Ovintiv Inc. (OVV) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you for standing by. Welcome to the Ovintiv Anadarko Basin conference call. As a reminder, today's call is being recorded. [Operator Instructions] For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent. Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference call over to Steve Campbell from Investor Relations. Please go ahead, Mr. Campbell.

Thank you, operator, and welcome, everyone, to our Anadarko Basin conference call. This call is being webcast, and the slides are available on our website at ovintiv.com. Before we get started, please take note of the advisory regarding forward-looking statements in our news release and at the end of our webcast. Further advisory information is contained in our annual report and other disclosure documents filed on SEDAR and EDGAR. I also wish to highlight that this -- that we prepare our financial statements in accordance with U.S. GAAP and report our financial results in U.S. dollars. So any references to dollars means U.S. dollars and the reserves, resources and production information are after royalties, unless noted otherwise. Following our prepared remarks today, we will be able to take your specific questions at the end. As always, please limit your time to one question and one follow-up. This simply allows us to get to more of your questions this afternoon. I'll now turn the call over to our CEO, Doug Suttles.

Thanks, Steve, and good afternoon, everyone, and thank you for joining us. Joining me here today are Mike McAllister, our President; Brendan McCracken, our EVP and Head of all external-facing activities; Greg Givens, our Chief Operating Officer; David Hill, our EVP and Head of Exploration; Renee Zemljak, our EVP and Head of Marketing and Midstream; and Matt Vezza, our Vice President responsible for the Anadarko Basin. We are very excited to share with you today the progress we've made in the Anadarko and to highlight the competitive returns we deliver here. About half an hour ago, we issued a news release with some of today's highlights and published a detailed slide deck for today's call. We plan to reference these slides during our prepared remarks. And we'll be happy to take your questions at the end of the presentation. We've had a great deal of news recently. We're extremely pleased with the 90% vote of confidence from our shareholders for our recent domicile move to the United States. This move was all about exposing Ovintiv to the deeper pools of capital in the U.S., which we believe will add value for all shareholders. It was also about gaining recognition for the company we've become. Ovintiv defines the new E&P. We are a leading North American crude and condensate producer with a quality multi-basin portfolio. We have a track record of execution and consistent delivery and have rigorously pursued a strategy to drive performance today and position us for success into the future. We are generating both earnings and free cash flow, and 2020 is expected to be our third year in a row to grow and to generate free cash. We have also returned significant cash to our owners. Our use of cutting-edge technology and our unrelenting focus on innovation has positioned us as an industry leader in every basin where we operate. We have a culture of excellence, which extends across all aspects of our business from commercial to operations to social responsibility. Our business model is sustainable. We have the right mix of growth, free cash flow and a return of cash that separates us from the herd. We expect to deliver again in 2020 and beyond. 2019 was another strong year for us. We met or exceeded all of our targets, including delivering on our capital guidance. Following the Newfield transaction, we significantly beat our synergy targets. We delivered $200 million of annualized G&A savings, 60% greater than promised. This savings is permanent and has a PV-10 value of more than $2 billion. We took $2 million out of our STACK well cost, double the original target, and we're not done yet. Recent pacesetters in the play have achieved D&C cost of $5.2 million. More to come on this in just a few minutes. We've generated significant free cash flow, greater than $375 million in the second and third quarters combined with more to come in the fourth quarter. We also bought back 13% of our outstanding shares, and we increased our dividend by 25%. As I mentioned, 2019 was another very strong year. Liquid production was 317,000 barrels a day, above the high end of our revised guidance of 316,000 barrels a day. Crude and condensate grew 9% year-over-year, adjusted for asset sales, and CapEx was spot on at $2.8 billion. And in the Anadarko Basin, we generated approximately 25% of total company upstream free cash in 2019. We are extremely pleased with the Anadarko Basin's performance after our first year. Well performance has been consistent, and our base production has been strong, and we've massively reduced development costs. The basin saw 18% crude and condensate growth over 2018 with fourth quarter production of 164,000 barrels of oil equivalent per day. During the second half of the year, we maintained flat production levels and a consistent oil and condensate cut despite dropping from 11 rigs at the time the deal closed in February to 5 rigs in the fourth quarter. This is the key message today. There's a reason that the Anadarko Basin works for us, while some other operators are pulling capital out of the play. We will cover this in detail on today's call. We are a top-tier operator with proven and consistent results in every place we operate. Our acreage is in the heart of the black oil window. We entered the basin at the right price, the acreage was thoughtfully held by production and primed for effective full field development. We have low royalties, and there are no overriding royalty interests, which some of our peers have due to their entry through the acquisition of private companies. The Anadarko is a world-class reservoir, rich in liquids across stacked pay with significant scale and running room. In short order, we reduced well costs from nearly $8 million to $6 million per well and have doubled returns to approximately 50% at mid-cycle pricing. In fact, as the team will talk to in a minute, our most recent wells have come in at $5.2 million, enhancing returns even more. Notice that we now estimate our breakeven oil price for STACK wells is approximately $30 per barrel. We know that scale across multiple basins is an advantage. We have experience across the leading plays in North America, where we have over 2 million net acres. We are the second-most-experienced driller in North America and benefit from the experience and the information that activity generates. And we've demonstrated our ability to both grow liquids, generate free cash and return cash to our owners. We have transformed our company, increasing our crude and condensate production by a factor of 7 since 2013. Our new name is a reflection of this transformation. I know this simple fact is often lost on many, but Ovintiv is now the second-largest unconventional North American E&P in terms of both total production and liquids production. We are constantly looking for ways to improve our business. This push for innovation means that our teams are always working on new ideas, ensuring their learnings across the organization in real time. Because of our size and our scope, we have valuable exposure to massive amounts of data. We are active data traders. Because of our history of innovation, we often get far more data in the door than we send out. We have access to a massive proprietary database and use it to improve development across the company. Being a top operator means more than just drilling high-rate wells. Underpinning everything we do is an uncompromising focus on safety and a deep commitment to operate in a responsible manner. Our track record in both safety and environmental performance is strong. 2019 marked our sixth consecutive safest year ever. We continue to reduce our methane intensity and freshwater usage because we know this not only makes good business sense, but it's also the right thing to do. And it's good to see that our results and hard work is being recognized by third parties. I'll now turn the call over to David Hill.

Thanks, Doug. When we first looked at the Anadarko, we saw a compelling opportunity that fit our key requirements. For those of you that have followed us for a while, you know we call these our 4 pillars: best rocks and a position of scale; good market access; a chance to apply our operational excellence and proven cube development model, which keeps costs low while delivering competitive well performance and maximizing recoveries; and the application of capital discipline where we target investments to the best areas of the play. We entered the basin at a very attractive price. Sure, we looked at deals in the Permian. We had a pretty hard time seeing how competitive bids could generate a full-cycle return at the corporate level and meet our development standards. In the Anadarko, we saw high-quality rocks that would allow us to instantly apply our proven practices to quickly reduce costs and enhance returns. The thoughtful approach taken by Newfield in acquiring and delineating the Anadarko acreage was an ideal setup for full-field development. Early lease line drilling with low-intensity completions helped reserve massive swaths of untouched resource for us to optimally produce via cube development. And because of their approach, this position met our development standards. The Anadarko Basin has an advantage with its proximity to markets. The basin is located only 70 miles from Cushing, and it's in the center of the Mid-Continent gas market. Furthermore, the basin's midstream and market infrastructure is well established and positioned to accommodate growth. Our marketing team has an excellent track record in multiple basins, managing risk, maximizing value and securing flexible midstream and market arrangements. We currently have 90% of our STACK oil production connected to pipeline infrastructure. It's important to note that production from our core STACK area is transported and sold in a segregated stream, achieving premium pricing at Cushing. Although geographically, the Anadarko Basin's in the Mid-Continent market area, 85% of our NGL production receives a Mont Belvieu-related price, and our natural gas production realized 83% in Henry Hub pricing in 2019. The Mississippian age Meramec and equivalents are a thick and complex lithologic system encased in a world-class generative petroleum system. At the base is the organic-rich Devonian age Woodford Shale, and at the top is a critical basinal seal formed by the clay-rich Chester Shale. Our acreage is in the heart of the black oil region. The play has a thick hydrocarbon window with multiple STACK targets. As you move west or deeper, the play quickly transitions to gas. Our focus is on the core of the black oil window, where our contiguous land position allows us to control cost and effectively execute our cube development model. The Meramec formation has a low clay content and is brittle, which enables greater hydraulic fracture and efficiency. The reservoir's porosity and permeability are enhanced by natural fractures, resulting in a resource play with enhanced storage and productivity. The play is also advantaged with no free water in the system. As we've said, Ovintiv is positioned in the core of the black oil window. Substantial well control gives us high confidence in results. We have a deep knowledge of the subsurface that has been built over time by acquiring high-resolution data through thoughtful pilot projects and testing. Examples include advanced geophysical logs, full core, 3D seismic, fiber optics, advanced geochemistry, tracers and production logs. This data is essential to understand how the reservoir behaves, how wells interact and how the acreage should be developed to maximize value. We have access to well data from over 700 horizontals from offset operators to assist us in designing each cube. 3D seismic across our lands enhance our geomechanical understanding and assist us in our development approach. One area that differentiates us is our fast cycle times and our ability to capture learnings and rapidly transfer them within the play and across our portfolio. STACK had all the characteristics of a premium resource play. What it needed was a top-tier operator. Ovintiv's acreage position was specifically targeted, is differentiated when compared to peers. It's in the bull's eye where the focus on the right product, oil. It has the right combination of reservoir pressure, oil cut, reservoir thickness, and it's deep enough to provide pressure and support high well deliverability. Strong early time oil cuts drive returns and quick payouts. This is readily observable in the public data. Good reservoir thickness leads to significant hydrocarbon-in-place. You move too far to the northeast, you lose pressure in reservoir thickness. As you move further to the southwest, the oil cut drops off again, but not all acreage is created equal. I'll now turn the call over to Mike McAllister.

Thanks, David. Let me take a slightly higher-level approach to define how we operate because it differentiates us. It speaks directly to why we were able to enter a basin and quickly become the leading operator. As Doug mentioned earlier, we have a great deal of experience in unconventional plays. In fact, we are the second-most-active E&P in North America. With that position comes a great deal of experience and practical knowledge. We've created a deep-rooted culture at Ovintiv, where innovation is rapidly shared across the company to improve results and expedite learnings. A simple example of quickly sharing learnings across the company was a new completion design that was very successful for us in the Eagle Ford. It was moved 2,000 miles north to Pipestone Montney, in 2 months, delivering a 50% improvement in well performance. Another example was in the Permian. By taking drilling learnings from across our multi-basin portfolio, we're able to cut our spud-to-rig release drilling time in half, from 24 to 12 days, which is industry-leading performance in the basin. For several years, we watched the early development of the Anadarko from the sidelines. We saw numerous examples of where our proven practices could be used to lower cost and improve returns. We had high confidence that we can make the basin economically competitive by lowering costs with no improvements to well productivity. And as you know, this was our promise at the time of the transaction. From the day the deal was announced, we began preparing to implement our best practices in the Anadarko. In a moment, Greg and Matt are going to review our impressive drilling, completions and operational performance. But first, I want to touch on what we were able to achieve from our -- with our supply management approach. Over my 40 years in the industry, with both large integrated and independent E&Ps, I've never seen a supply management team so effectively work with operations to deliver cost efficiencies across the business. Our supply management team covers 80% of Ovintiv's spend today. The supply team was ready to go immediately at closing, on bundling services for increased market competitiveness, leveraging our multi-basin scale, market knowledge and buying power and entering into strategic contracts with high-performing service providers. In fact, our frac sand costs have been cut in half, from $0.07 to $0.035 per pound, which equates to a $700,000 cost reduction per well. Working hand-in-hand with operations, our supply management team, led by Vineeta Maguire, delivered almost $100 million of savings in just the first year of operations in the Anadarko. I will now turn the call over to Greg Givens, our COO, who will tell you about our impressive drilling and completions performance.

Thanks, Mike. Let's start by taking a look at our drilling operations. After less than a year, we have established ourselves as the industry-leading driller in the Anadarko. We achieved an average drilling rate of more than 2,200 feet per day in our latest cube. We recently drilled a pacesetter well in 9 days from spud to rig release. This was achieved by drilling the lateral more than 60% faster than a previous best-in-class well. The tremendous headway we've made in STACK is now being applied to the SCOOP. In a recent cube, we reduced our drilling days by 20%. We have an active 2020 plan in the SCOOP and expect to see additional cost improvements as our teams continue to innovate and apply our learnings from across the organization. The change in our approach to completions is the most significant source of cost savings. The team is completing the wells faster, at much lower cost and without reducing the size of our jobs. By embracing the culture of innovation, the team delivered a significant shift in performance. This began on day 1 of Ovintiv taking over as operator. Our pump rates increased from 80 to over 100 barrels per minute reducing the time to pump each stage by 25%. By optimizing our operations, we've increased pumping hours per day by 2.5x. And as a result, our Q4 2019 frac cycle times were cut in half. In addition, we are saving $200,000 per well by optimizing drill out procedures. And most exciting of all, the teams continue to find ways to reduce cycle times, cut costs and improve operations. I'd like to turn the call over to Matt Vezza, our Vice President and General Manager over the asset. Matt joined us from Newfield and plays a key role leading our Anadarko operations. Matt?

Thanks, Greg. We've taken a close look at every phase in our operations, including production facilities. By standardizing well site designs, we have significantly reduced engineering, equipment and installation costs. Additionally, employing simultaneous operations in the Anadarko has contributed to the step change we've seen in pad cycle times. In 2020, we expect to achieve an additional 8% reduction in facility costs versus our 2019 average. When spread across more than 100 wells, this savings really adds up. We are extremely pleased with the efforts of our team to optimize base production and arrest decline rates. In fact, we improved our daily performance by 1,000 barrels of oil a day. This helped lead the strong outperformance you see in our fourth quarter volumes. Much of this improvement was instigated at the field level, where the combination of our culture of relentless improvement, coupled with empowering our operators with the information and the tools they need, enables us to optimize well productivity. We pushed accountability down to the operator level and effectively reduced downtime by more than 50% over the prior year. Our teams understand which levers to pull to create value and help maximize our revenues. Cycle times matter. We know that less days spent drilling and completing wells means fewer dollars spent and a faster return of capital. Cycle time improvement has been one of the major benefits of adopting cube development model. Reducing cycle time also helps us learn faster. New information can be quickly applied to our next cube. This is critical in optimizing unconventional developments. The tempo at which we are getting data today and acting on that data is adding value. This is a key difference between our cube development and Newfield's legacy row development where cycle times were nearly twice as long. You got a good look at how we are focused on adding value at every stage in the process. And I can assure you, we are far from done. Although we've made great strides over the last year, our track record demonstrates we will continue to find ways to increase efficiencies. And it is our full expectation that we will continue to deliver strong performance in 2020 and beyond. I'll now turn the call over to Brendan McCracken to talk about well performance and economics.

Thanks, Matt. One of the questions we've heard from the market was we get how you're going to make the Anadarko better, but how does the Anadarko make you better. Well, as Doug outlined, we've had very strong consistent performance since closing the acquisition, and the Anadarko has been a big part of those results. 1/4 of our free cash flow in 2019 was delivered by our Anadarko asset. Clearly, a big part of making this work has been doubling the well returns we are earning. When we entered the Anadarko, we believed we could make cube development work. We said we could make consistent wells in the black oil window of the STACK at development spacing. And that's what we've done. We've been reporting out on our progress each quarter. And shown on the slide here is the production from all our 2019 black oil wells. We're showing both the total BOE production and crude and condensate production for all these wells. There are 2 curves on each graph. The orange curve represents 99 wells that were a combination of Newfield drill and Ovintiv completion. The blue curve represents 67 miles that are Ovintiv-only cube development. As you can see, the crude and condensate performance has slightly improved for our cube wells. This is exactly what we expected, and the key is the costs are dramatically lower. In fact, when we combine these well results with our $6 million well cost, 19% royalty rate, $2.50 per BOE LOE and realized price at WTI, this is what delivers the 50% rate of return. In shales today, there are 2 primary development strategies being deployed. The first is the strategy we follow, we call it cube development. We deliver leading capital productivity and returns while in cube development mode, which means developing all the prospective benches at once at development spacing. The other strategy that some deploy is called upspacing, where operators choose to use very wide well spacing and only develop the most certain benches first. Depending on the operator's cost structure and completion design, this might be what they need to do to deliver acceptable returns, but it comes at the expense of future inventory and significantly erodes the value of the acreage. The most important parts of our cube development strategy are value and returns. We know for certain that returning to infill does not maximize value compared to getting the development spacing right the first time. We know that child wells drilled near parents in the same zone or in adjacent benches will perform meaningfully worse, also destroying value compared to our cube development. We have spent years building the physics-based modeling capability, proprietary data and systematic capability to be a world-class operator. And as shale enters the middle innings, it's all about converting the resource to value, and we are well positioned to lead in that phase. The graph on the slide illustrates this point for a STACK drilling spacing unit. You can see, in this case, the NPV for the drilling spacing unit is maximized at 6 wells per section in the Meramec. And at this spacing, with our cost structure, we're delivering a 50% rate of return. You can also see that if we still had Newfield's cost structure, the maximum NPV would have been at 4 wells per section, and it would have only earned half the IRR. One of the other questions we frequently get asked is why have other operators moved capital out of the basin. Well, David showed you our acreage position. Our acreage is positioned in the core of the play. And on top of that, we have 3 key advantages in our returns compared to our in-basin peers. Our favorable midstream contracts maximize our margins, we have low royalty rates, and we don't pay overriding royalties, and we've massively reduced well costs rapidly. Importantly, we aren't done. Our pacesetter well cost would deliver more than a 60% rate of return. As David said earlier, 1 of the things we liked about the Newfield position was the large contiguous acreage and the approach they took to hold the position. Going forward, we have 200 undeveloped drilling spacing units in the STACK and another 70 in the SCOOP. This gives us a long runway in the core of the play. I'll now turn the call back to Doug to close this out.

Thanks, Brendan. The key takeaways today are pretty straightforward. Our economics in the Anadarko Basin are differentiated versus our peers. This is leading to returns that are twice as high as the basin average. With a rate of return of about 50%, this play not only competes within our portfolio, but pound-for-pound, it is competitive with the very best shale plays across North America. We've outperformed initial expectations through rapid cost reductions and consistent well performance. We expect these trends to continue, just like we've demonstrated everywhere else we operate. We're very excited to see what our team can deliver in 2020. Ovintiv has the characteristics of today's successful E&P company, and what we are doing today is sustainable into the future. We have significantly improved the business, transforming our company from gas to high-value liquids, selling nonstrategic assets and creating a strong multi-basin portfolio with scale. We have a proven track record of constantly innovating to add value and driving efficiency into every corner of our business. We have grown the business in cash flow, in crude and condensate production and in free cash flow. We have a track record of returning cash to owners. We have a strong capital structure and an investment-grade balance sheet. We have an undrawn $4 billion credit facility that we recently renewed out to 2024. That credit facility has no reserve-based covenants and only a favorable debt-to-cap test. We have no debt maturities until late 2021, with the majority of our debt due well beyond the end of this decade. On a pro forma basis, our leverage is below 2x, and we are using our free cash flow to move that towards our 1.5x target at mid-cycle prices. And all of this is supported by a risk management program with a proven track record. Our recent hedge additions help ensure that we have the cash flow to deliver on our forward plans and ensure we remain financially strong. Although we are disappointed with our valuation today, we deeply believe that we have the right strategy that will be differentiated in the market. Our strategy is producing strong corporate-level performance today that we believe is sustainable on the road ahead. Thank you for listening to us. And now we'd be happy to take any of your questions.

[Operator Instructions]. Your first question is from Brian Singer of Goldman Sachs.

My thanks for doing the call and I appreciate the detail. My first question is with regards to well costs. You talked about the decrease in well costs that you've driven and also the pacesetter well costs that are $5.2 million versus $6 million as your base. What do you see as realistic from where you can go from here? And if you were to achieve lower costs, would you then demonstrate more free cash flow or use that to increase activity?

Yes, Brian, that's a great question. And I think it's interesting because I'm sitting here with Matt Vezza, who he and his team have delivered those results. And I think Matt's getting nervous now as I'm about to answer that question. But clearly, we've blown the target out of the water. I mean, we said we were going to take $1 million out. We've taken out $2 million and actually, we're now close to taking out $3 million. We'll see. But as we look to 2020, I'm confident our costs will be well below $6 million. And how repeatable or how much further below $5.2 million, we need to prove. But I can tell you the team is not out of ideas. And probably the most important question you just asked was, what are we going to do with the savings. And it's very clear what it's going to do. It's going to go to free cash flow and the balance sheet is where it's headed.

Great. And then my follow-up also is with regards to free cash flow, but also oil and liquids production. Is there a goal that you are setting or you think you can deliver from the Anadarko Basin for Ovintiv overall in 2020, either from a production, oil, particularly or free cash flow, either at strips or at $55/$2.50 that you assume in some of your slides?

Yes, Brian. And just in a couple of weeks, I think we've sent out the note that we're going to provide our full 4Q results and also our guidance for 2020 on February 20. So we'll get into that in some detail. But I actually see this asset as, from where we see it today, as performing very similar to we see the whole company after our rebase at the current activity level. Because as we highlighted in materials today, we've dropped from 11 rigs at the time we closed the deal to 5. And -- but I actually see this asset generating significant free cash for the business while delivering modest growth, but how we optimize that across the portfolio is something we work on every single year. And that is one of the advantages of having a multi-basin portfolio.

Your next question comes from Gabe Daoud of Cowen.

I appreciate all the detail here. Though I was curious kind of hitting on somewhat of a 2020 question again, but just given where the rig count is today in the Anadarko at about 6 and just given the significant well cost savings you guys have highlighted, how should we think about the budget for the Anadarko asset in 2020 versus 2019? And then do you think the SCOOP gets a little bit more activity this year?

Yes, Gabe. It's a little -- obviously, we're going to talk some more about this in a couple of weeks. But in many ways, what we're going to be doing here and trying to do here is what we've demonstrated in the Permian, where if we get a consistent activity level, we can even further drive performance and efficiency. So I think that's about what you should expect, and we'll provide more detail here in a few weeks. What was the second half of your question, Gabe?

Yes, sure, Doug. Just SCOOP, any like increased allocation this year to the SCOOP or still heavily dominated by STACK, I guess?

Yes. Well, if you look at the information we provided today, about 1/4 of our DSUs are in the SCOOP, and I think over time, you'll see roughly a similar amount of activity down there. We obviously concentrated in the STACK in 2019. So you'll see a bit more SCOOP activity. But 1/4 of our DSUs are down there, and they deliver and can deliver significant returns. And we've just started activity down there. And I think Greg mentioned, we're already starting to show significant cost reductions in that area as well.

Got it. That makes sense. Then just, I guess, as a follow-up, just looking at where the type curve is today versus Newfield's, I guess, a little bit of a wider range of 1.1 to 1.7 MMBOE I guess, versus today, kind of at 1.1, with 32% oil, is there anything in particular going on there or anything you could speak to? Or is it just kind of tightening as you guys have kind of taken the keys over? And then also, could you just kind of remind us where Newfield's oil cut was? Or I guess what their expectation was on their wide range of EURs? Was it also that 32%?

Yes. I mean the first thing I'd tell you is what you'd had previously to today was a blended type curve across the activity set. And what we've tried to do now is give you additional data, really 3 different type curves that reflect sort of the 3 areas that we'll be developing in the future and showing the returns from the range on those type curves and the cost that we're delivering. But I think Brendan tried to highlight, the well performance has been incredibly consistent. And that's what we're showing. And if you recall, when we entered play, the way we thought we were going to create value here was by radically reducing cost, which we've done. We weren't -- we didn't make at that time, and we're still not making today, assertions about radical changes in well performance. But what we have done is given you a wider or a full set of type curves that cover the range of DSUs we'll be developing going forward.

Your next question comes from Asit Sen of Bank of America.

So two unrelated questions. First, on completion intensity, Doug, in the past, you've spoken about up to 3,000 pounds per foot in completion intensity. Could you speak to the leading-edge intensity here for the pacesetter wells? And how are you thinking about balancing cost and completion intensity?

Yes. I think, and I'll invite Greg and Matt to add any comments they want here, but effectively, the costs we're talking about are at our 2,000 pounds per foot completion, which is where we've been, I think, throughout the year. So that's at what we'd consider today the optimum design. And at this point, I don't think -- we're always testing variations in completion design, but I don't think we have any significant plans to make major changes to that. But Matt, anything to add?

No, you're right, Doug. That's exactly right. Our standard is 2,000 pounds per foot and 2,000 gallons per foot right now.

Great.

So I think -- and I think Greg mentioned this, too, but we're delivering these costs not by reducing scope. We're doing it through doing things more efficiently. And what Mike talked to is the outstanding results from our supply chain team.

And I might just add that those pacesetter wells are at that same intensity that we're talking about at 2,000, 2,000.

Got it. Got it. And then 25% of free cash flow from Anadarko Basin is fairly impressive. Doug, could you speak to kind of the number of rigs or completion to keep production flat in Anadarko? Any sense of sustaining CapEx there?

Yes. I don't have that level of detail to give you today. But what I can say is, if you look at what we're doing, we're roughly drilling about 100 wells a year. We've actually grown a lot, but we've actually reset the level of activity at a more modest level than it was in the past. And by the way, that's consistent with how we run the business. And every place we invest in the company generates free cash flow. Every single asset in the company does that. And we focus our capital to generate liquids, particularly crude and condensate production. And as we optimize this, this will be everything from what Renee's team can do with realized pricing to market conditions and to the pace at which and the things we see to innovate. So we're going to always sort of move around the capital, probably not in massive amounts but at the margin to optimize the delivery for the corporation.

Your next question is from Marshall Carver of Heikkinen Energy Advisors.

Thank you for the update. Nice growth from 3Q to 4Q. I did have a question on the number of wells that you put online in the Anadarko Basin that drove that growth in the fourth quarter.

Yes, I don't have that at hand. In fact, I'll ask Steve or his team to follow up with you. But kind of, what -- as you saw and we highlighted in the numbers that we fairly quickly dropped rig count from the 1st of the year -- right after the 1st of the year, we took over. And obviously, we had a lot of wells come online in 2 and 3Q but only modest in 4Q. Matt was really trying to highlight, not only our wells -- new wells performing like we expected, but the focus on the base and driving downtime down and improving well performance, which our operating team has done, also contributed to this fourth quarter performance.

All right. And if you all could follow up, I would be curious about the number of wells put online.

Okay.

Your next question is from Neal Dingmann of SunTrust.

Thanks for details. Doug, my question, you and others have talked, it's certainly notable about the lower well cost that you're getting, certainly since the Newfield acquisition. I guess my question is just when you look at the economies of scale with running now 5 rigs in the play, do you still think you're achieving that? Or would you optimally want to go back to a higher number where you see that and also if you just talk around that, please?

Yes. No, I think we can not only sustain this level of performance, I think we'll extend it. And just to contrast it, I mean, if you look at our results in the Permian, which are as strong as anyone out there, I mean, we drill the fastest wells in the basin, our cycle times are the best there, our wells, as Brendan and David highlighted, perform just as well as upspace wells, but we're actually fully developing the acreage. We're doing that on a 5-rig program. The other thing to note is a 5-rig program for us is equivalent to like a 10-rig-plus program for others because we're so efficient. I mean you can look at every play we're in and our spud-to-TD times are at the very front edge of the basin and many times significantly faster than the average. And we're driving this forward. I mean when we talk about our full year 2019 results in 4Q, you'll hear about similar levels of performance everywhere we're operating. It's not unique. So I do believe we'll sustain this, and a lot of it is to do with the constant innovation, and the second piece is, I can't highlight it enough, is what we've done in the supply chain. And we've taken what we do in places like the Permian and brought it to Oklahoma, and it's worked just as good as it has everywhere else.

And then just lastly, one conceptual question. With the free cash flow to display and the Perm is throwing off, your thoughts about -- there's always that thought about growing faster to try to kick off even more cash flow to get that debt paid down a bit quicker versus running fewer rigs. I'm just wondering conceptually how you all sort of think about that into 2020.

Yes. We've been talking about this for a while. We actually think in the market conditions we have today and really referring to the macro, the rate of oil demand growth globally and how supply is playing in and some of the volatility there is in commodity, that modest growth, combined with a focus on free cash generation, is the right model. And we're very comfortable with our plans to do that. And of course, we also highlighted, we realize our leverage looks elevated relative to some peers, but our balance sheet is incredibly strong. We're investment-grade, we have no debt due, we have a $4 billion undrawn facility that does not have reserves covenant tied to it. And hopefully, you noticed today, we updated our 2020 hedge book, and you saw that it increased by 40% at robust numbers, which means we can execute a program, which actually has modest growth, free cash generation without putting the balance sheet at risk.

Your next question comes from Jeffrey Campbell of Tuohy Brothers.

Thanks for the call and all the information. It's really very helpful. On Slide 33, I think you referred to it earlier. I just want to dig in a little bit. It refers to an immediate 15% cost reduction versus expectations in the SCOOP. And I was wondering does the SCOOP have the potential for the same kind of savings that you've been getting in the STACK. And specifically, do you see enough landing locations to support a cube-type model?

Yes, I tell you -- Jeff, good questions. I'm going to pass this over to Greg, but as we mentioned, we do have about 70 DSUs to develop down here. But Greg, maybe you fill in your thoughts on costs.

Yes. I think all indications we've seen so far is that our cube model works in the SCOOP just like it worked in the STACK, just like it worked in the Permian and in the Montney and other areas. Feels like we've got a lot of running room there. We're just getting started, but I've got full confidence this team is going to see similar-type reductions in cycle time, and that should flow through to cost. So we feel real positive about where we're going in the SCOOP. As far as the landing zones there, we've actually got several formations available to us in the SCOOP. And so I think cube development is very applicable there. So we're encouraged by what we see.

Okay. Well, that's good color. And that seems like more optimism for the play than at the time of the acquisition, which I think is really good news. The other question I had was that, when I look at the overview map, I don't see the Uinta or the Duvernay on there like we did a year ago. I was just wondering what's the current status of those assets. And do we still think of the Duvernay as a free cash flow generator?

Yes. Jeff, both of those assets generate free cash flow, but they're currently not attracting capital. I mean we're focused -- we're focused, clearly, the majority of our capital in the 3 main plays, the Permian, the Anadarko and the Montney. And then our Bakken and Eagle Ford positions generate significant free cash, yet still have very attractive locations to drill, just a different scale. Today, we're not focusing a lot of capital on either the Duvernay or the Uinta. We're optimizing elsewhere. And in fact, as we've stated, the Uinta is really about appraising what that opportunity is and seeing where it fits in the portfolio over time.

Your next question comes from Josh Silverstein of Wolfe Research.

Thanks for all the information today. On the SEC economics because 1/3 of the wells -- 1/3 of the percentage of the well is NGLs. I was hoping you can give us some context around the price assumption there. You gave us the $2.50 and the $55 price for crude oil and gas, but I was just wondering what the NGL assumptions were on there.

Yes. Josh, they're very similar to what we're seeing today. So our view on NGLs is that over time, we think they are going to improve as export infrastructure comes online. But we're not building in -- you're seeing NGL prices more similar to the second half of 2019. So we're not building in a significant increase. And the other thing, and I think that David highlighted, is just know that our NGLs are really priced off Mont Belvieu, which is the best NGL prices in North America.

Got it. So that's something maybe a high teens number for the assumption there?

Yes, something like that. I mean just basically look at what the second half was, and it's about in that zone. We do think there's probably a bit of upside there. And clearly, we recognize -- it wasn't very long ago $2.50 might have felt good as a gas price. Clearly right now, it doesn't. But we've given you all the data. You can flex those numbers, and I think you'll see they're still robust. The returns are still robust because every play has some gas and some NGL production in it.

Your next question comes from Dennis Fong of Canaccord Genuity.

Just 2 quick questions here. The first is around a little bit of a follow-on to kind of completions intensity there around the 2,000 completions intensity. In the past, I know you guys have looked at higher levels of intensity, which is the way that we'd be thinking about it be kind of focused on Slide 31, where you guys are balancing the completions intensity with the wells per section that you guys are actually developing the play to and that at a higher intensity that you wouldn't have to drill necessarily as many wells in a particular section. Is that the way that we should be thinking about that balance? And is that your interpretation of the way to maximize value out of this play?

Yes. And I think, Dennis, I think that conceptually, what you described is how we think of kind of everywhere, which is you don't want to deploy more capital than you have to effectively recover their resource and maximize your returns. So you're always varying these. I would say when we use the word capital -- I mean, completion intensity, it's not just the amount of sand or water in the well. We believe the way you actually conduct the completions, so how we space perforation and stages, how we pump the job, how we use various sizes of proppants and even diversion agents, allow you to do that without more. But it's one of these things that I think we're still learning a great deal about. I mean we can talk to you at some point about rogue fracs. And when you get an individual frac out of an individual perf cluster that runs away from you, which obviously then contribute to that well and can damage offset areas. So we're always trying to understand how we can actually get the best recovery out of the rock at the least amount of capital. But at this point, we're not seeing a -- we're not anticipating, as Matt mentioned, a big change to the amount of sand or the amount of water, but we are pumping the jobs very differently, and you heard about that earlier, which is helping us get the cost down.

Perfect. And then my second question here is just related to some of the wells that were already drilled by Newfield that you guys were able to complete in this year. Were there substantive differences in terms of the techniques around drilling associated with some of those drilled and uncompleted wells that you were able to, say, translate into stronger well performance on the back of it? Or are those just kind of very similar outside of obviously the pace of drilling that you guys have been able to achieve now that the assets are under your belt?

Yes. Dennis, we're drilling the well, in other words, the landing zone, these kind of things, very similar to how we're doing before. Of course, what we've been able to do now is focus our attention, which was early on in the completions where we took a lot of cost out and drove a lot of efficiency, we've now been able to do that on the drilling side and also seeing substantial improvements. So I think you guys all know that essentially, the time it takes to drill the well fundamentally determines the majority of what it's going to cost, so if you can -- and as you probably know, the rig rate is not even half of the daily cost of running a drilling operation. So that when you take time out of the drilling operation and successfully deliver the well you want, you substantially reduce the cost of the well, and of course, you need less out of the supply chain, which takes pressure out there. But we're really drilling the same well design as before. We're just doing it faster and more efficiently.

At this time, we have completed the question-and-answer session, and we'll turn the call back over to Mr. Campbell.

Thank you, everyone, and thanks again for joining us today. We look forward to speaking to you again very soon. Bye. Thank you.

This concludes today's conference call. Thank you for your participation. You may now disconnect.