically up of -- 50% utilized on there. Just to increase liquidity, are you guys thinking of terming out debt or anything on the financing side there?

Robert W. Howard -- Executive Vice President and Chief Financial Officer

From the financing side, we do expect our borrowing base to increase as we add the PDP reserves. So one of the reasons so we added the six banks is to give ourselves our flexibility. But it does appear that the debt markets and long-term debt markets are very competitive right now. And I think, ultimately, long term, our capital structure should have some term debt in it.

And so the timing, I don't want to get ahead of ourselves on that, but it would make sense that there's some term debt tied into our capital structure. We still want to keep our debt metrics on the low side for what we would -- for our business. But you kind of look at the market just with where the debt markets are today.

Josh Silverstein -- Wolfe Research -- Director

Great. Thanks, guys.

Operator

Our next question comes from John Nelson of Goldman Sachs.

John Nelson -- Goldman Sachs -- Vice President

Good morning. And echo those before me, and so, Joe, congrats on the very impressive career and best of luck, and enjoy your time with family in retirement.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you, John.

John Nelson -- Goldman Sachs -- Vice President

Jim, congrats as well on your appointment. I'm not sure which of you would want to take this, and I apologize if it's a little direct, but it's kind of our job to ask this. I was talking to investors, I think a lot were surprised to see a leadership transition that was not part of a sale process for Jagged Peak. Can you comment on if any consideration to selling or merging the company was taken as part of this transition? And if not, then why?

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

John, I'll take that, and it was just a result of the age I'm at. I'll turn 65 this year, and the thought that the company would be operated for some time into the future and that it was probably an appropriate time. Jim's a little bit younger. He's been on the board.

He's familiar with resource plays and the requirements they have. And a sale process really didn't come into the consideration. It's just my age and my desire to retire as well as to have a man that can step in here quickly that had a lot of experience with resource plays.

John Nelson -- Goldman Sachs -- Vice President

Thank you for that. My second question, if I do dumb-Wall Street-guy math and just break down your D&C cost guidance versus the well guidance that you guys talked about, I get kind of north of $1,500 a foot as your well costs, which seems a little high versus some others in your industry. So can you just update us on what current well costs are and if there's any other contingencies kind of built for that 2018 guidance.

Chris Bairrington -- Vice President, Operations

John, this is Chris Bairrington. I'll comment on that. Fifteen hundred, I guess, I'm not sure how that number is coming up, but that is high. Currently, we're sitting approximately 11.5 in a two-section lateral and fully expect that that's going to continue throughout this year.

We don't have a lot that's baked into that number that we feel that efficiency gains still are on the table. We also feel that procurement of sand is also going to be a benefit for us. So there are some additional capital increases that we can have. Now the 11.5 does not also take into account the 6% inflation that we have built into our model as well.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Great. Thanks for taking my question, congrats again, Joe and Jim.

Operator

Our next question comes from Dan McSpirit of BMO Capital Markets.

Dan McSpirit -- BMO Capital Markets -- Vice President

Thank you, folks, good morning. Joe, happy trails and Jim, good luck.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thanks, Dan

Dan McSpirit -- BMO Capital Markets -- Vice President

You spoke earlier about substantially all of your production being on pipe these days. How much of that is firm? And what if any is subject to volume commitments?

Ian Piper -- Vice President, Finance and Corporate Planning

Dan, this is Ian Piper again. In terms of the oil side, I would think of it as all being firm, especially once Oryx II comes online in June. Our commitment will step up. Our capacity on their system will step up in June when that comes online.

But in terms of take or pays or minimum-volume commitments, we don't have any. Everything's structured as an acre syndication out here.

Dan McSpirit -- BMO Capital Markets -- Vice President

Thank you for the clarification. Have a great day. Thank you.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thanks, Dan.

Operator

This concludes the question-and-answer session. I would like to turn the conference back over to Joe Jaggers for any closing remarks.

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

Thank you and I'll wrap up by saying that I'm extremely pleased with what we've achieved at Jagged Peak -- our robust organic growth, our leading cost structure, our advantaged land position -- but what I'm most proud of is our organization and their dedication to our mission. Coupled with new leadership, they make me optimistic about the future and confident in our ability to deliver. Thank you very much, everyone.

Operator

This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.

Duration: 47 minutes

Call Participants:

Robert W. Howard -- Executive Vice President and Chief Financial Officer

Joseph N. Jaggers -- Chairman, President, and Chief Executive Officer

James J. Kleckner -- Incoming President and Chief Executive Officer

Jeanine Wai -- Citi -- Analyst

John Roesink -- Vice President, Development Planning and Geoscience

Chris Bairrington -- Vice President, Operations

Scott Hanold -- RBC Capital Markets

Ian Piper -- Vice President, Finance and Corporate Planning

Mike Scialla -- Stifel Financial Corp. -- Managing Director

Irene Haas -- Imperial Capital -- Managing Director

Jeoffrey Lambujon -- Tudor, Pickering, Holt & Company -- Director

Mark Petry -- Executive Vice President, Land and Acquisitions

Mike Kelly -- Seaport Global -- Partner

Josh Silverstein -- Wolfe Research -- Director

John Nelson -- Goldman Sachs -- Vice President

Dan McSpirit -- BMO Capital Markets -- Vice President

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