EP Energy (EPE) Brent J. Smolik on Q2 2016 Results - Earnings Call Transcript

| About: EP Energy (EPE)

EP Energy Corp. (NYSE:EPE)

Q2 2016 Earnings Call

August 04, 2016 10:00 am ET

Executives

Bill J. Baerg - Head of Investor and Media Relations

Brent J. Smolik - Chairman, President & Chief Executive Officer

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Analysts

Arun Jayaram - JPMorgan Securities LLC

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Brian Singer - Goldman Sachs & Co.

Gregg William Brody - Bank of America Merrill Lynch

Operator

Good morning, and welcome to the EP Energy Second Quarter 2016 Results Conference Call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note this event is being recorded.

I would now like to turn the conference over to Bill Baerg with Investor Relations. Please go ahead, sir.

Bill J. Baerg - Head of Investor and Media Relations

Good morning, and thank you for joining our second quarter 2016 investor update call. In just a moment, I'll turn the call over to Brent Smolik, Chairman, President and Chief Executive Officer of EP Energy. Joining him will be Clay Carrell, our Chief Operating Officer; and Dane Whitehead, Chief Financial Officer of our company. Yesterday, we filed our second quarter press release announcing our quarterly results. This morning, we posted slides to our website epenergy.com which we'll be referring to on this call.

Also on our website in the Investor Center section, you'll find our financial and Operating Reporting Package that includes non-GAAP reconciliations and other relevant information. We hope you'll download and review this helpful resource. During today's conference call, we'll make a number of forward-looking statements and projections. We've made every reasonable effort to ensure that the information and assumptions on which these statements and projections are based are current, reasonable and complete.

However, a variety of factors that could cause actual results to differ materially from the statements and projections expressed during this call. You'll find those factors listed under the cautionary statement regarding forward-looking statements on slide two of this morning's presentation as well as in other of our SEC filings. Please take time to review them. Finally, EP Energy does not assume any obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

Thank you. And I'll now turn the call over to Brent. Brent?

Brent J. Smolik - Chairman, President & Chief Executive Officer

Thanks, Bill. Good morning, everyone, and thank you for joining our call. Some of the themes on the call are going to be similar to those of the last few quarters. In spite of limited capital activities and investment, we delivered solid results in the quarter. And in a persistent challenging commodity price macro, our team stayed focused on improving what we can control. And by maintaining that focus, we achieved a number of financial and operational milestones in the quarter, which we'll spend much of our time discussing this morning. I'll provide an overview and review our operations. And then Clay will add some colors on recent developments in Wolfcamp program. Dane will then review our financial results for the quarter, the progress, we've made in improving our financial position in our updated 2016 outlook, and then we'll have time for your question as always.

So I'll start in the materials this morning on slide three. As a reminder given commodity price uncertainty, we started the year with the lower capital spending and activity levels. We made that decision to slow the pace of development, preserve capital and focus on enhancing returns and improving the balance sheet.

We also used that low in activity to accelerate our technical understanding of our each asset areas. That effort is paying off with improved well performance and further improvement in what we believe were already top tier capital and operating cost structures. We performed well financially in the quarter. We maintained capital discipline and continue to generate free cash flow, and we benefited from improved realized prices and lower cost, and delivered earning results which beat expectations.

We also increased our financial flexibility in the quarter in several ways. In the Wolfcamp, we successfully worked with our land owner, the University Lands System and came up with a creative solution to low commodity prices. We amended our land agreement to give us the flexibility to extend the lease holding period from early 2018 to the end of 2021, and then we also incorporated a sliding scale royalty framework, which improves well-level economics in low price environments.

We also significantly enhanced our oil hedge program in 2017, protecting downside risk while retaining upside to higher prices, which you may have seen in our recent announcement. And then finally, we reduced our outstanding debt and captured discount with further open market bond repurchases. All of those actions improved the value of our assets and they position us for the commodity price recovery.

Slide four shows our operational summary of our program for the second quarter. As planned, the second quarter was our lowest activity period in recent history with capital spending of less than $100 million. The chart on the right provides the CapEx breakdown by program and shows that we started shifting more spending in the quarter to our Wolfcamp program. In the quarter, we completed 15 wells in total, compared to 63 in Q2 of 2015 and the second quarter 2016, oil production was more than 45,000 barrels of oil per day and total equivalent volumes were 84,500 barrel per day. I'll recall that – we sold our Haynesville natural gas assets on May 3. So the numbers in that program reflect roughly one month of activity.

That oil production was down 29% from Q2 2015, driven by significantly fewer completions really dating back to the middle of last year. And for reference, in the first half of 2015, we completed 120 wells compared to 38 wells in the first half of 2016. We still believe that it's appropriate to stay disciplined regarding capital spending until we have more certainty about future pricing even though it negatively impacts our production volumes.

In Eagle Ford, we completed 8 wells, which compares to the 42 completed in the second quarter of 2015. In the Wolfcamp, we completed five wells from our DUC inventory and produced 17,600 barrel equivalents in the quarter. And note, the five Wolfcamp wells were completed late in June, so they didn't have any impact on the second quarter volumes.

Our Altamont program produced 15,500 barrels of oil equivalents per day with just two completions in the quarter. And then for remainder of 2016, we expect to stay at relatively low levels of activity in the Eagle Ford and the Altamont and shift focus to the Wolfcamp due to the improvements in the Wolfcamp returns.

Slide five summarizes our general operational focus in this part of the cycle and then includes some specifics for each program. Across the company we're doing all that we can to improve asset valuations and well-level returns, including we've continued to reduce capital and operating costs and increased efficiencies, and we've also realized better pricing relative to WTI and all programs with lower basis differentials and improved contract terms. We've optimized base production, which is so important during these periods of lower activity levels. And we've continued to increase our knowledge base and advance our regional earth models, which ultimately results in lower cost and improved well performance.

Over the last year, our Wolfcamp program has realized the greatest step change in performance and valuation. We now have one drilling rig running in the program. Our well performance this year has been very encouraging and ahead of expectations. And the combination of lower well cost, better well performance and the amendment of the UL agreement have all meaningfully improved well economics.

In the Eagle Ford, we continue to run one rig in the second quarter, primarily drilling lease obligation wells and adding to our DUC inventory, which had grown to 42 by the end of the second quarter. We recently released the drilling rig in Q3. We're taking a drilling pause and we expect to complete wells from our DUC inventory in the third quarter. And then depending on oil prices, we may bring that rig back later this year. In the Altamont, we're running one partnership rig and we expect to maintain that pace for the rest of 2016.

Our ongoing recompletion program, that's the addition of completions and existing wells, continued to deliver with low CapEx, good well results and strong returns. And we've also seen a fairly rapid improvement in realized pricing in the region, both on an absolute basis and relative to WTI, as Basin productions declined and demand has grown in the Salt Lake refinery market.

Slide six highlights our improving cost – operating cost structure. Total cost continued on a favorable trend down to $78 million for the quarter resulting from our focus on continuous improvement really in all expense areas of our business. And we've also successfully reduced cash operating costs per unit, even with a lower denominator.

Note that these metrics are pro forma to exclude Haynesville volumes and costs for both periods. It's also important to note that not only are these metrics improving year-over-year, but we believe they're top tier compared to other oily (09:21) E&P companies. Lease operating expenses of close to $5 per barrel remain very competitive as a result of the internal cost management initiatives we have underway, and a lower cost of services and supplies. We've reduced G&A cost consistent with our lower activity levels and total adjusted operating cost improved to $10.94 per Boe compared to $11.63 per Boe in Q2 2015.

Slide seven shows our continued progress in driving down capital costs in each program. We've maintained a favorable trend despite generally drilling longer laterals with larger and more complex completion jobs over this timeframe. We expect this trend to continue. We're showing the full year estimated averages in these 2016 numbers, which includes some carrying costs from wells that were drilled in 2015. But based on these trends and our ongoing initiatives, I expect that we're soon going to delivery Eagle Ford and Wolfcamp wells at or below $4 million per well. And in each of these programs, we've seen the benefit of overall service cost declines and improved efficiencies that we've been able enable to capture to-date and that we intend to hold on to long term. Our asset and operating teams have just done a great job of continuing to find ways to reduce well costs across all of our programs. That covers the overall results for the quarter.

Slide eight highlights some of the recent developments and the positive changes that have incurred in our Wolfcamp asset. We've always believed that our Wolfcamp is a great asset. We've been developing this program for several years now; we've learned great deal and we've recently improved on many of the value drivers.

So, we plan to spend some time on the call today updating on this evolving story. Our technical teams continue to advance our knowledge of the asset and our database now incorporates all the drilling, completion, reservoir production and seismic data over four counties. And that really allows us to refine our drilling plans with very specific landing targets – landing zone targets.

We operate in the southern portion of the Permian and we enjoy some of the lowest well and operating costs in the entire Basin. We've continued to improve well performance and we're now averaging EURs over 600,000 barrel equivalents per well. And we're not done with optimizing our drilling and completion designs as you'll hear from Clay in a minute.

We're also continuing to expand the development west into Reagan County. And as I mentioned, all of these well performance and cost improvements coupled with the recent UL deal have improved the economics and lower price environments. So we now estimate breakeven oil prices at approximately $32 a barrel, and before tax returns of almost 40% assume in a flat $55 WTI price.

What that means for us long-term is because we've significantly improved the Wolfcamp asset value, we now have the ability to invest strategically long-term through cycles in the program.

So with that as an introduction to the Wolfcamp, I'll hand off to Clay to provide a deeper dive into asset. Clay?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Thanks, Brent. As Brent mentioned, we are very excited about the continued improvement in the Wolfcamp asset. In the next few slides I'm going to share some of the steps that drove the significant value enhancement, we've realized over the last 6 months to 12 months.

On slide nine, I'm going to start with the amendment to the development agreement that we negotiated with our lessor in the Wolfcamp, the University Lands System. The amendment represents a true win-win for both parties as it allows us the flexibility to extend the leasehold timeframe out to the end of year 2021 and improves our well returns with a reduced royalty burden in the current price environment.

We created a sliding scale royalty framework that adjusts royalty burdens at certain WTI oil prices, and in exchange for this, we increased our annual well completion requirements in 2016, 2017 and 2018 to 34, 55 and 55 wells per year, respectively. 2016 represents a prorated number. The execution of this amendment served as a catalyst for us to restart the Wolfcamp program and we expect to continue to shift capital and activities here during the second half of the year.

Slide 10 illustrates some of the tools we used to continuously advance our technical understanding of the asset. It starts with our dynamic earth model, which helps us to progress our subsurface knowledge of the Wolfcamp Shale. The earth model incorporates reservoir and petrophysical properties such as oil and water saturation, porosity, organic content and ultimately provides a quality assessment of the amount of oil in place in each benches of the Wolfcamp across the average position. In addition, we incorporate mechanical properties, such as max and min stress, Young's modulus and Poisson's ratio to help us understand the rock competency, the lithology of an area and the brittleness of the rock.

Our extensive database of over 1,000 square miles of 3D seismic is also incorporated into the Earth Model in order to better understand the changes in the subsurface between wells. We use all of that information to optimize our landing zones. We target the highest oil in place benches and ensure that we will maintain wellbore stability by landing our laterals in the best rock.

We also use the data to avoid drilling and completion hazards such as faults and limestone layers that can impact the vertical fracture growth of our completions. We utilize real-time measurement while drilling information to geosteer the lateral within a plus and minus 10-foot target window. This ensures that we maintain the same reservoir quality along the full length of the lateral. And lastly, we incorporate the as drilled data to finalize the completion design.

Slide 11, highlights the improved production performance we're seeing from our ongoing completion optimization efforts. The chart in the upper left of the slide shows our average oil production rates at 30-day increments. We have continued to improve our production performance through the evolution of our completion designs. The red bars represent our current completion designs which have exceeded the performance of our previous designs, which are shown in blue and green in all time periods.

The higher early time production drives returns and higher later time production results in greater EURs and greater value from the program. The other charts on the slide show the progression of the key design parameters associated with our completions. We have increased proppant loading from approximately 1,300 pounds per lateral foot to over 2,000 pounds per lateral foot while decreasing the stage spacing from approximately 250 feet per stage to below 200 feet per stage.

And we have increased fluid volumes and adjusted the fluid system design to create greater complexity and to more effectively place the proppants. All of these refinements are in an effort to improve the induced fracture complexity along the lateral and to maintain the prop conductivity and productions contribution over the life of the well.

Continuous execution improvement and cost control are key tenants of the company's operational strategy in all areas. Slide 12 shows the cost and execution improvements we have seen in Wolfcamp assets since 2014. We have significantly driven down well costs through a combination of service cost deflation and execution efficiencies.

Type well costs have reduced to approximately $4.1 million on a go-forward, next AFE basis even with the larger designs that I discussed on the previous slide. In addition our drilling execution has resulted in reduced cost per foot and improved cycle times with the new record spud to rig release in June of 4.3 days.

Another area where we have continued to exhibit top-tier cost performance is in lease operating expenses. We have reduced LOE unit costs by almost $2 a barrel to the estimated 2016 average of approximately $6 a barrel. This represents a 22% reduction over the time period, even with lower production volumes in 2016 due to the reduced activity levels.

Slide 13 shows our oil production performance relative to our 600 MBoe type curve. Again our current generation completion and landing zone designs are shown in red and the previous generation designs in blue and green. As we have optimized our completion designs, we have seen improved production performance, which has coincided with the upward progression of our type curve.

Our current generation wells are outperforming the 600 MBoe type curve and represent a mix of 2015 and 2016 wells in both Crockett and Reagan Counties. There are 19 wells associated with this curve. We are pleased with the dramatic improvement in our well performance and that is why we are now putting more capital to work in this program and expect to continue to do so throughout the second half of the year.

On slide 14, it all comes together to show the improvement in our well-level returns. The chart compares our current well-level returns in blue with our previous disclosures in black at various WTI oil prices. Due to the combination of reduced capital and lease operating costs, coupled with the reduced royalty burden associated with the UL Development Amendment, we have improved our before – our break-even oil price by $7 to $32 a barrel and we have improved our before tax returns at a flat $55 per barrel oil price to nearly 40%. The blue line is updated for the impact at the sliding scale royalty framework and benefits from royalty relieved up to $60 a barrel.

The combination of all our improvements in the Wolfcamp has resulted in well-level returns that are comparable to the Northern Midland Basin and a significant improvement in our net asset value. We are happy to get back to work in this asset and are excited about the opportunity to continue to improve performance here.

I'll now turn it over to Dane to discuss the continued progress we had made on the financial side of the business. Dane?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Thanks, Clay, and Good morning all. In addition to the materials we posted for this call, we expect to file our 10-Q this afternoon. This quarter we delivered solid financial results and we've continued to make good progress in improving our balance sheet and increasing financial flexibility. Today, I'll highlight our progress to-date, and update our guidance for the rest of 2016.

So starting on slide 16, in Q2, we continued our trend of positive free cash flow. We generated approximately $26 million during the quarter, and year-to-date, we're approaching $150 million. Our financial results for the quarter were in line with our expectations and ahead of consensus estimates. Reported diluted earnings per share was $0.25 and adjusted diluted earnings per share was $0.21. We've generated net income of $62 million and adjusted EBITDAX of $256 million.

We continue to have success reducing costs with adjusted cash operating costs down 24%, compared to the second quarter of 2015. We also continue to reduce debt. At June 30, our net debt was approximately $3.9 billion, that's $900 million less than the balance at year-end of 2015. As of June 30, our available liquidity stands at approximately $750 million, and we expect to remain free cash flow positive for the balance of 2016, so all other factors being equal, liquidity should improve by year-end.

Slide 17 highlights our progress on improving our financial position. We're laser focused on improving our balance sheet and increasing our financial flexibility. And year-to-date, we've made meaningful progress.

On our Q1 earnings call, we announced three important steps that were completed early in the second quarter. Namely, our Haynesville asset sale, the RBL re-determination and a covenant amendment along with significant open market repurchases of debt. And we've done more since then, are buying back additional debt, addition some nice gas hedges for 2016 and more than doubling our oil hedges for 2017.

Regarding the debt purchases, since May 5, we've repurchased approximately $182 million face value for $106 million in cash. Year-to-date, that total is nearly $800 million face value, for $400 million cash. So roughly a $400 million discount captured. Our weighted average purchase price was approximately $0.50 on the dollar. The average yield to maturity is approximately 27% and the repurchases reduced our go forward annualized interest by more than $60 million.

I'll update our improved hedge positions on the next slide. We're pleased with the progress, but rest assured we know there is more work to be done. Expect us to continue to consider every tool available to improve our position. The focus will be on reducing the quantum of debt, extending maturities and potentially building our asset positions for future growth.

Slide 18 shows our current hedge position including the substantial improvements we announced last week. For the balance of 2016, oil production is essentially 100% hedged, with swaps at $80.67; 60% of 2016 gas is now swapped at an average price of $3.39. We added almost 8 Bcf of gas swaps at $3 during the recent price rally to build this aggregate position.

We made a bigger move on 2017 oil hedges. In addition to the 4 million barrels of $66 fixed price swaps that have been in place for a while, we've recently added 8.8 million barrels of $46-by-$61-by-$70 three-ways. And a little color on how we did that. Earlier in 2016, we saw that we could be overhedged for 2016 oil production assuming a capital spend at the low end of our original guidance range.

In Q1 when the oil price was bottoming, we locked in the value of those potentially overhedged positions at over $40 per barrel. As oil prices rallied this summer, we converted a portion of that locked-in 2016 value, about $30 million worth, into new 2017 three-way positions with the same counter parties, providing above market floor prices while retaining upside to $70 on those volumes.

As a result of all that, if you use the midpoint of our updated 2016 production guidance, we'd have about 75% of our anticipated 2017 oil production floored above $62, with upside in the event we see a rally in oil prices next year.

In Q2 2016, we had hedged settlement cash gains of $157 million and year-to-date that number is $369 million. The mark-to-market value of our hedge book at June 30 was approximately $340 million.

Moving to slide 19, we're updating our 2016 outlook. We're halfway through the year and we have better insights into lower costs and improved program performance. In the face of continued oil price volatility, we plan to remain conservative with our capital spending for the rest of 2016 and continue to generate free cash flow. So all that's baked into our updated thinking.

We expect to stay at the low end of our capital spending range for the balance of 2016 and spend $475 million to $505 million for the full year. Our capital efficiency is improving, so we anticipate more completions in production at the midpoint of the new capital guidance compared to what we originally had forecast for that same capital spend.

Our completion activity is expected to increase in the second half of the year, 52 completions at the midpoint or 50% more than the 38 wells we completed in the first half of the year. And the mix will shift to Wolfcamp as the return improvements there merit more capital activity. All in, we expect our oil production to flatten out in the second half of the year at a level slightly below the Q2 average.

Cash costs are right in line with our last update post the Haynesville sale announcement. Based on the improvements we're seeing in capital efficiency, we now believe our maintenance capital, defined as the annual spending level required to keep production flat, has declined to around $600 million. That's quiet an improvement over the last 12 months, down from something closer to $1 billion a year ago. In conclusion, we're pleased with the cost and performance gains, but we're still in an uncertain commodity price environment, so we intend to stay disciplined for the balance of 2016.

And with that, we'll turn it back to the operator and open the lines for your questions. Operator?

Question-and-Answer Session

Operator

Thank you. We will now begin the question-and-answer session. The first question comes from Arun Jayaram with JPMorgan. Please go ahead.

Arun Jayaram - JPMorgan Securities LLC

Good morning, gents. Dane, the sliding scale royalty, I'm having some memories of your time at Burlington Resources in Canada – you had to pull that one out of the old playbook. But my first question is really thinking about capital allocation between the Eagle Ford and obviously the improving well-level returns to the Wolfcamp is if we think about oil in the $50 to $55 range for 2017, how do you think about allocating between those two assets?

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yeah, I think if you note all those improvements that Clay went through and the lower CapEx per well, better well performance, lower operating expense per well Arun that – and the sliding scale royalty, and that price range you're talking about, the Wolfcamp competes very favorably in our portfolio, with everything else we have. And that's important for us, because – and remember that's the biggest inventory of future opportunities we have and we start some drilling commitments there. So it's playing out exactly like we hope. We're getting all the improvements in the value side and we want to shift more capital and see you can see that kind of in our little bit start to see it in the second quarter and then you can see it in the guidance for the second half that we're bumping up Wolfcamp as a percentage of the total.

Arun Jayaram - JPMorgan Securities LLC

And Brent, has there been any changes on the well productivity side in Eagle Ford, or is this just a function of just the Wolfcamp getting better?

Brent J. Smolik - Chairman, President & Chief Executive Officer

No, it's a function of two things. Wolfcamp getting better and then we've been drilling those wells so fast in the Eagle Ford that we had built up 40 DUCs, I think the number was 42 DUCs by mid-year. And so we've got plenty of inventory, so we can idle the drilling rigs save some of that capital shift at the Wolfcamp and then we can work on completing DUCs in the Eagle Ford.

Arun Jayaram - JPMorgan Securities LLC

Okay.

Brent J. Smolik - Chairman, President & Chief Executive Officer

It's really nothing – it's really signaling the improvement in the Wolfcamp and all the good things we've done there to drive the valuation up.

Arun Jayaram - JPMorgan Securities LLC

Okay. You highlighted or Clay highlighted just the minimum drilling commitments. Can you just talk about what those mean if – and what type of flexibility you have around that if, for example, if you didn't hit those, what is the impact from not meeting the thresholds? I just want to understand that a little bit more.

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Sure, Arun, this is Clay. So prior to amendment, we had drilling requirements that we were working on also. And so the go-forward here is that we get the benefit of extended timeframe to earn the acreage by meeting the commitments and we get the sliding scale royalty benefit. But if we don't' meet the requirement, then we don't extend anything for that year, but we'll have the opportunity in the next couple of years to extend it and you don't get the benefit of the sliding scale royalty, if you don't meet the requirement in that one year.

Arun Jayaram - JPMorgan Securities LLC

Okay. Makes sense, and...

Brent J. Smolik - Chairman, President & Chief Executive Officer

Arun, remember we had drilling obligations here before to able to hold out acreage position together and so we had always intended to develop this to drill wells out here. So the minimum commitment that we're – if we want to extend the period of time to earn the acreage, is important that we drill those each year, but we always intended to increase activities in the Wolfcamp.

Arun Jayaram - JPMorgan Securities LLC

Okay. And just my final question, you've talked about the 2006 (31:58) wells are outperforming 6 MMBoe (31:54) type curve. Can you give us a sense of maybe the magnitude of that and I'd love to get just maybe your current thoughts on the oil, gas NGL mix on your Wolfcamp program on the go forward basis?

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yeah. Clay, start with how wells are in that recent tranche?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Yeah, in the recent tranche, there are 19 wells included in there that include the five that are online with any kind of production history so far this year, and wells from the back half of 2015. And so it's still relatively early days on those, but we're really liking the trend that we're seeing there.

And then as it relates to the mix question, as we talked about on previous calls, as you reduce completion activity, we're not bringing on the newer wells that have the higher oil mix and we're starting to see that trend pick back up now with greater oil mix as we brought on the five wells in the latter part of the first quarter and into second quarter, and then we expect that to continue to grow in 3Q and 4Q as more of the new wells are coming online as part of that Wolfcamp activity increase.

Brent J. Smolik - Chairman, President & Chief Executive Officer

And then the oil mix you're referring to there Clay is that the total oil percentage for the reported volumes for the quarter?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Yes.

Brent J. Smolik - Chairman, President & Chief Executive Officer

And we'll expect to see that growing as we add more new wells to the rest of the year. The percentage of oil will increase going forward.

Arun Jayaram - JPMorgan Securities LLC

All right. Great, thanks a lot, gents.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Thanks, Arun.

Operator

The next question is from Sean Sneeden with Oppenheimer. Please go ahead.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Hi, thank you for taking the questions. Maybe as a just quick follow up to that one, Clay, do you think you could give us just a general sense of how to think about the mix as you kind of go from some of your IP30's to kind of IP90 and IP150s, that you kind of laid out on the slide there? Just so that we kind of have a sense of how that trends over time?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

The trend of oil percentage?

Brent J. Smolik - Chairman, President & Chief Executive Officer

The GORs, how do they – early on.

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Yeah. So our wells when they initially come online are closer to 75% to 80% oil and then that trend over a time period 60 days, 90 days, 120 days starts to get in line with the general trend that we have built into our type curves, that represents a mid-40%s type of oil mix over the life of our inventory.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay, that's helpful. And I think that, that definitely makes sense. And then when you think about the profit loadings that you guys have kind of outlined there, is the expectation that kind stop at kind of that 2,000 level that you kind of characterized as third generation or are you going to look at potentially actually going above those levels?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Yeah, I think the answer there is that we're continuing to use all the science we can with our subsurface understanding to guide us to how we can improve the value and improve the production rates and EURs of these wells. Right now with all our modeling efforts, this is what we think is the best completion design, but we're going to continue to keep incorporating new information and advancing our modeling efforts to have that tell us what the best way to go.

Brent J. Smolik - Chairman, President & Chief Executive Officer

And if I could, this is Brent, just to brag a little bit on Clay and the team, it's not easy to be able to increase profit loadings and increase the number of stages and drive down the well costs the way they've done it. That's no small feat to be able to drive well cost down close to $4 million while we're increasing the numbers of stages and the amount of profit that we pumping. So kudos to our team and to our service providers to help us get to that point.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

No it's certainly – I think it's been pretty impressive, the state of lease. And then maybe just shifting to the balance sheet, Dane, maybe for you, I guess, one, could you give us a sense of how much capacity under the RBL agreement that you guys have in place that you left for unsecured bond repurchases?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah, certainly. When we did the amendment in Q1, we had $350 million of debt repurchase capacity, but the ability to grow that with things like divestitures, divestitures proceeds. And since we closed the Haynesville sale subsequently, we've built that and then we've used some of that to buy back debt, so the net-net of all that is about $600 million today.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

$600 million today that you have?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Today, yeah.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay. And then I guess when you think about the pretty positives, operational developments that you guys have unveiled herein with the 2017 hedge book in place, how are you guys starting to think about that the term loan maturities at this point? Is that something that you think gives someone on the table of trying to address this year or how are you kind of thinking about that in broad strokes?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah, we're really looking at the entire capital structure both the quantum of debt and maturities. And we've really – we're working on an array of things. And it's kind of based on market conditions when you're best able to pull those various levers, but the maturities on the term loans is definitely one of the levers we're looking at.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay. And then maybe one last one and I'll re-queue. But just to be clear, on your $250 million on free cash flow guidance for the year, are you defining that just like operating cash less CapEx or how are you guys thinking about that?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah. It's pretty much that. So debt repurchases and asset sale proceeds are not in that number. But it's just...

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah, it's EBITDA minus CapEx, minus interest expense.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay. And you're kind of basing that, roughly, on the strips?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yes.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yes. To the forward estimate part of it.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah. We're essentially 100% hedged on oil for the balance of the year. So it's not very variable based on price.

Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker)

Okay. I appreciate it. Thank you.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

You bet. Thank you.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Thanks Sean.

Operator

Our next question comes from Brian Singer with Goldman Sachs. Please go ahead.

Brian Singer - Goldman Sachs & Co.

Thank you, good morning.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Good morning, Brian.

Brian Singer - Goldman Sachs & Co.

On the sliding scale royalty, can you just talk about how that came about and whether you see this as potentially something that you – that could occur more widely in – through your portfolio or whether this was more of a one off discussion?

Brent J. Smolik - Chairman, President & Chief Executive Officer

Well, this is the only place we have this unique of a situation with our land owner, where we have a single land owner across the entire acreage position. So that starts off making it unique. We'd entertain it elsewhere because I think it's really valuable, but I don't know that it's a high probability that we would be able to repeat that. But the way it came about, and Clay you jump in if you want to anything, but I think its starts with having really good working relationship with our royalty owners and we do view that consistently across the board; our royalty owners matter. And so because we had that good relationship and they're motivated to increase activity and grow their royalty stream, their revenue streams, then we're able to find a way that really does work for both parties here.

So I think there's not that many real win-win solutions – and I think that's the way Clay referred to it – in the business world in my opinion, but this one really is a win-win. The royalty stream for them grows as we increase activity and then we're able to justify spending capital through cycles now because we've got good returns at low prices, good returns at intermediate prices, good returns at high prices, so we can invest strategically in the asset. So I'm really pleased with the outcome and the collaboration between the partners here.

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

I'll just add that there was good alignment with us being such a significant holder of University Lands as part of our position. And so it was a natural starting point discussion between us and the UL.

Brian Singer - Goldman Sachs & Co.

Thank you. And then back to the production – next question. You talked a lot about the Permian and what to expect as wells go through their life, but can you talk about the Eagle Ford and then outlook for production mix as we go forward there?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Sure, I think it's a little bit of a similar story. We've had reduced completions in the Eagle Ford and so the mix trend has trended down a little bit over the last couple of quarters; that's mainly due to reduced completions. We've also, with our lease holding requirements, moved around a little bit and so we've drilled more of the southern wells that have a higher GOR. But all of that is as expect in our models and we think as we increase completions, that percentage would trend back up consistent with past percentages.

Brent J. Smolik - Chairman, President & Chief Executive Officer

And it's a lot less of an issue Brian in the Eagle Ford. The range of GORs from north to south is much smaller. And so we'll see some of that, but it's not going be – it will be less sensitive to seeing movements in oil/gas mix in the Eagle Ford than we are in other places.

Brian Singer - Goldman Sachs & Co.

Thank you.

Operator

Thank you. And our final question comes from Gregg Brody with Bank of America. Please go ahead.

Gregg William Brody - Bank of America Merrill Lynch

Good morning, guys.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Hi, Gregg.

Gregg William Brody - Bank of America Merrill Lynch

Appreciate all the color on the Permian; just have some follow-up questions with the AR. (42:15) Specifically, for your rig requirement – for your well requirement as part of the new agreement, how many rigs do you need to run next year to achieve that? And is there some backlog of DUCs that's part of that?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

It's a roughly a two rig program that will get us there. We have to keep the right amount of drilled, but not completed wells ahead of our rigs, so that we can have efficient operations. But we can get that done with a two rig program.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yes, and those counts we refer to, those well counts, are completion counts. So it's new wells that we turned into sales. And we get to count the – like any DUCs we complete this year, they're new wells going to sale is the way to think about it.

Gregg William Brody - Bank of America Merrill Lynch

Last time, I had checked there, I think you could drill a Permian well in about – what was it, about, that you can drill on every 15 days, is that about right?

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

Yeah. We're improving dramatically. I mentioned in the script that the spud, the rig release, it was a record well, it's not our average, it was 4.3 days. But moving in, rigging up and drilling the well and then moving off is probably closer to 10 days.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yeah. We think it was closer to three per month, if you think about it that way. So three per month for two rigs get to 72 kind of new – 70 new wells a year we could drill with two rigs.

Gregg William Brody - Bank of America Merrill Lynch

And just as we try to calculate the economics of those wells, it's helpful if you provide the fixed costs versus variable per well. Do you have that?

Brent J. Smolik - Chairman, President & Chief Executive Officer

On the lease operating expense side?

Gregg William Brody - Bank of America Merrill Lynch

Yeah.

Brent J. Smolik - Chairman, President & Chief Executive Officer

And do you have it in here, Clay? We're close to $6 on total. I don't know if I have that in...

Clayton A. Carrell - Chief Operating Officer & Executive Vice President

I don't have a break-out of that.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Let us get back with you on that piece.

Gregg William Brody - Bank of America Merrill Lynch

Sure.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yeah.

Gregg William Brody - Bank of America Merrill Lynch

And then maybe switching to your maintenance CapEx. I mean, provided that $600 million is that – is there a DUC component for that and just how much is there that's non-drilling related, that's maybe facilities?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah, I think on the second one, first. Our trend has been 15% to 20% of total capital would be in sort of non-drilling, it would include facilities capitalized interest and G&A, other corporate capital. And then the DUC component, it really doesn't factor that heavily into our capital efficiency. I mean, we kind of have sort of a steady state level of DUCs. I think we have about 40% in the Eagle Ford and about 30% in the Wolfcamp.

Gregg William Brody - Bank of America Merrill Lynch

Yeah.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

That might fluctuate up and down a little bit, but it doesn't factor into our $600 million number.

Gregg William Brody - Bank of America Merrill Lynch

Yeah. Should we apply that 15% to 20% to the well cost for the Permian (44:55) that you're talking about sort of the $4.1 million or better or is that inclusive of that?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

I think you would have to add to that to the $4.1 million. The $4.1 million is the delivered to sales well cost.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Right. And then, we'd have to put non-drill capital on top of that.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Right.

Gregg William Brody - Bank of America Merrill Lynch

Great. And then maybe my last question for you. You mentioned that $30 million of hedges that you used to improve – your locked-in hedges to improve next year's price? How much – where did that come from of what you've locked in? Was that spread out evenly over the second, third, and fourth quarter, or did you take that out of a certain part of this year?

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yes, it was just probably mostly a second half of 2016 set of contracts and we had early – in the first quarter, we have locked in a larger volume that was three quarters, so second, third and fourth quarter volumes and then as we got into June and we saw that oil rally, we decided to use a piece of that value, really it's sort of the cashless extension with the same counterparties to enhance that 2017 position.

But if you're thinking about where did it come from, out of your model, it would be in the third and the fourth quarter.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Yeah. We had already settled most of the first quarter – first and second quarter.

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah. It feels like a pretty good pride sitting here today, I mean that $30 million with the hedges is probably almost doubled.

Gregg William Brody - Bank of America Merrill Lynch

Made a lot of sense to monetizing them way down in Altamont actually at the top and then Altamont or...

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

Yeah, for us to be 75% hedged to the downside on oil, 75% floors is really important, I'm glad with it.

Gregg William Brody - Bank of America Merrill Lynch

And just one more clarification if you don't mind. So the amount of the basket to buy back bonds to $600 million, is that – how much is left after the sale – after the buybacks you've done thus far, or is that the total amount of the basket and we should subtract the amount you've purchased (47:03).

Dane E. Whitehead - Chief Financial Officer & Executive Vice President

That's what we have right now after all the purchases that we've announced. And remember that has grower provisions to it, so it's conceivable, if we do other financing transactions or asset sales, things like that that we could go about in the future. But right now today, taking everything into account that we've done so far it's $600 million.

Gregg William Brody - Bank of America Merrill Lynch

Thank you for all the information guys.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Thank you for the questions.

Operator

Ladies and gentlemen, this concludes our question-and-answer session. I would like to turn the conference back over to management for any the closing remarks.

Brent J. Smolik - Chairman, President & Chief Executive Officer

Thank you operator. And I'll just recap the quarter. This is Brent. We continue to improve our balance sheet, increase our financial flexibility while we significantly enhance well-level returns and asset valuations. So we feel really get about the quarter. Thank you for joining our call this morning.

Operator

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.

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