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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Good morning and welcome to Devon Energy’s First Quarter 2019 Conference Call. At this time, all participants are in a listen-only mode. This call is being recorded.
I’d now like to turn the call over to Mr. Scott Coody, Vice President of Investor Relations. Sir, you may begin.
Thank you, and good morning.
For the call today, we have slides to supplement our prepared remarks. The slides for today’s call along with our detailed operations report and press releases are available on our website.
Comments on the call today will contain plans, forecasts and estimates that are forward-looking statements under U.S. securities law. These comments and answers are subject to a number of assumptions, risks and uncertainties, many of which are beyond our control. These statements are not guarantees of future performance and actual results may differ materially. Following our prepared remarks, we will take your questions.
And with that, I will turn your attention to slide two and hand the call over to Dave Hager, our President and CEO.
Thank you, and good morning, everyone.
The first quarter was absolutely an outstanding one for a new Devon. As we revealed last year, transforming Devon to U.S. oil growth economy, allowing us to focus on our world-class oil assets in the Delaware Basin, STACK, Eagle Ford and Powder River Basin. With this formidable U.S. oil portfolio, we have multi-decade inventory that will drive sustainable, high-margin growth for the foreseeable future. While our U.S. oil assets have many advantaged characteristics, we are not finished improving our business, and we are acting with a sense of urgency to materially improve our entire cost structure. This focus on operational excellence positions new Devon to generate substantial amounts of free cash flow in today’s pricing and allows us to future deliver value to our shareholders with increasing amounts of cash returns.
And on slide three, from almost every perspective, the first quarter can be defined as one of outperformance from the new Devon. Light-oil production exceeded guidance by a wide margin. Improvements in our corporate and operating cost structure are trending ahead of plan and our capital efficiency for the quarter is very strong. All-in-all, we are executing at a very high level on the objectives underpinning our strategic plan.
And as you can see on slide four, based on the strength of the first quarter results from our U.S. assets, we are now raising our outlook for oil production growth to 17% in 2019. This represents a 200 basis-point improvement compared to our original budget expectations heading into the year. And if well productivity from our development program continues to outperform our expectations, there is certainly additional upside to our growth rates in 2019.
Importantly, we are delivering this incremental production growth within the confines of our original capital budget of $1.8 billion to $2 billion. And this view is backstopped by our strong capital efficiency in Q1. Tony will cover in more depth later in the call, but this improved oil production outlook is driven by the prolific well results we’re delivering in the Delaware Basin.
Moving to slide five. As I touched on in my opening remarks, the asset quality of new Devon ranks among the very best in U.S. upstream space, and we are actively working to further optimize the profitability of our business. A key area of emphasis is the aggressive reshaping of our organization with the singular focus on supporting our U.S. oil portfolio in a most cost efficient manner possible.
As you can see on the chart to the left, we expect our U.S. oil business to achieve at least $780 million in sustainable annual cost savings by 2021 versus our 2018 baseline. Our cost reduction plan includes a range of actions to achieve more efficient field level operations, lower drilling and completion costs, and better alignment of personnel with the go-forward business.
Turning your attention to right hand side of the slide. With our strong possible performance year-to-date, we are now on track to deliver more than 70% of our targeted $780 million in annual cost savings by year-end. The most significant contributor to our cost cutting performance is a substantial progress we have made improving our G&A cost structure. This was clearly demonstrated by our first quarter G&A results which improved 23% year-over-year and were below our guidance range for the quarter. Furthermore, with the steady cadence of successful cost reductions attained throughout the quarter, we now estimate that we have captured approximately $110 million of overhead savings on a run-rate basis. This momentum is projected to reduce G&A by more than 10% in the second quarter and with the planned exit of Canada and the Barnett asset of our portfolio, we expect to attain more than $200 million of annualized G&A savings by year-end.
Another key contributor to our cost reduction efforts is the capital efficiency we’re realizing as our U.S. oil business transitions to full field development. These efficiency gains were evident in the first quarter with capital spending declined 15% year-over-year and was below the low-end of our guidance range. Looking ahead, our U.S. oil business is well on its way to capturing $200 million or roughly 65% of our targeted D&C cost savings in 2019. Key drivers of this improved capital efficiency throughout the remainder of the year are improved cycle times associated with our Wolfcamp program and optimize infill spacing program in the STACK and the benefits of a dedicated frac crew in the Powder River Basin.
And the last item I will touch on with this slide is our plan to reduce our go-forward interest expense. With our plan to exit Canada and the Barnett, we expect to use potential proceed to retire up to $3 billion of debt, which will reduce our interest cost by about a $130 million or roughly 45% annually.
Turning to slide six. Our efforts to high grade our portfolio are also progressing. As we discussed last quarter, with our U.S. oil assets reaching sufficient operating scale to deliver advantage to returns, sustainable long-term growth and free cash flow, the timing is now appropriate to exit our legacy positions in Canada and the Barnett Shale.
In Canada, since the last time we spoke, we have made substantial progress advancing the exit of these assets from our portfolio. Data rooms have been open for some time, and we are having discussions with multiple parties regarding an outright sale at valuations consistent with our view of the intrinsic value of the asset. I am very encouraged by the nature of these discussions and we are well on our way to exiting Canada in a timely manner. With our Barnett Shale assets in North Texas, we’re also advancing the sales process with data rooms opening in the second quarter. Overall, for both Canada and the Barnett, we remain on track to have these assets exit our portfolio by the end of 2019.
Turning to slide seven. My final key message is that we’ll remain unwavering in our commitment to capital discipline and increasing cash returns to shareholders. As I’ve stated many times in the past, the benefits of any pricing windfall above our base planning scenario will simply manifest in higher levels of free cash flow for Devon, not higher capital activity. And given today’s favorable market conditions, our business is generating considerable amount of free cash flow that we’ll return to our shareholders.
With this disciplined and shareholder-friendly approach to the business, we are on pace to reduce our outstanding share count by more than 25% by year-end, and owners of our stock will also benefit from our recently raised dividend; it is 50% higher than just a few years ago.
So, in summary, our go-forward asset base is delivering top-tier operating results; our cost reduction efforts are trending ahead of plan; our portfolio transformation is on track to be completed by year-end; and we’re delivering on our promise to return cash to our shareholders.
And with that, I will turn the call over to Tony Vaughn, our Chief Operating Officer.
Thank you, Dave, and good morning.
As Dave touched on his opening remarks, new Devon has an advantaged asset base with unrivaled acreage positions in the best U.S. oil plays that strikes a great balance between sustainable growth and free cash flow generation. With our capital programs focused entirely on low-risk development opportunities in the economic core of the plays, we are experiencing a dramatic step change improvement in well productivity, capital efficiency, and corporate level returns. Not only is our go-forward business delivering operating results that rank among the best in the industry, but new Devon’s large, contiguous stacked-pay acreage positions provide us a multi-decade growth opportunity to drive high-return activity for the foreseeable future.
For the remainder of my prepared remarks today, I will focus on the Delaware Basin operations, which is the capital efficient growth engine, driving new Devon. Turning to slide number eight.
This page clearly demonstrates the substantial operating improvements that we have attained in the Delaware Basin over the past few years. The graphic on the left hand side of the slide showcases the tremendous step change improvement in well productivity we have accomplished in the Delaware with our ship to full field development. The focused development activity we have deployed in the economic core of the play has nearly doubled our well productivity in 2018 compared to our historical average. Importantly, we are not done improving. And based on our year-to-date results, we are well on our way to heating new record highs in well productivity during 2019.
Shifting your attention to the right hand portion of the slide, another area we have done a great -- a lot of good work is to maximize the value of our production with a marketing flow assurance strategy. I won’t go through all of the details here, but after including the benefits of hedging and firm transport, our light-oil realizations are near WTI pricing levels and gas revenues are protected by an attractive regional basis swaps. Furthermore, we have leveraged operating scale and acreage dedications in the Delaware to attain contractual, flow assurance guarantees that extend well into the next decade. Our margins will also benefit from the field level infrastructure we have invested in, which have substantially reduced our per unit operating cost by 60% from peak levels and will continue to drive per unit expenses lower in the future.
Overall, these results are nothing short of outstanding, given the constraints in this very active basin. The hard work and thoughtful planning from our operating teams is paying off and positions us well for long-term success.
Turning to slide number nine. I want to be clear on this one point, we are just getting started in the Delaware Basin. We have the acreage position and the inventory to lever this world-class performance in the Delaware Basin for many years to come. At today’s drilling pace, the 2,000 high return locations we have identified equates to 16 years of inventory. With the depth of stacked-pay resource across the Delaware, we expect our high-return inventory to continue to expand as Devon and the industry further delineate the rich geologic column across our acreage footprint.
And finally, on slide 10, let’s briefly pivot the conversation to the outstanding results in the Delaware Basin that drove Devon’s outperformance in the first quarter.
During the quarter, we brought on 25 new wells across the state line area of southeast New Mexico which helped net production in the Delaware surge 76% higher year-over-year, 76%. While we had great well results across our acreage position in the quarter, activity was headlined by five massive Cat Scratch Fever wells, targeting a second Bone Spring sweet spot in our Todd area.
As you can see on the map to the right, these prolific wells achieved average initial 24-hour production rates of 10,000 BOEs per day per well. All 10 wells from the first phase of the Cat Scratch Fever project are now on line and initial production rates from these wells are some of the highest in the 100-year history of the Delaware Basin. We will follow up the success with the second phase of the Cat Scratch Fever project that is expected to be on line by year-end. The 10 development wells associated with Phase 2 will provide a nice uplift to our Delaware Basin production in the fourth quarter and provide strong momentum into 2020.
Another key area where we are achieving very strong results is in our Rattlesnake area in southern Lea County where we have six Wolfcamp development projects underway. Our first two projects Seawolf and Fighting Okra have been great successes for us with average 30-day production rates in excess of 3,000 BOEs per day per well. The next catalyst for Devon in this area is our multi-phase Flagler development, where the first phase of this project will bring seven upper Wolfcamp wells on line around midyear. Beyond Flagler, we have three other projects that will contribute to our growth trajectory over the next year. This Rattlesnake acreage is truly special, and I look forward to providing updates in the future quarters on our high rate wells.
And with that, I’m done with my prepared remarks and will now turn the call over to Jeff Ritenour, our Chief Financial Officer.
Thanks, Tony.
My comments today will be focused on detailing the next steps and the execution of our financial strategy. Beginning with our balance sheet, we have tremendous amount of flexibility when it comes to our financial position. We exited the first quarter with $1.3 billion of cash on hand and expect this balance to meaningfully increase in the future with the proceeds from exiting the Barnett and Canada along with the free cash flow that new Devon is generating at today’s strip pricing.
As you can see on slide 11, this exhibit outlines the free cash flow new Devon is capable of delivering at various pricing points. This plan is designed to completely fund our three-year capital requirements in an ultra-low WTI breakeven price of $56, while providing an attractive mid-teens oil growth rate. And at $65 WTI pricing, the new Devon is capable of delivering three-year cumulative free cash flow of $3 billion. This is equivalent to more than 20% of our market cap at today’s share price and represents a very competitive free cash flow yield to investors while still providing an attractive oil production growth rate.
A top priority for our excess cash is the repayment of our debt in order to maintain Devon’s targeted debt to EBITDA ratio within a range of 1 to 1.5 times. With this strategy, we expect to redeem up to $3 billion of debt maturities by year-end with proceeds from Canada and the Barnett, which would result in our go-forward interest expense declining by approximately $130 million annually on a run rate basis.
In addition to debt repayment, another key financial priority is the return of cash to shareholders. From a dividend policy perspective, our goal is to steadily grow the dividend by targeting a manageable payout ratio of 5% to 10% of our operating cash flow. With this policy, our quarterly dividend is increased by 50% over the past few years. And given that our go-forward U.S. oil business is well-positioned to efficiently expand cash flow for the foreseeable future, we expect to reward shareholders by continuing to steadily grow our dividend over time.
With regards to our ongoing share repurchase program, not only is this the most active program by a wide margin in the E&P space but is also one of the largest buybacks regardless of sector in the S&P 500. Over the past 12 months, we have repurchased 114 million shares at a total cost of $4 billion. The execution of our remaining $1 billion authorization will result in a reduction of over 25% of our outstanding shares. To accomplish this, we expect to utilize cash on hand and free cash flow generated throughout the year to continue the repurchase of our shares.
So in summary, our financial strategy is working quite well. We have excellent liquidity and our business is generating substantial free cash flow. The go-forward business will have a debt to EBITDA ratio pushing towards 1 times, and we are set to sustainably pay and steadily grow the dividend for the foreseeable future. We will also continue to aggressively buy back our stock.
With that, I’ll turn the call back over to Scott.
Thanks, Jeff.
We will now open the call to Q&A. Please limit yourself to one question and a follow-up. If you have further questions, you can reprompt as time permits. With that, we will take our first question.
Thank you. Our first question comes from the line of Arun Jayaram from JP Morgan. Your line is open.
Good morning. Arun Jayaram from JPM. Dave, you touched on this in your prepared remarks. But, I was wondering if you could characterize the interest level in both of the data rooms that you opened in 2Q. And as you sit here today, how would you handicap the potential for a Canada spin versus outright sale?
Well, in Canada, as we said, we are in discussions with multiple parties. We are having advanced discussions with them at a value that -- values we think are appropriate for the intrinsic value of the assets. I don’t want to go into more detail than that, but we feel really good about those discussions we have. And we are optimistic that it’s very likely that we could have a sale of those assets. We are of course in the background working in parallel, the potential spin and all the steps that are necessary to do that. We view that as -- at this point probably more of a backup plan, most likely. And so, we’re encourage. I don’t know if I want to put a percentage on it of everything, but we’re encouraged where those discussions are.
In regards to Barnett, we are -- have not yet opened the data room; it will be opened very soon. We have received a lot of inbound cost. It’s not often when a quality asset such as this with a very large contiguous acreage position with very low decline assets that frankly we’ve been able to enhance with some recent drilling and completion activity through our promoted interest that we’re receiving through the Dow joint venture that we have to show the capability what a modern drilling and completion activities could do in the Barnett. It’s not often you get an opportunity to bid on that type asset. And we think that people are seeing that. This has a unique compelling opportunity. And so, we’ve received a lot of phone calls already around that. And we’re very confident, once the data room is opened that we will be able to proceed in timely manner and advance to a sale of that asset.
Great. And just my follow-up, Dave or Tony. I was wondering if you could provide some color around Phase 2 of Cat Scratch Fever. It looks like from the cartoon, it’ll be completed over a bit of larger area like step in Phase 1. So, I was wondering if you could maybe compare and contrast the development, and perhaps the spacing and lateral lengths of those two projects.
I’ll do that, Arun, and then I’m going to turn the call over to John Raines who is our Business Unit Vice President. He’ll be able to give you a little bit more granular information. But again, Arun, I think we’ve commented in the past that this area in Todd is a special area; it’s got additional sweet spot at the top of the second Bone Spring wells that we have mapped out extremely well. The guys have done a lot of subsurface technical work on the area. We knew it was going to be special area, didn’t understand how special it would be once we started producing the wells. But the Boundary Raider wells followed by these 10 wells in Phase 1 have been outstanding. And I’m going to let John describe where we get to in Phase 2.
Yes. Arun, it’s a good question. Following specifically on Cat Scratch 1.0, the full program of 10 wells is a mix of single-mile wells, mile and a half wells and the two-mile wells, we obviously highlighted here in the quarterly option for it. We had three single mile wells, and two one-mile-and-a-half wells. As we contrast that to Phase 2, right now, we’re planning on having six one-mile-and-a-half laterals, two two-mile laterals, and two single-mile laterals. And I’d say, the big difference between the two projects, as we go east, obviously we’ve had significant outperformance on the first phase of the project. I would note and be transparent that we have not made upward adjustments to our expectations for Phase 2. And the reasons for that, one, we have a little bit of thinning in the pay in our upper second Bone Spring sweet spot. As you move east, this project does move east with a little bit of water as well. But, what I would say is, we’re highly confident in Cat Scratch 2.0. And the last two wells that we brought on in Cat Scratch 1.0 were approximately located in and around the area of the majority of the Cat Scratch 2.0 wells and they are exceeding our forecast to type curves based on early time results.
Our next question comes from the line of Scott Hanold from RBC Capital Markets. Your line is open.
Thanks. Good afternoon. And, Dave, you’ve commented that if the well performance continues to look strong, there’s some upside, potentially oil production through the course of 2019. Can you just quantify at least maybe just for 1Q just to give us a sense of was the outperformance all directly just better productivity or was there just some more efficient operations that also enhanced that or OBO activity?
I think, we overall characterize it to be about 70% well performance and a 30% well timing, moving up to well timing of it. And -- but just to be clear on that, Scott, what we really did with our increase of 200 basis points to the 2019 oil guidance, we only took into account the actual results from Q1. We did not adjust up any future activities. And John just mentioned a couple wells early on that are exceeding expectations. Of course, that is early, and we feel good about the program. But we thought the most appropriate thing, and perhaps a somewhat conservative thing right now is to just adjust out for the Q1 activity and then see how we perform on the remainder of the activity and then make adjustments, if appropriate, then.
Okay, I appreciate that. And with respect to doing things a little bit quicker, and obviously this stronger oil price environment that’s occurred since -- I think they’ve already put off their budgets. Have you seen any -- and I know you guys kept your budget unchanged. Have you seen any inflation pressures that are different than what you last spoke of? And, given the fact that you are maybe, what, 30% advantaged, I guess in that 70-30 split you gave me, is -- what would you do kind of as you get through the year, if you continue to run ahead of pace?
Well, let me just make one point, very, very clear to start with. We will not be raising our capital guidance. Period and stop. Okay? So, we are executing very well on our program. We have -- we’re really essentially just executing our program right now that we had planned to execute for 2019. We have executed it a little bit quicker so far. But I might turn it over to Wade Hutchings, our Senior Vice President of E&P, who -- he can walk you through a little bit more of the details, if you’re curious. I mean, the overall picture is that you add completion rates occasionally during the year and rigs. And then, when you need them on a spot basis, you back us out -- back them out at times. But that’s all part of our original plan, and we are just executing on that plan, and that’s what will execute this year. And you can see by the great results on the capital efficiency in 2019 -- or first quarter 2019, we will not be raising capital guidance because the results we’re achieving. But, I think Wade can give you a little more details if you’re interested on just kind of an ins and outs of the activity?
Sure. Happy to do that, Dave. I would just reiterate, now that we’re about four months into the year, our month-to-month, quarter-to-quarter plan on rigs and crews is proceeding really quite close to our original yearly plan. And let me give you a little bit of context for what you see in our 2Q guide. Essentially, what you’re seeing there is the execution of our plan in the Rockies, where we had indicated that we would be building enough inventory to support a full-time frac crew. That crew is now in the field. And so, that’s contributing to that second quarter guide, as well, we have very specific project in the Delaware Basin where we’re bringing in a spot crew that spans part of the second quarter and third quarter. So, that’s what’s contributing essentially to the second quarter being our peak of activity for the year.
When you look at it on a more full-year basis, in the second half, you should see our capital roughly average a touch under $500 million a quarter. That’s really driven by the planned reduction of one frac crew in the STACK in the second half of the year, and then, essentially, the completion of this midyear spot crew in the Delaware, and actually the completion of some increased spot activity in the Eagle Ford in the middle of the year. So, again, very confident in the full-year guide we’ve given and are able to use the flexibly we have in our programs to ensure that we’ll meet that guidance.
Okay. And was there any OFS commentary that you all could provide, the inflation side?
Hey, Scott, this is Jeff. Yes. No, absolutely, throughout different cost categories across the portfolio, you’re seeing some inflation but we’re also seeing deflation in several areas as well. So, from our standpoint, enterprise-wide, we really see a flat inflation, deflation output as compared to 2018. So, with the cost efficiencies that we’re driving in the activity that the team’s described, marry it with some of those puts and takes, we really see flat year-over-year basis.
Our next question comes from the line of Doug Leggate from Bank of America. Your line is open.
Thanks. Good morning, everybody. Guys, I wonder if I could actually start with the STACK and talk about the evolution of the up-spaced wells, at least that they are showing substantially better performance relative, obviously you showed one clear example, but just across the board at least by that changing spacing is having a very significant impact. I’m just curious, if you could offer any commentary around that and whether it would change your relative plan in terms of where incremental capital goes across the two main areas?
Hi, Doug. Wade Hutchings is going to that.
Yes. Good morning, Doug. Yes. We’re certainly pleased by the new spacing projects that we now have on line. If you look there on slide 17 of the ops report, you’ll see we’re giving you a third -- about a 60-day update on three of those keys. You can see all three of them are actually at or above our expectations. And if you recall, that’s our new infill type curve expectations for this core volatile oil area to play. If anything, we’re seeing slightly better oil rates than that type curve suggested. So, yes, broadly, we’re encouraged by that.
I would say, our capital allocation for the STACK for the year is essentially based on that kind of result. And so, at the current moment, I don’t know that we’re anticipating a significant shift of capital in the stack relative to our 2019 plan.
One last key point is the key thing that’s also driving our continued investment in the STACK in addition to this well performance, is we are seeing the impacts of our optimized stimulation design, which we’re quite confident is giving us at or better stimulation than we’ve had in the past at lower capital costs.
Sorry. I was just going to ask -- I appreciate the clarification, Wade. But, I just wanted to check, should we anticipate that you -- and obviously, you cut your type curve after the past year? Is it possible that you maybe took it a little too far, will you start to see that reset higher again or are you comfortable where we are right now?
That’s certainly always a possibility. I’d say today, based on the results we have we’re comfortable with that type curve. But, we’re going to get a lot of new results over the next few projects. And we’ll certainly revise that upward as warranted by the results. I’d just say, again, we’re encouraged by these first few more optimally spaced projects that we’ve now got in the ground.
I appreciate that. My follow-up, Dave, I’d love to get into a little more detail on the Delaware and the inventory levels and so on. So, I wonder if I could just try and hit a fairly high level. If I look at the current 16-year inventory that you mentioned in the slide deck. Obviously, that’s a risk inventory level, but it’s also at the current pace. So, I’m just wondering, how should we think about the inventory debts evolving over time as activity changes? Maybe I don’t know how you’re thinking about that over your longer term, but obviously vision 2020 is only a year away now. So, when you think about over the next three or four or five years, how does that evolve? And I’ll leave it there. Thanks.
Well, Doug, I’m going to have Tony or John address this in a little bit more detail. But, I think, the first thing to know that we’ve said before about where we are in the Delaware program is, we’ve spent the bulk of 2016 and 2017 and the first part of 2018 really appraising what were the best zones to develop in different parts of the acreage position in the Delaware. And then, as we started moving through the last part of 2018 and now in 2019, and for many years here to come, we are now -- have a much better understanding of which are the best zones to develop and which areas. And so, we are really drilling the best zones, and you’re seeing the results for that. And that’s what the uptick and performance in the Delaware. And the most important thing is this is a sustainable increase that we’re going to have this rate of change that we saw moving into 2019 is sustainable for many years in the future.
I think, John’s going to tell you we’re still continuing to do some appraisal work out there. And we’re finding some zones that are working in areas that we had not anticipated before. So, we feel really good about the 2,000-well, inventory. But, I think there’s potential as we do more work to have this go somewhat higher. I think, John can give you a little bit more feel on that. So, John, do you want to?
Yes. I’d say, the number we disclosed, the 2,000 locations, really represents what we feel good about today in terms of our characterizations. If you take a look at our unrisked count, we’re at about 5,000 potential locations. And that represents potential future inventory and acreage positions that aren’t necessarily within our core five areas that we tend to talk about. And one thing that we’ve seeing out here with heavy industry activity, industry is going to help us derisk some of that inventory. And then, as Dave mentioned, 90% to 95% of the current year program is for development type of inventory. But, we have a very meticulously planned appraisal roadmap. But we’re planning our key appraisal projects by chance of or a probability of success as well as the NAV that they bring into our development inventory. And right now, we’ve focused mainly on advancing our Leonard and Wolfcamp programs in our Todd, Cotton Draw areas. So, feel really good about the inventory situation, even beyond the 2,000 that we disclosed in the ops report.
Sorry, guys. To be clear, 16 years, does not go up or down or the objective to kind of hold that flattish as you move through next several years development pace? That’s really what I just wanted to get at?
Yes. I’d say, we’re probably going to keep it at least flat as we add more inventory, if there is additional appraisal work.
Hey, Doug, this is Wade Hutchings. Hey, Doug, let me add a little bit more high level color here. I think for clarity, we would note, all of these life of inventory calculations are at today’s activity levels. So, that’s just one clarification.
Last quarter, we essentially introduced a new set of more clear, transparent information about our inventory. And so, if you recall, last quarter we talked about at the four-basin levels, 4,200 high-quality locations, the 2,000 in the Delaware are part of that. There is a couple of really key points I want to make. First, different than any of the disclosures we’ve made in the past on inventory, those numbers are operated only. And so, we’ve really focused in our characterization approach on where are we confident that we will operate on the acreage we have. And so, that’s one of the key differences from what we’ve told you in the past.
And so, when we talk about 2,000 high-quality locations in the Delaware, those we have a significant amount of confidence in. And as John noted, when we look at that at higher price points or even on an unrisked basis, that operated number of goes well over 5,000 locations. So, we’re actually encouraged by the depth of inventory we have in the Delaware today and certainly that’s why you’re seeing a capital flow there.
One of the other things we’d note is, as we focused in on our operated positions, the teams have done an excellent job of improving the size and scale of that through lots of trades. So, our non-operated positions have actually strong. And as we have traded those non-op positions or core operated positions, one of the key things that’s allowed us to do is turn more of our inventory from 5,000 to 10,000-foot locations.
Our next question comes from the line of Subash Chandra from Guggenheim Partners. Your line is open.
Yes. Thank you. The first question maybe for Jeff. If you could remind us from potential asset sale proceeds, what proportion would go towards delevering to keep the parity on debt EBITDA metrics, and what proportion might be to refuel share buybacks?
What we’ve said from day one is our expectation is the first $3 billion would go to debt repayment. So, the combination of the proceeds we received from both Canada and the Barnett will take the first $3 billion and work our leverage metrics down to that -- into that lower end of that 1 to 1.5 times ratio. And anything beyond that would be available for other alternatives and share repurchase would be at the top of that list.
Okay, thanks. And maintenance questions for Wade on the Permian and the inventory there. I’m thinking of slide 16 in the ops report, which has the circle and the number of potential intervals. I was just curious, even though we’re not addressing that on this call. But, if you recall that slide, I’m just curious, maybe what proportion of those circles have been tested to-date? Because I think -- go ahead. Sorry.
This is John. I think what we’re trying to represent in that slide is just the full column of opportunity there. I’d say for the most part, we have tested the majority of these potential landing zones in our Thistle and Rattlesnake areas. As we move west in the play, we’ve got more appraisal to do in the Leonard, in Cotton Draw and Todd, as well as the Wolf Camp, in Cotton Draw and Todd. And then, right now we’re drilling our first Wolf Camp development spacing test in our Potato Basin area. So, I wouldn’t give you a percentage but that just generally tells you how we’re progressing the derisking of our five core areas in Delaware Basin.
Yes. That helps. And just a final one if I can in the PRB also on the spacing, which interval and what spacing have you launched in the quarter?
Hey, Subash, you cut out on that. Could you please repeat the question for us?
Yes, sure. In the PRB, you’ve launched the spacing test, I was just curious, which interval and what spacing you’re testing?
We’re testing the Turner right now. And we’re probably saying that something more appropriate to three wells per section is going to be what we land on there in the Turner. I’m going to turn the call over to Aaron Ketter who’s head of our Rocky Mountain business unit.
See, in this quarter, we’ve obviously been continuing to address the Turner across our acreage, which is varying in stages from development to appraisal depending on the acreage position. And in conjunction with that, we’ve also commenced our Niobrara spacing test. And so, that’ll be very important to us, as we get results the latter half of this year and really set up our 2020 capital program.
Right now, for that test, we’re entertaining three wells per section with some upside there, but we’ll wait to get the data back before we make better decisions.
Our next question comes from a line of Charles Meade from Johnson Rice. Your line is open.
I wanted to ask first question about the Eagle Ford. You’ve had a change of partners there, and it’s a little I’d say best prominently discussed in your -- at least in this quarter’s results. Is there any kind of change to your thinking about whether -- or how important that is in your new Devon portfolio?
Well, we are very encouraged with the working relationship that we have with BP; it’s been a great relationship so far, our great exchange of technical views on the asset. And as a result, we think that we are -- our view of the asset frankly has improved. And we see a good growing inventory out there. Obviously, it’s -- in addition to that, it’s a high margin asset with the Gulf Coast type pricing plus that you get for the asset and generate significant free cash flow. So, we’re extremely pleased to have that as part of our inventory for the new Devon company.
Got it. Thank you. And then, if I could ask another question about the Cat Scratch Fever wells in the Delaware Basin, I guess, there is two parts. One, you guys have been pretty open to the fact that those 10,000 BOE a day rates, those are test rates. But, can you give us an idea just in broad terms whether -- or at what rate perhaps as a percentage of those test rates that you’re actually producing those, and those are actually contributing to say, 2Q volumes? And then, the other thing about those rates is it really indicates a different kind of reservoir. So, is there a chance that you can drill wells at significantly wider spacing and still capture the majority of that resource in place?
Yes. This is John. With respect to the spacing, we’re very confident in the four wells per section. So, that is the plan that we’re currently executing out there in the drilling phase. We do feel that this is a sweet spot in our Todd area. So, the overall inventory associated with the project is quite limited to the two phases of Cat Scratch Fever. Back with respect to your earlier question around the contribution to the first quarter beat, I would say that most of that is driven by the Cat Scratch Fever Phase 1 program. These wells exceeded significantly our type curve estimates and each of those wells, in particular the five two-mile wells, approximately 60 days in are still exceeding our forecasted production by about 1,000 barrels a day each. So, you could see, it’s delivering quite a bit of the beat in the first quarter.
And our next question comes from the line Brian Singer from Goldman Sachs. Your line is open.
Continuing on the theme of the Permian inventory but more from a rate of return perspective, can you just give us your latest thoughts on how the Wolfcamp rates of return compare relative to the Bone Spring, relative to the Leonard? And then, as a follow-up question with regards to slide 16, as you go through your derisking efforts, do you think that that’s going to result in greater confidence in the 2,000 locations or an increase in the locations within the number of landing zones that you highlight for subfield here?
I’d say with respect to your latter question, we feel like the derisking that we’re undertaking in the Delaware Basin, not only Devon but industry, will result in an increase in the number of locations, not necessarily landing zones. I think, we’ve laid those out on slide 16. But, we feel that overall it will increase the number of locations.
With respect to our three core programs on a rate of return basis, one thing that’s unique a little bit about the Devon position, we’ve got five core areas of consolidated acreage, each of which has some difference in the geology. So, our characterizations vary across those five areas. But generally speaking, all of these are very competitive programs with rates of return that exceed on a burden basis north of 40%. Again, depending on which area we’re drilling, the Bone Spring could be better than the Wolfcamp, the Wolfcamp could be better than Rattlesnake. But generally speaking, they’re all very competitive.
And then, within STACK, what are the in STACK -- what are the key milestones that you’re looking for over the course of the year as it relates to how you think about your 2020 plan? So, you talked about stable production this year. Is it your goal that STACK is going to be a stable production type strategy for the next couple of years, and what could change that?
I may just start off. I think we view the STACK as really one of our flex assets, so we have that. We are going to maintain capital discipline as a company, and it’s going to be a significant free cash flow generator for the Company. But, it’s one of the assets, given the success we’re having into Delaware, the growth we’re seeing with the opportunities we have in the Rockies, the program that we’ve lined out with BP and Eagle Ford, it’s the one asset that we have the ability to really flex the rig count up and down, while generating significant free cash flow. So, having said that, Wade, may be able to walk through a little bit more of the operational milestones that we’re looking at for over the next year or so.
Yes. Happy to do so, Dave. I think for 2019, our primary focus is continuing to develop the core volatile oil part of the play, continuing to execute on this new optimized spacing program that we have. We do, however, this year have two pretty important appraisal tests of development mode in the more liquids-rich gas condensate window. And so those results are pretty critical to inform our plans for 2020 and 2021. And so as those results come to a mature state; we’ll certainly be sharing those with you. So I’d say that’s really the key milestones for the year, is determining the depth of extent of the core volatile oil window that we can continue to develop and then the running room in that gas condensate window. But, I’d just reiterate Dave’s point. We’ve now gotten the STACK play to a spot where it’s generating material cash flow for us, somewhere on the order of $300 million a year, and so we see it as a -- as a really important part of funding our future growth objectives across the enterprise.
Our next question comes from the line of Jeanine Wai from Barclays. Your line is open.
My first question is on free cash flow. And Dave in your prepared remarks, you indicated that any excess free cash flow would not be recycled back to the drill bit and we noticed in your earnings presentation that you now only list three uses of free cash flow instead of four in your April presentation. I guess the reinvest in high-return US oil business option kind of dropped off there. Can you talk about what’s changed in your thought process between now and your previous update? We like that you’re signaling to the market your commitment to the CapEx budget, but we kind of thought that was equally strong last quarter. So we’re just wondering if there’s something in the operating environment that you’re seeing that kind of factored into this. You mentioned flat cost year-over-year, so is it something related to like logistics or expected asset sale proceeds or something else?
No, nothing has really changed with that. Well, I think the only reason we dropped that off is that we have already laid out that plan, that we plan to execute with the New Devon. And we are committed to staying with that plan that we’ve already laid out. So I wouldn’t say that operationally there is any change at all. It’s just that from a, I guess, that slide standpoint, we have already communicated what the plan is. People understand what the plan is, we have no plans to change that. We are going to be very disciplined from a capital standpoint and focus on the high-return areas in our New Devon. So really, the optionality is not around changing that plan. The optionality is around the other -- everything else that we’ve laid out there. But there’s no -- I would not look at it as any sort of strategic change at all.
And then, my follow-up question is on efficiencies. You also mentioned that you’re executing a little more quickly than expected and that matches I guess, specifically in the Delaware your Q1 spuds are tracking ahead of the quarterly run rate. So given your commitment to the CapEx budget which you’ve made very clear, if your efficiencies continue to pull forward both drilling and completion, where in the portfolio does CapEx come out first to offset this? We noticed in the presentation last night that the Delaware percent of total CapEx ticked up a little bit and I think you mentioned there was some flexibility in the Eagle Ford and the STACK and some of your other comments.
Yes. And I’ll let Wade walk through the details of that before we see it.
Sure. Let me address two key parts of your question. I think to the question of where will the first dollar come out if we need flexibility to stay within our capital guidance. Short answer to that is, we had a lot of flexibility in the STACK area and that’s likely where that first dollar would come out. Back to your earlier question on the improvements that we continue to see in cycle times and the opportunity we continue to capture at pulling-forward IDs. There’s a lot of things that drive that, but we have a fairly intense focus today on all of the whitespace in our capital execution programs between when we spud a well and when we’re able to bring that well on line. And many of the times that you’ve seen us pull forward IDs, those are simply because we’ve found areas in that whitespace to eliminate. And so we’re able to get the well online sooner even though our basic execution timeline of spuds may not have changed materially.
Our next question comes from the line of Ryan Todd from Simmons Energy. Your line is open.
Maybe a couple of quick ones. I mean, congratulations on the progress you have made so far in terms of cost reduction and the update on the reduced outlook for the 2019 SG&A. Maybe can you talk about -- is there -- you’re clearly ahead of expectations probably where the market maybe even expected you to be by year-end in the first quarter. Is there a potential upside to the $300 million total? Is this just you think you’ll get there faster than where you thought? And between now and year-end 2019, how much more outside of the Canada and Barnett, how much more do you think -- what’s the potential upside that you think you get the SG&A down between now and then?
Hey, Ryan. This is Jeff. Yes. No, I appreciate the question and as we think about the run rate going forward, we really feel like we’re well ahead of schedule. As you described, if you look at our guide for the second quarter, it equates to about $110 million excluding the Canada and the Barnett piece which is again, ahead of our $200 million estimate for the full year. So I would answer the question to say, yeah, there’s always potential upside. We’re continuing to look at all parts of our business and attacking each of the different cost categories. So, we feel good about that. It’s too soon obviously to change any guide at this point in time, so we still feel very comfortable with the parameters that we laid out on the last call. But we continue to expect on a quarterly basis you’ll see that run rate continue to trend down as we walk through 2019. So obviously, there’s still some noise in the first quarter. You’ll really see the savings show up in our second quarter results and then further as we can move into the third quarter and fourth quarter of this year.
And then, maybe just a quick follow-up. I appreciate the color that you gave early on in the Q&A about the progress on the sale of the Canadian assets. Do you anticipate the decision on Trans Mountain expansion, which I think is targeted for June 18th, will have any impact on the timing of the conversations in terms of the Barnett Canadian sale?
We don’t think so. And there are obviously a lot of variables that are going on, but the company that we’re talking to are long term players there. They’re sophisticated players, they understand all the variables that are sitting out there. Obviously prices have improved somewhat, differentials have improved in the shorter term, while longer term, it looks like the differentials are trending more toward real economics. These guys all understand all these variables quite well, and I wouldn’t isolate any one variable in here as being really the most important in order to move forward with this.
And our next question comes from the line of David Heikkinen from Heikkinen Energy Advisors. Your line is open.
I think you kind of got to this point of your Delaware results grew 15,000 barrels of oil a day quarter-over-quarter, and it sounds like that’s sustaining pretty well with the 60-day rate. How do you think about just Phase 1 and then Phase 2, adding that much volume and then digesting it and then growing is how I kind of see things flowing. So Delaware declines quarter-over-quarter, is that that reasonable? And then you see another big bump up at the end of the year with the Phase 2 coming back.
Hey, David. This is Scott. From a modeling perspective, the trajectory of the Delaware, obviously you saw a pretty significant uptick in Q1. We’d expect some minor growth in the second quarter on an oil volume growth basis in the Delaware and then certainly we’re positioned for strong growth in the second half of the year. So that’s going to be driving the overall corporate growth rates. And as you saw, we’ve raised our guidance for the full year and on top of that, we also raised our exit rate growth too. So the Delaware is the key growth engine. The Rockies is going to start contributing in the second half of the year as well, and we’re going to have a lot of momentum heading into 2020 as well.
And then, Dave, I don’t believe you’re trying to signal anything with the up to $3 billion of debt reduction with the asset sales as far as the proceeds by putting a cap or anything on proceeds, is that fair?
That’s entirely fair, David. We are not signaling anything. We’re just saying that the first $3 billion of proceeds from the sale of the Canada and the Barnett will go to debt reduction and that’s what we’ve said. Before we began the process, that’s what we’re saying today. So there’s no signaling at all going on.
Yes. I didn’t expect it. Thanks, guys.
And our next question comes from the line of Paul Grigel from Macquarie. Your line is open.
Maybe following up then on the Eagle Ford and around the CapEx budget, how are the discussions going in terms of potential cadence or changing to activity levels, given the very clear communication you guys’ total CapEx budget that the Eagle Ford could still move around this year into year-end, how should we view that?
Paul, this is Tony. The relationship that we’ve had with BP is working quite well. We picked up a additional rig so we have four rigs currently working there. As we’ve seen over the past two years, three years, the IDs and the rate can be a little bit lumpy, but for the most part, we’ll see a increased rate in the second half of the year associated with one of the larger projects that will come on. Just one thing of note, this relationship is so good with one of the four rigs it’s currently working right now, is being operated by Devon. The technical dialog between the two companies could not be better and I think we’re more closely aligned probably than we had been with the previous partner there. So it’s going really well.
Right. Good to hear. And I guess, turning back to the Permian quickly, given some of the dislocation in natural gas prices around the line of possible Permian hubs, can you guys just remind us how you’re positioned there? Any thoughts that you have on -- clearly revenues, not to focus on them but on actually being able to physically move your gas out of the play.
No, Paul, you’re right. Spot on economic and realization standpoint when you marry the hedges that we have in place, we’re in a great spot there. We’re -- I think our hedges are about $1.45 off of Henry Hub. So as compared to some of the other noise you’ve seen in the basin here over the last several months, we’re getting a really nice realized price there from a flow assurance standpoint. With the scale that we have operationally, the long term contracts that we have, we actually avoid physically blaming at Waha. Our gas goes to EPMG and then with the firm sales that we have with our long-term customers, that gas actually moves to the west. So we have not seen any issues on moving our gas and feel really good about the flow assurance there.
Perfect. Thank you.
Well, we’re now at the top of the hour. We appreciate everyone’s interest in Devon today. And if we didn’t get your question, please do not hesitate to reach out to the Investor Relations team at anytime, which consists of myself and Chris Carr. Have a good day. Thank you.
This does conclude today’s conference call. Thank you for your participation. And you may now disconnect.