Devon Energy Corp (DVN) — Q3 2020 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 presentation that cover our results for the third quarter and updated outlook for the remainder of the year. Throughout the call today, we will make references to our earnings presentation to support our prepared remarks, 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; David Harris, our Executive Vice President of Exploration and Production; Jeff Ritenour, our Chief Financial Officer; and a few other members of our senior management team. Comments on the call today will include 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 the risk factors provided in our SEC filings and earnings materials. With that, I’ll turn the call over to Dave.

Thank you, Scott, and good morning. We appreciate everyone taking the time to join us on the call today and for your interest in Devon. For the purpose of today’s call, my comments will be centered on three key points: our outstanding third-quarter results, our improved outlook for the remainder of the year, and the benefits of our recently announced merger with WPX. On Slide 7 of our earnings presentation, I’ll begin my prepared remarks by covering a few key highlights from our outstanding third-quarter results. Across the portfolio, our teams are responding to a challenging operating environment by delivering results that continue to exceed production and capital efficiency targets, while successfully driving down per-unit operating costs and maximizing margins. This is evidenced by several noteworthy accomplishments in the quarter, including oil production exceeding midpoint guidance by 6,000 barrels per day, complemented with capital spending that was once again below forecast. Furthermore, we continue to expand margins through improvements in our cost structure, headlined by operating expenses of 8% below guidance and G&A costs reduced by 30% year-over-year. With this strong operational performance, we generated $223 million of free cash flow in the quarter. And just after quarter-end, with the closing of the Barnett transaction, we paid out a $100 million special dividend. All in all, the third quarter was excellent, both operationally and financially, as we executed at a very high level on every single strategic objective that underpins our business model. This strong performance is a testament to the hard work and dedication of our team, and I want to thank our employees for their continued commitment to excellence. Moving to Slide 11. With the strong results our business has delivered to date, we’re now raising our outlook for the remainder of 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 our full-year oil guidance for the second consecutive quarter. Looking specifically at the upcoming quarter, we now expect our oil production to average 148,000 to 153,000 barrels per day, a 7,000 barrels per day improvement versus prior guidance expectations. Importantly, we’re delivering this incremental production with $30 million less capital compared to the revised budget we issued earlier this year. We also continue to act with a sense of urgency to materially improve our cash cost structure to get the most out of every barrel we produce. With this intense focus, we are on track to reduce LOE and GP&T costs by approximately $0.50 per unit or 6% compared to our previous expectations. To achieve this step level improvement and field-level costs, we have meaningfully reduced our recurring LOE expense across several categories, including chemical and disposal costs, compression, and contract labor. We have also taken steps to streamline our organization’s corporate cost structure. This is clearly demonstrated by our G&A expense trajectory improving by around $35 million compared to the revised budget. We expect to achieve a $250 million G&A run rate target by year-end. Turning briefly to Slide 13. The positive impact from higher volumes, better capital efficiency, and strong cost discipline has resulted in increasing amounts of free cash flow in 2020. Including the proceeds of the Barnett Shale divestiture that closed on October 1, we are on pace to generate around $900 million of free cash flow this year. This is a tremendous accomplishment given the incredibly challenging conditions we have faced. Importantly, with this excess cash flow, we have rewarded shareholders with higher dividend payments. Turning your attention back to Slide 3 of our presentation, I’d like to cover the strategic rationale underpinning our recently announced merger with WPX. This groundbreaking transaction announced on September 28 represents the first true merger of equals within the E&P space in nearly two decades. This strategic combination of Devon and WPX is transformational, as we unite our complementary assets to create a leading unconventional oil producer in the U.S. with an asset base underpinned by a premium position in the economic core of the Delaware Basin. By bringing together our respective companies, shareholders will benefit from enhanced scale, immediate cost synergies, higher free cash flow, and the financial strength to accelerate the return of cash to shareholders through an industry-first fixed plus variable dividend strategy. Additionally, the low premium stock-for-stock combination underscores our confidence that this transaction will allow shareholders of both companies to benefit from synergy realization and the powerful upside potential associated with our financially driven business model. The path to completing this merger is progressing well. We received HSR clearance last week, S-4 proxy will be filed within the next few days, and both companies plan to hold shareholder votes around year-end to finalize the merger. Integration plans are also underway, led by a transition team comprised of senior leaders from each company. In addition to ensuring a seamless transition, the team is also tasked with capitalizing on the synergies and operational efficiencies that contribute to the significant upside of the combined company. Moving to Slide 4. The value of our merger with WPX lies not only in the power of our enhanced scale and strong financial position but also in how we will manage our company in the future. As I have mentioned many times in the past, with a commodity business such as ours, any successful strategy must be grounded in supply and demand fundamentals. We understand the maturing demand dynamics for our industry and recognize that the traditional E&P growth model of the past is not a viable strategy going forward. To succeed in the next phase of the energy cycle, a successful company must deploy a financially driven business model that prioritizes cash returns directly to shareholders. Devon is an industry leader in its cash return movement, and with this highly disciplined strategy, we’re absolutely committed to limiting top-line growth aspirations to 5% or less in times of favorable conditions, pursuing margin expansion through operational scale and leaner corporate structure, moderating investment rates to 70% to 80% of operating cash flow, maintaining extremely low levels of leverage to establish a greater margin of safety, and returning more cash directly to shareholders through quarterly and variable dividends. I believe these shareholder-friendly initiatives that underpin our cash return business model will transform Devon from a highly efficient oil and gas operator to a prominent and consistent builder of economic value through the cycle. With the extreme price volatility we have recently experienced, I want to provide a few preliminary thoughts on 2021. While it is a bit too early to provide any formal guidance, I want to be clear that our top priorities are to protect our financial strength, aggressively reduce costs, and protect our productive capacity. We believe we can accomplish all these objectives in the current operating environment. In fact, with our strong hedging position and pro forma cost structure, we can fund our maintenance capital program at an ultra-low breakeven level of $33 WTI pricing, if not lower, with the leading-edge results we are achieving in the Delaware. We will provide more formalized guidance for 2021 upon completion of the merger with WPX, but we will remain mindful of commodity prices, nimble with our capital plans, and we will invest responsibly to protect shareholder value during this time of uncertainty. Finally, on Slide 5, another critically important component of Devon’s business model is our commitment to delivering top-tier ESG performance. Doing business the right way has always been a focal point for Devon and predates the growing focus on ESG that has taken off in recent years. We believe strong performance in the ESG space is essential and impacts every aspect of our business operationally and financially. As with all other aspects of our business, our focus is to control what we can control while providing energy the world needs. We take pride in fulfilling this need in a reliable and responsible manner. As such, our top environmental priorities include eliminating routine flaring, reducing emissions, and advancing water recycling. In addition to these environmental objectives, we strive to cultivate an inclusive and diverse workplace where broad experiences and fresh perspectives can sharpen our competitive edge. From a governance perspective, we are proud of the combined company, where we’ll have a strong, diverse, and independent board committed to responsible operations to advance the best interests of all stakeholders. The bottom line is we are committed to these principles, which is underscored by the inclusion of ESG performance as a key measure in our compensation structure. In summary, I want to emphasize that as a go-forward Devon has all the necessary attributes to successfully navigate and flourish in today’s environment and create value for many years to come. Our shareholder-friendly strategy is designed to yield attractive returns and free cash flow yields that will compete with any sector in the market. The combination of our top-tier asset portfolio, proven leadership team, and disciplined business model offers a unique investment proposition in the E&P space. And with that, I’m going to turn the call over to David Harris to cover a few of our operational highlights from the quarter.

Good morning, everyone. As Dave touched on, Devon’s operations are hitting on all cylinders as we have repeatedly delivered best-in-class results over the past several quarters. Turning your attention to Slide 8 of our earnings presentation, our world-class Delaware basin asset is the capital-efficient growth engine driving Devon’s operational outperformance in the third quarter. With our capital activity almost exclusively focused in the Delaware, our high margin production continued to rapidly advance, growing 22% on a year-over-year basis. During the third quarter, our operated activity consisted of nine drilling rigs and three dedicated frac crews resulting in 32 new wells commencing first production. With most of these completions weighted towards the back half of the quarter, only 14 of these new wells meaningfully impacted production totals in the third quarter by attaining peak production rates. Overall, initial 30-day production rates from these 14 wells average an impressive 3,900 BOE per day, of which greater than 65% was oil. Those wells collectively rank among the very best results we have delivered to date in this world-class basin. While we had great results across our Delaware basin acreage position in the quarter, new well activity was highlighted by the record-setting well productivity from our Cobra project in Lea County. This two well, three-mile lateral development targeting the XY sands in the upper Wolfcamp achieved average 30-day rates of approximately 7,300 BOE per day, or 475 BOE per 1000 feet of lateral. These wells drilled in the deepest part of the basin are the longest wells drilled in the history of the Delaware by measured depth and are the highest rate Wolfcamp wells we have brought online to date at Devon. Importantly, the capital cost for the Cobra project came in nearly 20% below our pre-drill expectations. Our results at Cobra are another example of the industry-leading performance we have consistently achieved in the Delaware over the past few years. This performance reflects the quality of our acreage and our technical understanding of the subsurface that allows us to identify the best landing zones. Furthermore, with the experience of drilling hundreds of horizontal wells in the basin, our results are aided by understanding parent-child dynamics, appropriate well spacing per development, and customized completion designs to optimize results. I am confident we can continue to deliver this differentiated well productivity in the Delaware going forward. Our large contiguous stack pay position in the economic core of the play provides us a multi-decade inventory opportunity. We have a deep inventory of approved federal drilling permits in hand covering all of our desired activity over the next presidential term. Turning your attention to the left-hand side of Slide 9, in addition to strong well productivity, another key highlight for the quarter is the substantially improved drilling and completion cost results we’ve achieved in the Delaware basin. This is evidenced by our drilled and completed costs reaching $560 per lateral foot in the third quarter, a 40% improvement compared to 2018. These results are absolutely best-in-class among our peers. The key drivers of this performance are the continual optimization of drilling and completion designs, along with repetition gains from drilling two-mile Wolfcamp wells and non-productive time improvements across all phases of the value chain. These are truly special results, and I would like to congratulate our operating team for this outstanding accomplishment. However, we are never done improving, and based on leading-edge results, we expect our steadily improving cycle times and costs to provide a capital efficiency tailwind into 2021. Shifting your attention to the right-hand portion of the slide, we have also done a lot of good work to expand our margins by lowering per unit operating costs by 26% since 2018. One of the most meaningful sources of cost improvement is the scalable infrastructure we have proactively built out. We have nearly all of our oil and produced water connected to pipes to avoid the higher expense of trucking, and this is also a major positive from a safety and an environmental perspective. Looking specifically at our water infrastructure, we are fully integrated with nine water recycling facilities, 40 operated saltwater disposal wells, and connections to several third-party water systems. This operating scale and flexibility allows us to source more than 90% of our operational water needs from either recycled or brackish water at costs that are well below market rates. This strategic infrastructure provides the advantage of avoiding the extremely high expense of trucking in the remote desert of Southeast New Mexico, which can easily exceed a couple of dollars per barrel. Other important factors contributing to our cost improvement in the Delaware are the use of leading-edge data analytics that have reduced controllable downtime in the field by 12% year-over-year, as well as supply chain initiatives that leverage our purchasing power to secure services at advantageous rates. The bottom line is that the hard work and thoughtful planning from our operations team and supply chain personnel positions us to capture additional savings that many of our competitors cannot. And with that, I’ll turn the call over to Jeff Ritenour for a brief financial review.

Thanks, David. My comments today will be focused on a brief review of our financial results for the quarter and the next steps in the execution of our financial strategy. A good place to start today is by reviewing our financial performance in the quarter, where Devon’s earnings and cash flow per share comfortably exceeded consensus estimates. Operating cash flow for the third quarter totaled $427 million, a rebound of nearly 200% compared to last quarter. This level of cash flow fully funded our capital spending requirements and generated $223 million cash flow in the quarter. At the end of September, Devon had $4.9 billion of liquidity, consisting of $1.9 billion of cash on hand, and $3 billion of undrawn capacity on our unsecured credit facility. Subsequent to quarter-end on October 1, our liquidity was further bolstered by the closing of our Barnett Shale divestiture. For those not familiar with the transaction, we agreed to sell our Barnett Shale assets for up to $830 million of total proceeds, consisting of $570 million in cash and contingent payments of up to $260 million. After adjusting for purchase price adjustments, which includes a $170 million deposit we received in April and accrued cash flow from the effective date, we received a net cash payment at closing of $320 million. In conjunction with the closing of this transaction, we returned a portion of the proceeds to shareholders by way of a $100 million special dividend. This special dividend was paid on October 1 in the amount of $0.26 per share. With the excess cash inflows our business is on track to generate in 2020, we expect our cash balances to exceed $2 billion by year-end. The top priority for the large amount of cash we have accumulated is the repayment of up to $1.5 billion of outstanding debt between Devon and WPX. This debt reduction plan will provide a nice uplift to the go-forward company’s cash flow, resulting in interest savings of approximately $75 million on an annual run rate basis. We expect to execute our debt reduction plan throughout 2021 with completion by year-end. We’ll be mindful of macroeconomic conditions and remain flexible with how we execute the repurchases, which may include both open-market transactions and tender offers. Should commodity prices deteriorate from current levels, we’ll prioritize liquidity and defer debt repurchases to a more appropriate time. Longer-term, it is our fundamental belief that a successful E&P company must maintain extremely low levels of leverage. In accordance with this belief, we’ll continue to manage towards our stated leverage target of around one times net debt to EBITDA. Turning your attention to Slide 14 with our business scale to consistently generate free cash flow, another key financial priority for Devon is to further accelerate the return of cash to shareholders through higher dividends. However, we believe the traditional dividend growth model deployed by most U.S.-based companies is flawed when applied to a commodities business. The historical practice in the industry of raising the fixed quarterly dividend in times of prosperity and cutting the dividend or underinvesting in the core business during down cycles is not an optimal solution. With these specific challenges in mind, we’re implementing an industry-first fixed plus variable dividend framework to optimize the return of cash to shareholders through the cycle. This progressive dividend strategy is uniquely designed for our inherently volatile business, whereby a sustainable fixed dividend is paid every quarter and a supplemental variable dividend is also calculated and reviewed each quarter. More specifically, upon closing our merger with WPX, Devon’s fixed quarterly dividend will remain unchanged and paid quarterly at a rate of $0.11 per share, with a target payout of approximately 10% of operating cash flow, assuming mid-cycle pricing. In addition to the fixed quarterly dividend, up to 50% of the excess free cash flow in a given quarter will be distributed to shareholders through the supplemental variable dividend, if certain liquidity, leverage, and forward-looking price criteria are met. In conjunction with this more flexible dividend payout strategy, we will also utilize a portion of the combined companies’ excess free cash flow to further improve our balance sheet and evaluate opportunistic share repurchases. With that, I’ll turn the call back over to Scott for Q&A.

Thanks, Jeff. We will now open the call to Q&A. With that operator, we’ll take our first question.

Good morning, guys. This is actually Kalei on for Doug. I’ve got two questions, if I may. Both are related to public policy on oil and gas. So under a potential Biden administration, obviously, there is a risk to the industry. Firstly, what’s your understanding of the potential subsidies to the industry that could be targeted? Specifically, I’m thinking about items like IDCs or even a minimum book tax that could raise cash costs on the business. How would this change items like your breakeven and how you pursue your activity levels?

This is Jeff. To be honest, I don’t have a lot of specific details around any changes that the Biden administration is planning or has talked about. Certainly to the extent that IDCs were to be limited or changed in some way, that would be impactful, certainly to our financial results and the taxable income that we would generate as a company. So that’s something we’ll certainly have to be on the watch for and be mindful of, but we don’t have any specific details at this point.

All right, thanks. For my second question, I’d like to ask for an update on your federal acreage plans. How many permits have been secured? To what date does that bring you to? And if you anticipate that window closing under a new administration, to obtain permits, what do you think that would close?

Well, I’ll start off here, and David can provide detail. I think we’ve said in our prepared remarks that we anticipate having about 650 federal permits by the end of the year. 80% of those are going to be in the Delaware basin or about 520 federal permits in the Delaware basin by the end of the year is our anticipation. The key point of that is that this covers four years of activity that we would anticipate in the Delaware basin. And that’s keeping in mind, when I say that even under the maintenance capital scenario, our overall production for the company would remain flat. That means though in the Delaware basin, we would be growing our production. So that’s a level of permits that would allow production to actually grow in the Delaware basin while keeping the overall production for the company as flat. The other thing I’d mention is that we are very well aligned with the state here. 40% of the revenue in New Mexico comes from oil and gas activities, and the state understands this extremely well. Governor Grisham, who’s on the Biden transition team, understands and supports oil and gas activity in the state. I know there’s a lot of discussion around this, and I understand why, but the alignment with the state and what we do as an industry for the state to help out with other social needs that the state has is extremely important. So while it’s a hypothetical question, we think most likely things will slow down, but there’s not going to be a stopping of activity on federal acreage. Even if there is, we have four years' worth of activity covered with the permits we anticipate by the end of the year. David, did I miss anything there?

No, you didn’t. I couldn’t have said it better myself. I think you’ve covered all the relevant points and agree with everything you said.

Guys, I appreciate that answer. Maybe if I get to that follow-up for clarification, I’m just wondering if any of the 650 permits that have been secured require any extensions by the federal government, because four years is a long period at the time?

Yes. Federal permits are issued with a two-year term, and then you have the ability to extend them for an additional two years. So certainly, permits that are out past that two-year term would require us to go through the extension process. But a couple of things I’d point out is that we’ve never had an extension denied before. It’s important to know that the permits are underpinned by environmental assessments. That’s done as part of the permitting process, and those environmental assessments are good for a period of five years. So the answer to your question is yes, but we don’t foresee many material impacts from that.

Perfect. I appreciate it, guys. Thank you.

Thank you. Good morning. Another topic that’s come up with some of the M&A that’s happened in the Permian basin after the Devon WPX announcement is the topic of decline rates. You highlighted the very strong well performance that you’re seeing and have been seeing in the Delaware basin, and I wonder if you could give us an update on where you see your Permian and corporate decline rate and how you expect that to evolve in 2021 in a maintenance program?

Good morning, Brian. This is David Harris. Yes. As we’ve talked about in the past, if you look at our year-end reserve report that we filed last year, if you look at those decline rates on a company-wide basis, that put us in the high-30s percent on an oil basis and in the low-30s on a BOE basis. As we move forward into this year and as we’ve been moderating capital, combined with some of the fantastic work that the teams are doing from a base production perspective, which we continue to see outperform quarter-over-quarter, our expectation is that on a company-wide basis, that oil rate would move from the high-30s to the low-30s, and on a BOE basis down into the mid-20s.

Great. Thank you. My follow-up is also regarding the Permian. On Slide 10, you talk about in some detail the various projects that you have and the order of completion, drilling and production they lie. I wondered as you contemplate the WPX acquisition and you think about where a maintenance drilling program between the two companies where you would prioritize, how would you see the Devon legacy drilling activity evolving, and what would be the main areas you highlight? Would you be drilling more or fewer wells there? How would you think about the prioritization in the context of having WPX assets?

We’re still in the process of developing a combined 2021 capital program. We don’t have anything specific to lay out there. But obviously, in the Delaware basin, where we’re drilling the legacy Devon wells, we’re delivering best-in-class costs for these wells. Productivity that’s as good as anybody out there. Our economic position is incredibly strong. On average, I’d say the Devon legacy activity is even a little bit stronger than the WPX, but the WPX is extremely strong also. And that’s why we like it. It’s hard to talk about specifics on what you can do right here in Lea and Eddy County. We haven’t developed any sort of combined budget yet, but both areas are highly economic.

Got it. Great. The last one, if I could just add one more point: the $560 per foot cost that you achieved in the third quarter of 2020. Do you care to hazard a forecast for where that could be in 2021 in a maintenance-type scenario?

We have been highlighting improved performance on a cost per foot basis every quarter for the last couple of years. We just continue to find ways to reduce that. To your comment about making a forecast, frankly, to points to levels that I’m not sure I would’ve thought we could get to. There is some service cost inflation in there, but I’d tell you that probably three-fourths of the improvement we’re making here over the last quarter and in the last several quarters is efficiency-driven. So we absolutely believe we can carry forward these levels and continue the rate of change. We expect that’s going to provide a nice capital efficiency tailwind, and another leg to the capital efficiency story. People will say, why are you doing this? Well, one of the big things that we have going for us is that we were the first ones to go to 10,000 foot laterals in the Wolfcamp out here. We had a few wells at the beginning that were challenging for us, but most industry is drilling 7,500 foot laterals. We figured it out, and that design has proven to be very robust. We have many repetitions of drilling the same type well over and over and over many more than many of our peer companies with this design, and that just allows us to be further down the efficiency curve. We are, however, never done improving.

Thank you.

Good morning, guys. Dave, my first question for you or Jeff, is about Slide 14. You’ve talked a lot about your thoughts regarding the variable dividend, but I want to make sure I’m clear. On that slide, you talk about that the dividend can be up to 50% of excess free cash. I’m just wondering how you think of that prior to determining where you want the debt level to be? Is that once you get the debt level to a certain point, and once you have growth at a certain point, I'm just wondering how I should think about that interacting with leverage and growth?

What we’ve said is that our breakeven for maintenance capital would be $33 WTI. If we add in the fixed dividend, that would take the breakeven up to $37, and we’ve said we will invest at maintenance levels up to around $45 per share. At that point, we would mix in a combination of some growth and select growth while also adding to free cash flow. By the time we get to $50 or so, we can accomplish all of our objectives of 5% growth and really strong cash flow yield. So once we start generating free cash flow and feel we have a strong enough financial position, we can do a combination of debt pay down and the variable dividend. We believe we can manage both.

Yes. That’s well said, Dave. The short answer is we’re already there. We’ve got the cash balance, we feel like we have a strong balance sheet, and we’ve got a constructive view of the commodity price outlook. So obviously, we’ve seen some weakness in prices this week and that could certainly continue into next year. We’ll be mindful of that. But we believe, with the combined company, we can deliver cash returns to shareholders via the fixed and the variable dividend along with accomplishing our debt reduction target over time. We feel like we’re there and in good shape.

Great, great details. Just one follow-up. Dave, you also talk about maintenance capital a lot. Given all the efficiencies you've achieved, how should we think about the definition of maintenance capital going forward, specifically in 2021?

We’re trying to use what I would consider more of a Webster’s Dictionary definition of maintenance capital. It’s not an optimized maintenance capital. We’re not counting on any sort of drawdown of DUC inventory in this at all. This is more about how much capital do we think we need to spend, or what price of WTI do we need given the capital we need to spend in order to keep production flat without any drawdown of DUCs? If we were to draw down DUCs, it could be even better. As we’ve accomplished better capital efficiency along with the cost synergies we’re anticipating, that’s what's allowing us to lower maintenance capital significantly. I would anticipate that to continue to decrease through time as we achieve further efficiencies and lower overall corporate decline rates.

Very good. Thanks for the detail.

Thanks and good morning all.

Good morning.

I appreciate your earlier comments on federal and state alignment and selection rents are certainly top of mind with investors. Regarding the 650 permits you’re expecting to have on hand at year-end, did the permits comprehend any change in development approach from your current practices, including spacing, lateral length, etc.? If a negative election and/or regulatory outcome were to occur, could the permits be amended later for longer laterals if you needed to accelerate resource conversion?

The 650 permits that we have in hand contemplate our current development strategy around the zones that we’re most focused on and that spacing as well as giving us some flexibility for some down spacing. About your question regarding the transition to three-mile laterals, a quick rule of thumb is that if you’ve got a drilling permit in hand and make a change that doesn’t result in a different level of surface disturbance, you don’t need to get a new permit. You go through what’s called a sundry process, which is a quick and routine process. This is something we’ve done from time to time when we tweak landing zones or bottom-hole locations. So that’s the process we would go through as we look for opportunities to incorporate more extra-long lateral development into our programs.

Got it. It’s fantastic detail.

I think there’s a lot of excitement and enthusiasm that the synergies are not only achievable, but we’re going to see even more than that after we begin integration. The early meetings with the teams from each side have shown a lot of promise as we think through how we can optimize programs together, and this is where we should be able to find some additional benefits that we might not have thought of initially.

That’s exactly right. As the teams have started to work together, we’ve already begun thinking about specific areas across the organizations. There’s no doubt in our mind that we’ve got a lot of momentum there. We should see increased synergies over time in most areas.

Well, it looks like we’ve gotten through our question queue. We appreciate everyone’s interest in Devon today. If you have any further questions, please do not hesitate to reach out to our investor relations team at any time. Have a good day. Thank you.