Devon Energy Corp (DVN) — Q4 2019 Earnings Call Transcript

Good morning and thank you to everyone for joining us on the call today. Last night, we issued an earnings release and operations report that cover our results for the year and our forward-looking outlook. We will make references to our operations report during the call today to aid the conversation and these slides can be found on our website at devonenergy.com. Also joining me on the call today are, Dave Hager, our President and CEO; Jeff Ritenour, our Chief Financial Officer; David Harris, our Executive Vice President of Exploration and Production; and a few other members of our senior management team. Comments on the call today will contain plans, forecasts, and estimates that are forward-looking statements under U.S. securities law. These comments are subject to assumptions, risks, and uncertainties that could cause actual results to differ from our forward-looking statements. Please take note of the cautionary language and risk factors provided in our SEC filings and earnings materials. With that, I'll turn the call over to Dave.

Thanks, Scott, and good morning everyone. For Devon, 2019 can best be defined as a year of exceptional execution and differentiating performance across every aspect of our business. As you can see on slide 5 of our operations report, a critical accomplishment during the year was our timely and tax-efficient transformation to a U.S. oil business. Even with the challenging market conditions, we successfully completed our portfolio simplification objectives in only 10 months and were able to exit non-core assets at highly accretive valuations. Furthermore, by sharpening our focus on Devon's world-class U.S. oil assets, we delivered a step change improvement in corporate level rates of return, achieved enhanced capital efficiencies, expanded our margins, reduced leverage, and returned industry-leading amounts of capital to shareholders. All in all, it was a great year. But let me be clear, we are just getting started and the investment case for Devon has never been stronger. Looking ahead to 2020, our strategic framework for success and disciplined capital priorities remain unchanged. These priorities are outlined on slide 10 of our operations report. As always, Devon's top priorities will be to fund the maintenance capital requirements of our business and the quarterly dividend. Once these objectives are met, the next step in our capital allocation process is to selectively deploy capital to high-return projects that will efficiently expand the cash flow of our business. Importantly, our 2020 plan meets all of these capital allocation priorities at low breakeven funding levels, even after accounting for the recent weaknesses in gas and NGL strip pricing. Should this volatility drive prices higher, we will remain disciplined, and the benefits of any pricing windfall above our conservative base planning scenario will manifest itself in higher levels of free cash flow for shareholders, not higher capital spending. Conversely, should we see price volatility to the downside, we have designed our operating plan to have the flexibility and agility to reassess the capital program and react to any structural changes in the macro environment. Now, let's run through some of the specifics of our 2020 operating plan, which you can see on slide 11. The key takeaway from this slide is that, due to capital efficiencies, we are lowering the top end of our upstream capital guidance in 2020 by $50 million to a range of $1.7 billion to $1.85 billion. Furthermore, the impact of this investment program in 2020 is expected to be enhanced by a reallocation of capital from the STACK, a liquids-rich combo play to the Delaware, the top oil play in all of North America. This shift in capital allocation will increase spending in the Delaware Basin by approximately 15% year-over-year and Delaware will now account for approximately 60% of total capital investment for the year. Another important distinction of our 2020 program is that the reallocation of capital to the Delaware Basin will be deployed exclusively towards accelerating Wolfcamp development activity. This is significant because our Wolfcamp activity exhibited the most substantial capital efficiency improvement of any opportunity in our portfolio in the back half of 2019. With this increased capital allocation, the Wolfcamp will now account for two-thirds of our Delaware activity, providing a visible capital efficiency tailwind that will accrue to our benefit throughout 2020 and carry forward into 2021 as well. While the 2020 capital program is concentrated in the Delaware Basin, I would be remiss not to mention the exciting catalyst-rich program we have planned for the Powder River Basin. With the appraisal success we achieved in the Niobrara in 2019, we plan to double our activity levels in this emerging resource play over the upcoming year. A key objective of the Niobrara program in 2020 is to derisk and prepare a portion of our 200,000 net acres for full development by early next year. And lastly, with our Eagle Ford and STACK assets, it will be business as usual, with the operating team laser-focused on executing their capital programs efficiently, managing base production, and maximizing free cash flow for the company. Turning your attention to Slide 12. Based on the strong operational momentum of our business, we are raising Devon's per share growth outlook for 2020. Not surprisingly, this improved outlook is underpinned by the outstanding well performance we are experiencing in the Delaware Basin. As a result, we are now increasing the lower end of our oil growth outlook by 50 basis points to a range of 7.5% to 9% compared to 2019. And to reiterate, this higher growth rate is matched with lower capital spending expectations as well. To maximize the value of this production, we have aggressively acted over the past year to materially improve our corporate cost structure. The success of this ongoing initiative is evidenced by Devon's G&A costs projected to be reduced by 25% year-over-year. And lastly, while Jeff will speak to this later in the call, the per share impact of this improved 2020 outlook will be further magnified by our new $1 billion share repurchase program and yesterday's announcement to increase the quarterly dividend by 22%. Moving to Slide 13. While 2020 is setting out to be a great year for Devon, another critical message I want to convey is that the differentiated operating performance achieved in 2019 is sustainable longer term. At Devon, we absolutely have the right personnel, financial strength, and inventory depth to deliver both attractive growth rates and increased amounts of free cash flow in 2021 and beyond. While it is too early to provide official guidance for 2021, our thoughtful and pragmatic approach to the business will remain the same. Our Delaware-centric capital program will remain focused on steady activity levels that deliver the right balance between returns, capital efficiencies, growth rates, and free cash flow. With this disciplined financial framework, we believe investors can directionally expect a mid- to high single-digit oil growth rate in 2021 for a relatively stable amount of capital investment. A noteworthy driver of this preliminary outlook is the positive rate of change we expect to realize from our transition to higher Wolfcamp development activity. Looking beyond the next few years, given the quality of our inventory, I believe a sustainable long-term oil growth rate in the mid-single-digit range feels an appropriate rate to expand our business while generating increasing amounts of free cash flow that can effectively compete with any sector in the market. Slide 14 showcases the free cash flow our business can deliver through 2021. As you can see in the gray box at the top of the slide, Devon's improved operating outlook lowers the breakeven funding level of our operating plan in 2020 and 2021, from our previous disclosure last November. The combination of higher oil growth rate and improved cost structure and a stronger hedge book now allow us to fully fund our capital program at $46.50 WTI and $2 Henry Hub pricing and Mont Belvieu realizations of less than 30% of WTI. While we are pleased with these improvements in breakeven funding, which meaningfully improves our position on the U.S. cost curve, we are not stopping here. To be successful in this unforgiving environment, you must roll up your sleeves, get your hands dirty, and on a daily basis look for ways to reduce costs by controlling the controllables. And at Devon, that is exactly what we're focused on. So, in summary, Devon's multi-basin oil business is built to last. And our disciplined capital plans are designed to deliver compelling amounts of free cash flow and an attractive growth in our per share metrics for the foreseeable future. And with that, I'll turn the call over to Jeff to review our financial strategy and detail how we plan to allocate the excess cash flow from our business.

Thanks, Dave. At Devon, we believe our financial strategy and underlying balance sheet strength are significant competitive advantages. The extreme commodity price volatility we have experienced over the last year is a constant reminder that a strong balance sheet and effective risk management programs are critical to the long-term success of an E&P company. Core to our financial strategy is the emphasis on building a high-margin asset base. Devon's advantaged asset base is very well positioned on North America's marginal cost curve. The high-grading of our asset portfolio over the last several years and the disciplined allocation of capital to our highest return opportunities is working to lower the breakeven pricing for the company. As Dave mentioned in his opening remarks, and as outlined on slide 14, our improved operating outlook has lowered the breakeven funding level of our operating plan in 2020 and 2021 from our previous disclosure last November. This allows us to provide shareholders with free cash flow, even in challenged commodity price environments. To further expand our margin of safety, we are actively deploying proven and progressive risk management and supply chain practices to optimize our financial results. Examples of this include our disciplined hedging program, which uses a combination of systematic and discretionary hedges to effectively mitigate pricing volatility. We have over 40% of our 2020 projected oil production hedged at an average floor of $53 per barrel, well over our funding breakeven pricing of $46.50 per barrel. In addition, our supply chain team has shifted the majority of our contracted services to shorter-term over the last year, allowing us to take advantage of the deflationary environment and providing flexibility should market conditions change and demand adjust to preserve free cash flow. In combination with our high liquidity and low leverage, these prudent risk management and supply chain practices allow us to optimize planning efforts and enhance our capital allocation decisions in periods of uncertainty. Now turning your attention to slide 8 of our operations report, I plan to briefly cover the details of our financial position, where we have built a tremendous amount of flexibility. An important strategic priority over the last year has been the repayment of debt to further strengthen our investment-grade financial position. We made significant progress towards this initiative in 2019, as we retired $1.7 billion of senior notes, which reduced our debt ratio to around 1 times net debt-to-EBITDA on a trailing 12-month basis. Importantly, this deleveraging activity completely cleared Devon's outstanding debt maturity runway until late 2025, extending the weighted average maturity of our debt portfolio to more than 18 years. While our balance sheet is in great shape and we have tremendous flexibility, we're not done making improvements. In the fourth quarter, Devon generated $171 million of free cash flow and we exited the year with $1.8 billion of cash on hand. Furthermore, Devon's cash balances will increase upon closing in mid-April with our $770 million Barnett Shale divestiture. We are keeping a close watch on interest rates and credit spreads as we evaluate the next potential steps in our debt repurchase plan. Current market dynamics have driven redemption premiums substantially higher, but we are prepared to be patient and opportunistic to repurchase additional debt should the market move to our benefit. Pivoting your attention to the left-hand side of slide 9, another top financial priority for Devon is returning capital to shareholders in the form of an increasing dividend. Overall, from a dividend policy perspective, we are targeting a payout ratio of 5% to 10% of operating cash flow at our base planning scenario of $50 WTI pricing. Additionally, we believe consistent and sustainable growth in our dividend provides for a very attractive and competitive result when compared to our E&P peers and other large-cap companies across the broader S&P 500. Our $46.50 per barrel breakeven underpins this policy and supports growth in the dividend over time. Given the strength of our projected 2020 financial outlook and reduced breakeven, we were pleased to announce last night that our Board has approved a 22% increase in Devon's quarterly dividend. This shareholder-friendly action is consistent with our target payout ratios and is aligned with our commitment to steadily grow the dividend over time to a level that is highly competitive with other sectors in the market. In addition to our dividend, we are also returning cash to shareholders through Devon's industry-leading share repurchase program. Since our program began in 2018, we've repurchased 147 million shares at a total cost of $4.8 billion. Our Board of Directors authorized a new $1 billion program last December, paving the way for additional repurchases in 2020 and a total reduction in Devon's outstanding share count of approximately 35% by year-end. This is not only the most active program in the E&P space, but it also outpaces the activity of any company regardless of sector in the S&P 500. We have been aggressively buying our shares over the last year at levels ranging from $20 to $25 per share. Given our view of the attractive valuation of our shares compared to the intrinsic value of the company, you can expect more of the same from us in 2020. In summary, the disciplined financial model we are using to operate the company is working and checks all the boxes necessary for long-term success. We have a strong financial position with a low breakeven funding level and our business can generate excess cash flow in any commodity price environment. We have excellent liquidity and a strong balance sheet with very low leverage ratios, and we're rewarding our shareholders with a return of cash through our dividend and share repurchase program. With that, I'll turn the call over to David Harris to cover our operating performance and outlook.

Thanks, Jeff. The fourth quarter was another strong one operationally for Devon that can best be described by oil production once again exceeding guidance and capital spending coming in 6% below forecast. This trend of operational excellence has now been established over multiple quarters and is a testament to the high level of performance of each of our asset teams in effectively fulfilling their respective roles in our business. For my prepared comments today, I plan to cover the asset-specific highlights that are driving this positive business momentum and provide some insights and observations regarding our outlook for 2020. As you can see on slide 16 of the operations report, our world-class Delaware Basin asset is the capital-efficient growth engine driving Devon's operational outperformance. In the fourth quarter, net production from the Delaware continued to increase rapidly, growing 82% on a year-over-year basis. This strong growth was driven by 36 high-impact wells brought online in the quarter that were diversified across all five core areas in the Wolfcamp, Bone Spring, and Leonard formations. These strong wells achieved average 30-day rates of 2,800 BOEs per day, of which 70% was oil at an average cost of around $7.5 million per well. The overall returns from our fourth-quarter program in the Delaware Basin were simply outstanding. Looking specifically at the project level detail for the quarter, our much-anticipated Cat Scratch 2.0 project did not disappoint. This 10-well project which developed a second Bone Spring sweet spot exceeded our pre-drill expectations by reaching average 30-day rates of 3,000 BOEs per well or 425 BOEs per 1,000 feet of lateral. While the Cat Scratch results were certainly impressive, I believe the top thematic takeaway for the fourth-quarter activity is the operational momentum we are establishing with our Wolfcamp program. As you can see on the map at the right side of slide 16, we brought online three impactful Wolfcamp projects during the quarter to help further validate the commerciality of multiple Wolfcamp landing zones across the basin of Southeast New Mexico. Of particular note was our highly successful seven-well Spud Muffin project in the Potato Basin area in Eddy County, in which we co-developed the third Bone Spring and Upper Wolfcamp intervals. While the industry has been active for some time in the Potato Basin area, the Spud Muffin project was our initial operated test in this area. Given the well productivity we experienced, this will be an area that definitely works its way into the Delaware Basin capital allocation mix going forward, which further deepens our resource-rich opportunity set in this franchise asset. As Dave touched on in his opening remarks, the setup of the Delaware Basin in 2020 is exciting. Our diversified development programs across our five core areas position us for another year of exceptionally strong oil growth. In total, we expect to invest around $1 billion of capital in the Delaware that will result in approximately 130 operated spuds. Of this activity, we are allocating nearly 65% to the Wolfcamp formation, which essentially represents a doubling of Wolfcamp activity year-over-year. To reiterate comments from earlier in the call, this shift in Delaware capital allocation to the Wolfcamp is impactful given the substantial capital efficiency improvements we've achieved in the second half of 2019. In fact, in the most recent quarter, our drilled and completed feet-per-day metrics in the Wolfcamp improved 48% and 62% year-over-year, respectively. These steadily improving cycle times and costs provide a capital efficiency tailwind heading into 2020. The next asset I would like to discuss is the Powder River Basin, an important emerging oil growth opportunity in our portfolio. In the fourth quarter, our development-focused program commenced production on 19 new wells that drove net production more than 50% higher year-over-year. Importantly, this oil-weighted production growth was accompanied by a step change improvement in capital efficiency. Specifically looking at the Turner formation, which was our top development target in 2019, the team did a fantastic job of substantially reducing cycle times and recognizing savings of more than $1 million per well as well costs pushed towards $6 million per well by year-end. As I look ahead to the upcoming year, our highest priority in the Powder River Basin is the delineation of our Niobrara potential. Our Niobrara position consisting of 200,000 net acres in the core of the play's chalk window has repeatable resource play characteristics and the potential to be an important growth driver for Devon longer term. Over the past two years, results from our Niobrara appraisal work have confirmed this potential with 11 operated wells now online and the average 30-day rates from these oil-prone wells reaching as high as 1,500 BOEs per day. Further progressing the team's confidence, our initial spacing test brought online in the second half of 2019 suggests the commercial potential for at least three to four wells per section. These tests have also confirmed our ability to develop the Niobrara independent of the deeper Turner interval. Based on positive operating results obtained to date, we are doubling our Niobrara activity in 2020 to approximately 15 wells. With this increased capital allocation, we are methodically focusing our delineation efforts in the Southwest quadrant of our acreage, which we call Atlas West and has delivered some of the highest oil rates in the basin. With additional success, we believe it's possible to ready a portion of our Atlas West acreage for full-field development in 2021. And finally, our Eagle Ford and STACK assets are successfully fulfilling their strategically important roles in our portfolio, providing nearly $600 million of free cash flow over the past year. Specifically in the Eagle Ford, the key message I want to convey is that we have reestablished operational momentum in the play with our new partner, exiting the year producing around 53,000 BOEs per day. Our fourth-quarter operations were impacted by a well control event related to surface equipment. This situation has been resolved, but it did result in estimated downtime of 9,000 BOEs per day in the quarter and remediation costs in the quarter of approximately $7 million. Looking ahead to 2020, we expect to maintain strong operational continuity in the Eagle Ford running an average of three to four rig lines through most of the year. This disciplined and capital-efficient plan is expected to deliver a modest increase in our production volumes on a year-over-year basis while staying true to the role of generating significant amounts of free cash flow. Lastly, in the STACK, we are excited about our recently announced Dow joint venture. With the Dow deal, we have monetized half of our working interest in 133 undrilled locations in exchange for a $100 million drilling carry over the next four years. This innovative agreement will help us bring forward value in the STACK while delivering carry-enhanced returns that compete effectively for capital within our portfolio. In addition to the benefits of a drilling carry, our returns are also expected to be enhanced by lower well costs from focused infill drilling and from midstream incentive rates that substantially improve per unit operating costs for each new well brought online. Initial activity from the Dow joint venture will begin in the second quarter of 2020 with a two-rig program developing the 18-well Jacobs Row in Northern Canadian County. First production from the Jacobs Row is forecast to occur in early 2021. While we will continue to look for smart ways to enhance the value of our STACK position, we are quite pleased with the initial step we have taken with Dow. That concludes my prepared remarks. And I would like to turn the call back over to Scott.

Thanks, David. We'll now open the call to Q&A. Please limit yourself to one question and a follow-up. This allows us to get to more of your questions on the call today. With that operator, we'll take our first question.

Yeah. Good morning. Dave, the 2020 capital allocation obviously 60% going to the Delaware, 20% to Powder, 17% to the Eagle Ford, and 3% in the STACK. And the STACK CapEx is down from call it a 16% mix last year. How comfortable are you with the complementary assets in the portfolio to the Delaware? And how are you thinking about inorganic opportunities as we did see a favorable reaction to the WPX Felix transaction, which was announced a few weeks ago?

Sure, Arun. Yeah, first off, we are very comfortable with the capital allocation we have and frankly the shift of capital from the STACK to the Delaware is the primary reason that you're going to see the growth that we have described in 2021 in general terms, why that is sustainable over a longer period of time, because if you think about it conceptually it takes nine to 12 months for first production to come from capital. And so really for the most part the capital that we're spending in 2020, where we've shifted some of that capital to the Delaware is being reflected in 2021 production results, which is driving that oil growth rate. And that is sustainable for many, many years with the deep inventory of opportunities that we have in the Delaware Basin. So that's fundamentally why we're going to see the kind of growth rates that we're describing here for a long time. Now given that, we are comfortable and we are driving higher capital efficiencies internally, we're driving higher levels of cash flow and focused on returning that value to shareholders through increased capital efficiencies and the higher cash flow that we're generating, we have no need to do an acquisition. Now are we looking at opportunities? Absolutely. We are in the deal flow. We're always going to be in a deal flow. We think that's part of our job. But we are going to be incredibly disciplined around any decision regarding that because of the strength of our internal portfolio that we have and the confidence that we have that we're going to be able to continue to drive higher cash flow through the oil growth and increased capital efficiencies.

Great. And I had one operating question. I know there's been a lot of excitement around the Cat Scratch area Todd. We did want to see if you could maybe elaborate on the initial delineation success in the Potato Basin. I think your pad is just south of Oxy's height and length 14-well program. So I was wondering if you could talk about some of the implications of these delineation results and perhaps capital allocation on a go-forward basis in this fifth part of your Delaware Basin portfolio.

Arun, this is David Harris. Thanks for the question. Yeah, we're really excited about the Potato Basin areas. I mentioned in my prepared remarks, this is an area where some other companies including Oxy as you mentioned have been active for a little while. Spud Muffin is our first operated test. We brought seven wells online there and they far exceeded our expectations for that area. We think we're going to see increasing activity out there not just from an industry perspective, but you'll increasingly see it compete for capital within our portfolio. I think if you look in the operations report at kind of how we've allocated capital throughout the year, it's going to be roughly about 20% of our capital or so going forward. And so it's one of the things that we like about the Delaware position that we have in the five core areas. We're diversified across the basin of Southeast New Mexico and think that that will continue to be an exciting area for us going forward.

Thanks. Good morning, everyone. I’d like to follow up on Arun's question regarding the Delaware inventory. Dave, we haven't heard you discuss inventory depth in quite some time, particularly not in terms of numbers in your presentations. Could you provide us with an update on how the risk development inventory appears, especially in the Delaware? Additionally, I would like to bring up a second part to that question. We haven’t heard much discussion about interference or parent-child issues for about a year. I want to ensure that you are comfortable with the spacing you’re implementing in the Delaware at this time.

Thank you, Doug. We have the inventory slide in our corporate presentation, but there is no significant news to report. We focused on other information in the operations report. David Harris can provide more detail, but we have a substantial inventory in the Delaware Basin that will attract capital for many years and will support the company’s growth. We are mindful of factors like spacing and parent-child relationships in this context. You may notice that the number of locations could change in the future as we continuously update our assessments; this is due to our shift towards longer laterals, which may require fewer wells to access the same resource. This aligns with our drive for capital efficiency as a company. However, I don't anticipate any significant changes to the resource itself. David, do you have anything to add?

Certainly. In addition to what Dave mentioned, I want to highlight our capital efficiency. Last year, we identified approximately 2,000 wells in our risked Delaware inventory and plan to start about 130 new wells this year, providing roughly 15 years of inventory. As Dave pointed out, we have an extensive runway of high-quality projects ahead. A key factor that hasn't been fully accounted for yet is the improvement in the quality of our inventory due to capital efficiency. We are significantly reducing costs and cycle times, which should continue going forward. Enhancing well productivity will undoubtedly have a positive impact as we advance the development of our resource base.

Thank you for the answers, everyone. I'd like to ask a question for Jeff, if I could. It contains a bit of a Delaware-related topic. Jeff, you mentioned the 5% to 10% payout ratio for dividends. Could you elaborate on what you consider to be the right balance of cash returns? The long-term growth figure in the mid-single digits seems to be a new target. Is that the result of your planning process? How do you integrate all these elements together? I'll stop there. Thank you.

I would say it's more about managing output. We have maintained a balance among various targets and metrics related to growth, payout ratios, and dividends. The foundation of that is reducing our breakeven funding level. You may have heard us mention the $46.50 target for 2021, and we're actively working to lower that figure. This reduction is essential to our financial strategy as we incorporate high-margin assets into the portfolio, particularly in Delaware. When considering our competitiveness not only in our sector but also in the broader S&P 500, we assess what free cash flow yield appears competitive, which we believe falls within the 5% to 10% range. We align that with our dividend expectations, ensuring our offering is competitive in both the E&P sector and among the broader S&P 500. By integrating these factors, we envision a strong strategy focused on both growth and free cash flow metrics.

So Jeff to be clear you're tapping the spending or are you targeting a growth rate?

Yes. It's really a returns-based focus. So we start from the ground up in building our game plan and portfolio, and we allocate as much capital as we can to the highest-return products, and everything else just falls out of that.

All right. Thanks so much, guys.

Hi, good morning, everyone.

Good morning.

My first question is on the updated corporate breakeven. So your two-year now is averaging $46.50 WTI and $2 Henry Hub. Can you just talk about how the breakeven in 2021 compares to 2020? And any changes you have to the assumptions that are embedded into that? I guess kind of what we're getting at is that the 2020 breakeven benefited from momentum in 2019 and hedges and that's true for a lot of E&Ps right now, but there's also some offsets as well for you guys too. But the average $46.50 over two years seems to imply an improvement in 2021. So just any color that you would have on that would be great beyond just the timing of the Wolfcamp activity?

Yes. Jeanine, you're spot on. That's exactly right. It does imply improved breakeven in 2021 versus 2020. You're right. We took the benefit of the hedges that we have in place as it relates to 2020, but I'll point you back to some comments Dave made earlier, which is a function of our capital program. The capital that we're spending and the allocation to the Delaware and specifically the Wolfcamp in 2020 is what's really driving that improved capital efficiency in 2021. It's just increasing our ability to lower that breakeven in future years.

Okay. And then my second question is on dividend coverage. We've seen a lot of increases so far this earnings season. And when Devon thinks about dividend growth and the risk/reward associated with that, on what WTI price are you comfortable with in terms of dividend coverage on an unhedged basis?

Yes. We – Jeanine, as we said in our prepared remarks and I think we've talked about in the past, we've tried to build the business around a $50 oil and kind of $2 gas price. So that's where we start with our base business plan and then evaluate obviously the different market dynamics as we go through each year with our Board to determine where the dividend ultimately lands. But as we discussed in my prepared remarks, what underlies our policy, our dividend policy is that 5% to 10% payout ratio, which we think is very competitive with the peer group and the broader S&P 500.

Okay. Great. Thank you for taking my questions.

Hi, good morning.

Good morning, Paul.

Two questions. Hi, Dave. Dave, can you maybe share if there's any information about the Atlas West data you moved into the full development? What kind of resource potential number of prospect inventory that kind of information that maybe we – you can share with us?

Paul, this is David Harris. If I understood the question correctly, you were asking about resource potential and potential inventory in our Atlas West area, is that correct?

That's correct that you were talking about if the 2020 delineation to be successful as expected, then you will move into development in 2021. So I mean, how big is this development plan? Or that is the area that we are talking about?

Yes. So when we talk about Atlas West and Atlas East, it's our entire 200,000 acres in the northern part of Converse County. So as a reminder that doesn't include any of our acreage up in Campbell, where other operators have been active in the Niobrara. As we think about that position, it's probably early before we move into development to really give you specific resource sort of numbers. But if you just did some pretty simple math at kind of the three-well spacing, which we think is kind of the bottom end of where we'd be that likely points you to something in the neighborhood of about 500 locations.

Okay. Great.

And…

Yeah, I’m sorry.

I just wanted to clarify that those would be two-mile locations.

Right. And then, that's including both Atlas West and Atlas East or just Atlas West?

Both.

Okay. The second question is that in the event when you guys just looking at any inorganic opportunity, what financial and operating metrics would be used in the valuation? And what type of minimum metrics would you need before you would even consider? So we're trying to understand the process there. How does that work?

The most important thing to consider here, in response to Doug's question, is that we have a solid internal game plan. Therefore, we do not feel the need to pursue any inorganic activities at this time. Although we are currently in discussions regarding several recent deals, including the Felix transaction, we will remain very disciplined. When considering any M&A activity, our criteria include ensuring that it is accretive to our financial metrics on a per-share basis. It must also align strategically with our asset portfolio, allowing us to realize synergies beyond the current execution methods, such as general and administrative synergies, lease operation efficiencies, or capital efficiency. Additionally, it must compete for capital allocation within our portfolio. Margin expansion is another key consideration; we are always looking for ways to improve our overall margins and reduce costs across the combined entities. We will remain very disciplined in this process, as we believe we have a strong strategy, a solid asset base, and the right team to move forward with these opportunities. If we find opportunities that match these criteria, great. If not, we are still very confident in our current strategy.

Thank you.

Good morning.

Good morning, Matt.

My first question relates to STACK capital allocation. Just given the depressed natural gas and NGL environment at the moment, could you provide some color on how you're thinking about rates of return in the STACK JV at strip? And is there a price at which you might consider delaying development until you see an improvement in the forward curve, while pulling forward more free cash flow generation in 2020?

Matt, this is David Harris. Yeah. In terms of STACK activity with Dow, as we've highlighted the first phase of the work that we're going to do with them is in the Jacobs Row, which is a Woodford Row development similar to some of the ones that we've done before. These are very predictable projects, and we're going to be looking at starting that project in the second quarter likely in the May timeframe, which just given the size of the project likely means that the production isn't coming on until the first part of 2021. As we've modeled that, even at the strip today where we currently sit that initial project in the Jacobs Row represents a fully burdened rate of return of about 20%. So, given the predictability of that project, we feel good about that project internally. With respect to competing for capital obviously we have a partner. We want to stay aligned with them, so we'll continue to be mindful of the commodity price environment as we go forward and have the right kind of dialogue that you would expect as we think about forward decisions around the program.

Great. And then just a follow-up question on capital allocation. The PRB is still receiving a large portion of the development capital and looking back over the last two years on a capital efficiency basis, definitely appears that it's lagging the Delaware to some degree, but you're progressing a couple of different initiatives especially on appraisal. Just curious as you guys think about the 2020 program for the PRB, are there some indicators on the horizon that might show a step change in capital efficiency metrics this year as it relates to that asset? And then over time, if you don't see a material change in capital efficiency, is there the potential to reallocate more capital to the Delaware Basin?

Yes. This is David again. Yes. I think the punchline answer to your question from a capital efficiency perspective you've already kind of hit on just in terms of the little earlier stage, nature of the assets, some of the appraisal work we're doing. So clearly we've got some science and data acquisition capital there as we're seeking to best understand the resource and how to move it into full-field development. I think throughout 2020 and into 2021, particularly with the Niobrara as we move into more of a development mode, we think you'll see a step change in that capital efficiency as we start to mature that asset.

You've observed the changes in the Wolfcamp, which illustrate how much we have been able to reduce drilling and completion costs as we transition into full development mode. However, we haven't begun this process in the Niobrara yet, and currently, we're still focused on appraisal. While I can't guarantee that the numbers will be exactly the same, I can share that our teams have set ambitious internal cost reduction targets. Once we enter full development mode with strong confidence, we will be able to achieve those goals. For now, as David mentioned, our priority is on appraisal and understanding the resource. Things can shift rapidly once we move into development.

Thank you.

Good morning and thanks for taking my questions. Maybe a follow-up on that one. So if you do move Atlas West and the PRB towards development in 2021, I'm curious broad-strokes that your flattish total 2021 CapEx level isn't how that may shift based on capital level allocation from elsewhere in 2021?

Probably not a significant shift. We'd just be able to do more activity much more efficiently, but not a significant overall shift in the capital allocation.

Okay. And then I had a question on your outlook to 2021. I was curious what service cost environment is currently contemplated in your updated 2020 CapEx guidance versus perhaps what pricing you saw in 4Q 2019, and then what if any deltas you're assuming on pricing or further efficiencies in the 2021 CapEx commentary?

Yes, this is Jeff. We have incorporated some efficiencies from the latter half of 2019 into our program. However, when it comes to service cost inflation or deflation, we have kept that flat. We have noticed some deflation in certain services, which could potentially benefit us in 2020. Overall, we expect that to remain consistent for the year.

And is that flat from...

And Brian just let me add a few other tidbits. You were asking about other nuances that may impact the modeling of that. One thing you have to be mindful of is what the differentials we just carried forward kind of the current state that we're seeing right now into 2021. Where there could be upside on that is obviously is the Permian highway or Whistler comes online, you could potentially see some substantially improved realizations, but we did not build that in. One other item you want to notice, we expect our G&A cost to continue to gravitate towards that $350 million target. So that would be another improvement you should account for when you're trying to calibrate to our estimates. Sorry. I didn't mean to cut you off there, but I'll let you ask your next question.

Yes. No problem. Just to clarify on the flat service price comment. Is that flat from 4Q, flat from 2019 levels? Just want to make sure I'm clear on what the baseline is there.

Flat from full year.

Okay. Perfect. Appreciate it. Thanks.

Good morning all. Dave, my first question is for you or Jeff around your financing. Specifically, the recent drilling partnership with Dow, is this something that we could see in additional areas in the STACK or potentially other plays?

We have a solid partnership with Dow, which began in the Barnett through a similar agreement. This current deal is a bit larger, and we believe it will be successful. There may also be opportunities with Dow in other areas. Additionally, we are exploring some chances related to OBO capital that may not meet our return expectations. Instead of opting out of those wells, we are considering bringing in a partner to help execute a program tied to them. This is another type of deal we are currently pursuing, and while I'm not discussing Dow in this context, it could involve other partners in the future.

Interesting. Okay. And then, my follow-up, my second question is on your shareholder return. You all have been aggressive in the last several months with stock repurchases. And I'm just wondering, would you all share some details on how you all think about capital allocation between these repurchases and the growth of dividends. And more specifically, I was just wondering about if you would continue to aggressively repurchase this much stock. Do you base it on what your yields or growth levels are? Just wondering how you sort of balance those things. Thank you.

I want to begin by stating our intention to implement a dividend, and Jeff has mentioned that we are considering a range of 5% to 10% of cash from operations. Our goal is to establish a dividend that is not only sustainable but can also grow over time, so we are taking a measured approach. Currently, our yield is about 2% based on our trading position. However, we believe this is sustainable and has the potential for growth. Jeff will provide details on our financials, including the cash we currently have and the cash we expect to generate, which supports our confidence in being aggressive in this area. We have already optimized our capital program based on expected returns, capital efficiency, appropriate growth rates, and the free cash flow we anticipate generating. Essentially, we have confirmed our strategy. Looking at our free cash flow and the cash available within the company, we are confident in our position. Jeff will elaborate on our financial details, and we believe we are significantly undervalued, presenting a compelling investment opportunity.

Yes. So Dave, you summed it up well. The only thing I would add is some specifics around the cash balances. We talked about this a little bit in the opening remarks, but we have about $1.8 billion of cash at year-end. We'll add to that with the Barnett divestiture, the $770 million roughly. And so, as Dave articulated, we feel like we can accomplish our financial objectives both on the debt repurchase and with $1 billion share repurchase program that our Board has approved for this year. So, we feel really good about our ability to continue returning cash to shareholders via the dividend and the share repurchase this year.

Hey, good morning. Just looking at slide 16, do you have the oil mix breakdown between the Wolfcamp and the Bone Springs? And was the Spud Muffin mix different than other pads?

Could you provide more detail about the oil mix? Specifically, are you interested in the quarter or just the projects we launched during the quarter?

Yes, the projects that you brought on for the quarter in slide 16 the overall oil rate.

Okay. Yes. For the 30-day rates we achieved in the quarter, about 70% of the projects were oil. Some are slightly above that and some are slightly below, but that's a good way to think about it.

And do you have the mix between the Wolfcamp and the Bone Springs just thinking about as the program goes more towards the Wolfcamp next year?

Just reviewing the numbers, they appear to be roughly the same, hovering around that 70% mark. There will be a significant difference in the 30-day rate or on an EUR basis between the Wolfcamp and the Bone Spring.

This is David Harris. They're about $6 million plus or minus.