Ovintiv Inc. (OVV) Q4 2019 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2019 Fourth Quarter and Year-end Results 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's representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise that you 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 fourth quarter and year-end 2019 conference call. Today's call is being webcast, and our slides are available for you on our website at ovintiv.com. Before we get started today, please take note of the advisory regarding forward-looking statements found in our news release and at the end of our webcast slides. Further advisory details are contained in our annual report and other documents filed on SEDAR and EDGAR. I also wish to highlight that we prepare our financial statements in accordance with U.S. GAAP and report our financial results in U.S. dollars. So references this morning to dollars mean U.S. dollars, and the reserves, resources and production information are all stated after royalties unless we state otherwise. Following this morning's prepared remarks, we will all be available to take your specific questions. As always, please limit those to one question and one follow-up. This simply allows us to get to more of your questions today. I'll now turn the call over to our CEO, Doug Suttles.

Thanks, Steve, and good morning, everyone, and thank you for joining us. We finished 2019 very strong and are off to a great start in 2020. We drove efficiency gains in every part of our business last year, and again, exceeded expectations on all key financial and operational measures. This momentum is carrying into 2020, where we again expect to capture further efficiencies across our business. I'm joined today by Mike McAllister, our President; Brendan McCracken, our Executive Vice President of Corporate Development and External Relations; Corey Code, our Chief Financial Officer; Greg Givens, our EVP and Chief Operating Officer; David Hill, who's our EVP and Head of Exploration; and Renee Zemljak, who's our EVP and Head of Marketing and Midstream. Please note that we plan to reference the slides we issued yesterday, and we will take your questions after our remarks. We believe that Ovintiv defines the new E&P, and our 2020 outlook we will discuss with you today is consistent with our strategy to balance significant free cash generation with crude and condensate growth. We have financial strength with strong investment-grade rated balance sheet and an asset base capable of generating significant free cash flow while growing, marking the third consecutive year where we've accomplished this. And that free cash is targeted at our balance sheet. We have a history of being extremely disciplined with our capital. This ensures that we achieve the strategic outcomes that we target for our business. Our assets are top tier. We have scale and a deep inventory of crude and condensate development projects across our quality North American portfolio. We have managed the development of this resource thoughtfully using our unique industry experience and proprietary data set. This leaves us with a long runway of future opportunity, and this is a key advantage. We have a culture of operational excellence, which extends across all aspects of our business, including ESG. Our use of cutting-edge technology and our unrelenting focus on innovation has positioned us as an industry leader everywhere we operate. And lastly but very important in today's volatile commodity price environment, we have shown our ability to effectively manage risk. This is part of our sustainable business model that is yielding superior results through this cycle. Now I'll hand the call over to Corey to cover our financial and our operating results.

Thanks, Doug. 2019 was another great year of performance. Here are some of the highlights. Both our financial performance at the corporate level and our operating performance at the field level were excellent in 2019. The year marked our second consecutive year of free cash generation, and we had strong crude and condensate growth in our three core growth assets. Over the last two years, we've generated a cumulative free cash flow of about $615 million [ph] excluding onetime costs. This highlights our organic ability to generate substantial free cash. Our results again exceeded expectations for both earnings and cash flow, and our capital investments hit the midpoint of our original guidance. In short, we delivered on our promises. We exited 2019 with 2.2 billion barrels equivalent of proved reserves, which equated to a reserve replacement ratio of more than 2 times annual production. And you can take a look at our reserve information in today's deck as well as in our 10-K, which will be filed later this week. Certainly one of the most significant highlights was the quick and successful integration of our Newfield acquisition, closed just over 1 year ago. We rapidly cut well costs in the Anadarko and demonstrated our ability to implement proven practices from other areas into a new region. The play is competitive across our portfolio and industry. G&A savings nearly doubled our original target, and we combined the best and brightest of both organizations to form one team. Our business model is sustainable, and we have a unique combination of profitable liquids growth and free cash generation. We're one of the largest producers of high-value crude oil and condensates, and over the last 2 years, returned $1.7 billion to our owners. Let's look a little closer at our 2019 summary results. Our release has all of the details and helpful reconciliations that are provided in the slide deck. Our fourth quarter cash flow was $815 million or $3.14 per share. And our operating earnings were $210 million or $0.81 per share. During the year, we’ve returned $1.25 billion [ph] of cash to shareholders through our share buyback program. Said another way, we bought back about 13% of the company. We also increased our dividend by 25%. For 2019, our full year free cash flow, excluding onetime items, was $476 million, while cash from operating activities was $2.9 billion or $11.22 per share. Full year earnings were $234 million, and operating earnings were $860 million or $3.29 per share. SEC proved reserves at year-end increased 60% - increased to 60% liquids, and totaled approximately 2.2 billion BOE. And our total proved reserve life index has grown to more than 10 years. Fourth quarter total production was 593,000 barrels of oil equivalent per day, including crude and condensate production of 226,000 barrels per day. This ranks us as 1 of the largest crude and condensate producers in this sector today. Pro forma total production was at the upper end of our revised guidance at 589,000 barrels equivalent of oil per day, including crude and condensate production of 228,000 barrels per day. Our crude and condensate volumes were up 9% year-over-year, adjusted for asset sales. Our pro forma liquids production was 317,000 barrels a day, also above the high end of our revised guidance. Total cost came in at $12.59 per BOE, below the low end of our guidance. We met or exceeded all of our objectives in 2019, while hitting our original capital plan of $2.8 billion on a pro forma basis. We generated more than $950 million of upstream operating free cash flow, excluding hedge, in 2019. Strong performance from each asset in the portfolio allowed us to more than offset the impact of asset sales in China and Arkoma, which together totaled about 5,000 BOEs a day. Before I hand the call back to Doug, I want to reinforce the confidence we have in our balance sheet. First of all, our business is sustainable, and we're generating free cash flow for a third straight year, while growing our high-value crude and condensate volumes. We target a leverage ratio of 1.5 times at mid-cycle prices, and expect to do this organically over the next couple of years without any commodity price help. We've recently renewed our credit facilities that total $4 billion, with a maturity date of July 2024. These credit facilities have only 1 financial covenant, and adjusted debt to cap not to exceed 60%. At year-end, we were at 28%. It's equally important to note what our credit facilities do not have. There are no borrowing-based covenants, there's no quarterly determinations and no leverage coverage ratios. The $4 billion credit facility capacity is set for the next 4.5 years. In terms of other indicators of our balance sheet and credit worthiness, we have investment-grade credit ratings, and our bond trading prices reflect confidence in our business. And we also have access to low-cost commercial paper borrowing. Our confidence in our balance sheet is backed by extremely strong liquidity, good leverage, a strong hedge book and capital discipline to adjust our activity levels to drive free cash flow. We remain committed to our 1.5 times leverage ratio target. Just to be clear, our balance sheet is not at risk. I'll now turn the call back over to Doug to discuss our 2020 outlook.

Thanks, Corey. As we've said a few times today already, we expect that 2020 will be our third consecutive year of free cash flow generation, while growing our crude and condensate production. Our capital will again be targeted to specific programs that drive our long-term trajectory, generating profitable liquids growth, improved capital efficiencies, lower costs, strong returns and growing margins. We have high confidence in our ability to consistently innovate to deliver results. You've heard us refer to this as the Ovintiv Edge. Our liquids mix will continue to increase in 2020, which increases our margin. Our outlook has liquids making up 56% of our total estimated production or 200 basis points higher in 2019. At our size, this represents the addition of about 4 million barrels of liquids produced in calendar 2020. This is meaningful since it translates to more than $120 million of incremental cash flow. Our focus on capital efficiency is driving improved performance, and we expect to deliver 4% oil and condensate growth in 2020, with a significant reduction in capital. When compared to 2019, we are budgeting $175 million less capital. Recall that in 2019, we had a $75 million third-party carry capital in the Montney. Our strong hedge book gives us confidence in our cash flow outlook. For 2020, we have over 70% of our expected oil, condensate and natural gas production hedged. We have created tremendous scale in our business today, and believe this gives us a distinct advantage to manage the volatility in our sector. Here, we show 2020 consensus estimates for liquids production and EBITDA for our peers in the S&P 400 and 500. We ranked near the top in both lists, and are one of the largest independent producers on both liquids production and EBITDA generation. We are a crude and condensate-focused company. It makes up more than 70% of our liquids production. We don't invest into our legacy gas assets but run those parts of our business incredibly efficiently. Our multi-basin portfolio and deep unconventional experience gives us an edge to drive innovation in reservoir development, cost performance and supply chain management. This is demonstrated by our continuous improvement in capital efficiency year after year. We believe that we have the key ingredients today that will consistently create value over time. World class execution, when coupled with scale, is a winning combination. Priority one in 2019 was effectively integrating our Newfield acquisition. This meant ensuring that we quickly achieved our targeted G&A synergies and rapidly reduced well cost in the Anadarko. Not only did we achieve these targets, we beat the annualized G&A synergies by 60% and nearly doubled the expected well cost reductions. This took hard work at every level and from both companies, and today, we are clearly one team. We know the importance of returning cash to owners and have an established track record of doing so. In 2019, we lived within our means, generated free cash, bought back 13% of our outstanding shares and funded a 25% increase in our dividend and grew our crude and condensate production by 9%. I'll now ask Greg Givens, our COO, to talk about a few of our operating highlights in 2019.

In 2019, the Permian team delivered once again and grew crude and condensate production by 10%, with a load leveled 4-rig program. This highly efficient operation generated $209 million in upstream operating free cash flow in 2019. We continued our track record of exceptional drilling performance, and the team beat their own pacesetter lateral performance 5 times in the quarter. Average spud to rig release now sits at less than 11 days, and our overall cycle times continue to improve. Our penetration rates are more than 20% faster than our Midland peers. Driving down cycle times are critical for several reasons. First, it shifts revenue earlier in time, which increases returns. It also results in lower cost because many of the services in our business are billed by the number of days on location. And finally, it means we get the results from each cube sooner, so we can apply the learnings across our operations more rapidly. In addition to outstanding operational execution, our supply management team continues to generate additional savings. Over the last two years, we've seen a 10% reduction in drilling and completion costs. In 2019, we had about a third of our total activity in Howard County. Our recent Howard results have been strong and have outperformed our expectations by more than 10% over the first 6 months of production. Although the majority of our program will continue to be in Midland, Martin and Upton counties, we expect to focus roughly a third of our 2020 development in Howard. We are running 5 rigs in the Permian today, and expect our oil and condensate volumes to grow 10% or more again in 2020. Let me give a quick update on the performance in the Anadarko Basin, all of which was covered in great detail on our recent Anadarko webcast. If you haven't reviewed that deck, it's on our website, it tells a great story of cost reduction and competitive returns. The Anadarko generated $263 million in upstream operating free cash flow in 2019. This makes the Anadarko the largest contributor of free cash in our company. To summarize, in the first year, we took $2 million out of our STACK well cost, double the original target. And we're not done. Four recent pacesetters in the play have achieved drilling and completion costs of 2 point - $5.2 million. We have doubled returns and made the STACK competitive with all other plays today, both in our portfolio and across the industry. In the Anadarko, we saw 18% crude and condensate growth over last year, with fourth quarter production of 164,000 BOE 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 of the deal closed in February to five rigs in the fourth quarter. We’ve recently drilled a 9-day pacesetter well, and drilling rates through the lateral were over 60% faster than our previous best-in-class well. Our completion performance has been equally impressive, with continued improvements on frac efficiency, leading to a 35% reduction in our well cycle times. The improvements we've made in the STACK are now being applied to SCOOP. In a recent cube in the SCOOP, we took the drilling days down 20%. We have an active 2020 plan in the SCOOP, and expect to see continued cost reductions as we apply our learnings from the STACK and other basins across the organization. Our oil and condensate production in the Montney increased 27% over the previous year. The Montney generated $199 million in upstream operating free cash flow in 2019. The Montney's rapid growth was driven by a step change in liquids deliverability when compared to the 2018 program. We optimized spacing and increased completion scope by 50% with no additional capital per lateral foot. Our program was focused on the liquids portion - liquids-rich portion of the fairway, which resulted in the average 2019 Montney well producing greater than 70% more condensate in the first 180 days compared to 2018. The returns from the play were further strengthened by our industry-leading cycle times. Overall, the improvements to the Montney program are resulting in less than 2-year payouts. Our objective will remain much the same in 2020 as we continue to focus on the condensate fairway and begin to prepare for the additional processing capacity coming our way in Pipestone in early 2021. Our base assets play a vital role in our portfolio today. They are comprised of high-value oil-producing properties, which generated some of the strongest returns in our portfolio. For 2019, these assets, the Eagle Ford, Bakken, Uinta and Duvernay, produced more than 75,000 barrels per day of liquids, and generated a combined $283 million of upstream operating free cash flow. We manage these assets for cash flow generation. Our drilling program results are highly repeatable and are typically more front-end loaded to capture operational efficiencies. As a multi-basin operator with scale, we've adopted a culture of continuous innovation, with the ability to rapidly transfer our learnings across the company. This can be seen both in the Bakken and the Eagle Ford, where significant cost reductions continue to be realized after multiple years of operating in these plays. I will now turn the call back over to Doug to close out.

Thanks, Greg. I think as you can see from our continued strong results, we've significantly enhanced our business with a focus on crude and condensate, selling nonstrategic assets, reducing leverage and commitments and creating a strong multi-basin portfolio with significant scale. We're proud of our track record. We delivered ahead of our promises across the board through disciplined capital allocation and operational excellence, and we've returned more than $1.7 billion to our shareholders over the last 2 years. We have a proven ability to manage risk through the cycle. Our strategy is delivering strong corporate level performance. We believe this is sustainable on the road ahead, and our plan will create compelling value by generating both free cash flow and growth. If prices are lower, we have almost unlimited capital flexibility, and we will prioritize free cash flow over growth. On the flip side, if prices are higher, we will not accelerate growth. We will see additional free cash flow expansion and accelerated delevering. Our results are the product of our quality asset base and our great teams. Thanks for your investment in our company and we'd be more than happy to take your questions. Operator?

[Operator Instructions] Your first question comes from Arun Jayaram with JPMorgan. Your line is open.

Yeah, good morning, Doug. I was wondering if you could give us a little bit more detail on Slide 22, on the percentage CapEx breakout by area. And maybe help us characterize, given at current strip prices, what the relative returns look like in the big 3 areas? And perhaps maybe you could discuss that on a payback basis in terms of - what are the paybacks in investment looking like in the Anadarko, Permian and Montney?

Yes. No, thanks for the question. I think what you can see is that now, essentially since we've level loaded the Anadarko program, I think Greg highlighted that when we closed the transaction, Newfield have been running 11 rigs, and we've now rebased that to a more continuous program and kind of 5 to 6 rigs now. So I think what you're seeing is a very balanced approach to distributing capital across the portfolio. And another question we commonly get is, is well, how's the performance of capital across that asset base and as we've consistently indicated is, it's very, very similar. Wealth and ability to predict. They all get there in a different way. Places like the Montney have very low cost and very low royalties, which - and of course, they produce a product which sells for the price of crude oil. Where as we move into places like the Permian, we have a higher percentage of oil in the product mix, but the costs are higher, and the royalties are higher. So what we see, Arun, across the portfolio is very similar financial performance. And whether we look at that on a returns basis or we look at it on a payout basis, they're all - at mid-cycle pricing, they're all generating something around 50% return in payouts in the 2-year-or-less window.

Great. And my follow-up is, I'm wondering if you could discuss, call it, the oil price breakeven. Doug, you mentioned in the press release, it's less than $52. I was wondering if you could give us a sense of what that number is on a post-hedge and a pre-hedge kind of basis.

I must admit, I don't have all those numbers in my head right now. I can tell you, though, that if you look out in time, in a $50 world, this business can continue to grow and generate free cash. So it's not just about a hedge book in 2020. We believe that's sustainable. And depending on how you define breakeven, we could keep this business flat, continue to fund the dividend and maintain cash flow neutrality well into the 40s.

Great. Thanks a lot.

Your next question comes from Gabe Daoud with Cowen. Your line is open.

Thank you. Good morning, Doug and everyone. Just - and I appreciate all the details so far. I was just wondering if you could maybe give us a sense of capital and production trajectory throughout 2020. I'm just wondering if we should expect a bit - a little bit of lumpiness as we've seen in years past.

Yes, Gabe. Great question, and Greg kind of touched this briefly, where once again, as we focus on capital efficiency, which, by the way, by our benchmarks, if you look at our capital efficiency on crude and condensate growth, it's amongst the very best in the industry. And we're doing that in a multi-basin portfolio and it competes even with single basin players. But to make sure we get those levels of efficiencies in our smaller assets; we tend to have to front-end load the program. In other words, we've talked about this in the past, it's more efficient to run 2 rigs for 6 months than 1 rig for 12. So it will mean that we'll have a bit more capital in the first half of the year than the second half, which is pretty similar to recent years.

Got it. Thanks, Doug. And then, I guess, just as a follow-up, can you talk a little bit about how you view the portfolio today? And then general thoughts on how you look at inorganic opportunities against the capital allocation framework that you've laid out?

You know, Gabe, we have a - I think we tried to touch it on the call, we've got a very strong portfolio. As you know, we've been committed for a long time to the multi-basin approach. We think, obviously, you can see that the industry has largely followed us, that there are very few single basin players left in the sector, particularly as people recognize the importance of scale. But we've got a very long runway. I think we highlighted what happened with reserves year-over-year and the depth of it. So I think our focus is about executing incredibly efficiently over what we have, and actually using the free cash we generate, as Corey highlighted, to move ourselves over the next couple of years to our target of 1.5 times net debt-to-EBITDA.

Got it. Thanks, Doug.

Your next question comes from Greg Pardy with RBC Capital Markets.

Thanks, good morning. Is there any update just on the implementation of wet sand in the Anadarko, now that's something you've been working on?

Yes, thanks for your question, Greg. We've been continuing to work at optimizing all of our operations across the portfolio and some of the highlights that we talked about in our Anadarko day are continuing to progress. We're continuing to see really good results in driving down cost in that basin, which make it competitive with, not only the rest of our portfolio, but the rest of industry.

Yes, it sounded like kind of like a non-answer, but that's okay.

Well, yes, Greg, I'd just add, I think we kind of highlighted even at the Anadarko day that, in areas we're now seeing delivered sand as low as less than $0.03 a pound. And that - and what's interesting, we recognize the supply chain has to, over time, make money. Otherwise, it's not sustainable. And the wet sand idea is a really cool idea, because it reduces the cost of a sand supplier, because they do spend a lot of money actually drying the sand. And of course, as you know, then we bring it out to our location, and we mix it up with water again. And I think as we've shared with you, this was an idea that was hatched between our supply chain organization and our operations folks. And we actually patented the idea. So if other people want to do it, the nice thing is they get to pay us royalty in doing it. But it's been one of the things we've done to continue to drive capital efficiency. And yes, we are looking at using it in places beyond the Permian and now the Anadarko.

Okay, perfect. And you mentioned the four pacesetter wells at $5.2 million. Do you have more? Is $5.2 million now the number that we should start thinking about in terms of D&C on a go-forward basis in the Anadarko?

Greg, I should buy you a beer for that, because now I get to help set another target for Greg and his team. But I'm not - we're not quite ready to say that's going to be the average well, but I also believe that it's not going to be our best well either, that there's more potential similar to everywhere else. And it's actually very exciting to think that, in the course of literally 12 months, we've taken well costs from $7.9 million to $5.2 million. But I think as we go through the year, you're going to continue to see the average move there in the pacesetter go below that point.

Okay, terrific. And maybe just the last one for me is on the Uinta. I know you've been in appraisal mode. Could you comment around maybe what the appraisal activities are this year? And then I know you don't typically like to talk about A&D, but maybe just some broad comments around whether that market is beginning to thaw [ph] and whether we could - whether it would be reasonable to expect at some point that, that could move out of the portfolio?

Well, yes, Greg. And actually, this kind of ties back to Gabe's question. So we've got an 8-well program in the Uinta this year, which is testing and appraising how these wells will perform in development mode. So it's - we're actually doing a cube there today. Because actually, on an individual well basis, if you follow the play, there's been some very strong wells drilled, upwards of over 2,000 barrels of oil a day. The question is, can you actually sustain that performance as you develop in a cube? Because this is a STACK play environment like places like the Permian. And like we've done elsewhere; the results will determine where this ultimately sits in the portfolio. But we're very focused now. This isn't about trying to grow oil production. It's about appraisal, and it's a very disciplined program. The good news is it will actually, we believe, generate competitive returns even in that role. But if you think about it, by the time we get those results, those wells online probably late 2Q, then as similar to what we did in the San Juan, we'll then have to see what their sustained performance look like. So that decision is still some time out.

Okay, terrific. Thanks very much.

Your next question comes from Josh Silverstein with Wolfe Research. Your line is open.

Thanks. Good morning, guys. I just had a couple of questions on the balance sheet. A few things right now, you've seen a lot of debt refinancing going on, particularly amongst the investment-grade producers and they are getting rates in the 4% to 5% range, and you guys have plenty of notes in the 6% to 8% range. So I just wanted to see what the hurdle is there to doing some refinancings to lower your interest expense that way?

Josh, Corey here. So I mean, obviously, we're paying close attention to what's happening in the market, and some of the producers are getting good refi rates. Obviously, the - as I alluded to, the bond trading prices are at a premium. So really for us, with lots of liquidity and generating free cash, it's a good option to watch. But we haven't committed to what that looks like, I think, for us. As we keep demonstrating growth and free cash and having good credit, we can see the better side of some of those rates relative to what we have today. But because our bonds trade at a premium, there is upfront cost to doing that. So that's kind of the trade today. I guess, I'd just point out, too, that our next maturity isn't until mid-November 2021. So we've got some time to decide that.

Great. Thanks. And then, I guess, still just on the debt side, and maybe from a strategic standpoint, I think you mentioned previously in the past that, to hold the fourth quarter liquids volumes flat, it would be around a $2 billion spend. And so what's one of the key priorities - the key priority to get your balance sheet down to that 1.5 times leverage ratio? Why don't you just go there today, the growth rate is below where peers are today, so why not just go to the maintenance level just to accelerate that deleveraging?

Yes, you know, Josh, if you kind of do the math, and this is kind of why I highlighted the incremental cash flow from the growth, we actually look at the best trajectory to get there is actually to do this modest growth with free cash generation. You actually get there faster than going in the way you proposed. And given a combination of our confidence in 2020 cash flows, and as Corey said, we have a $4 billion credit facility, which is rock solid, we have a commercial paper program, we have an investment grade debt, we have a business that grows and generates free cash, we think this balanced approach is not only the fastest way to get there, but it's actually the best way to get there.

Got it. Thanks guys.

Your next question comes from Brian Singer with Goldman Sachs. Your line is open.

Thank you. Good morning. You discussed the CapEx trajectory a bit, being a bit more front-end loaded earlier. Can you talk a little bit about how we should think about the quarterly production trajectory, particularly on oil, given some of the volatility in CapEx and also the timing of when you would expect some of the cube pads [ph] to come on?

Yes, Brian. What you're going to see is a small decline from 4Q to 1Q, just because these activities came down in the fourth quarter. And then you'll see us grow through the balance of the year. It's a good question there. I don't expect a lot of production growth because, as you saw, even in 4Q, we had strong volumes. Even though in places like the Anadarko, I think, we had 25 wells turned in line. So a really modest number. But you should expect a small decline in 1Q and then growth beginning in 2Q as the program, the effects of the start-up here in the first quarter show up in the production volumes.

Great, thanks. And then my follow-up is with regards to some of the productivity and cost efficiency outlook in the Permian Basin. Can you talk about how you see that in 2020 through the life of the well, do you see any changes in what we would expect or what we should expect from your well productivity or type curve? And the same on the cost side, which is, is there scope? And what do you see as the scope for further cost efficiencies and cost reductions in the Permian?

Yes. I think when you look, we show continued gains, and Greg kind of mentioned as we show that capital efficiency will continue to get stronger and stronger even as we go from '19 to '20. Most of that is driven off cost, but as Greg highlighted, in places like Howard County, we've actually had stronger well results than we had predicted. And we're constantly working on that. But today, we have greater line of sight to capital efficiency gains from further cost improvements. I mean, if you look at it, and we've discussed this with the big drilling companies, we have the fastest spud TD times in the industry in the basin, actually by a long way, not a short way. And that drives cost reduction. We're still seeing it. I think the one thing that people have missed is the value of shorter cycle times. And much of what we pay for in this industry, we pay for by the day. So the less days it takes to get the total project completed, from the first time you show up on location till the time you leave and turn on production, you actually lower cost. You also get learnings a lot faster, which means you can constantly tune your programs and optimize them going forward. But we still see that continuing. And by the way, it's not really driven off. Service cost deflation is really driven by greater and greater execution is what's driving it.

Great. Thank you.

Your next question comes from Neal Dingmann with SunTrust.

Good morning, all. Doug, my first question is on operations, financial priorities, specifically. You all continue to generate healthy free cash flow. So just wondering, any change of thoughts on how to prioritize either stock or debt repayment, just shareholder return in general versus incremental growth, either - really Permian or any other place?

Yes. And I think we're pretty clear on this today, is that we do want to get to our leverage target at mid-cycle prices of 1.5 times. So that's where we're focusing free cash today, is to get to that point. But we actually see we'll get there by actually having a modest crude and condensate growth. We've been talking about for a while that somewhere in the mid- to upper single-digit growth range is the right zone. We obviously have almost complete ability to flex around that number and respond to market conditions. But today, the priority and the use of free cash is to the balance sheet.

That makes sense. And then just one last one. Secondly, could you speak to the depths - your thoughts today about your depth of your Permian inventory, more specifically, sort of comfortable with the level now based on the plan and operations? Thank you.

Yes. No, that's a great question. And a couple of things. Last year, we had a very strong year. I think we replaced, across the portfolio, 40% of what we drilled by just doing swaps and trades, by taking acreage that we probably wouldn't develop because it wouldn't meet our premium criteria and with swaps and trades across the company. A lot of it was in the Permian, but it's across the company. I think we replaced 40% of the wells we drilled. So without spending a single dollar, we replaced 40% of the inventory we drilled. And when we look at how we develop in the Permian, this is why we've challenged - consistently challenged this idea of up-spacing is the right way to manage development doesn't make any sense. Now it does if you've obviously developed too tightly. But if you're not approaching, we call it cube, others call it co-development, you're fundamentally creating a problem for your inventory down the road. Because we haven't done that, and we've been consistently following a proven approach, what it means is, we have more inventory on less acres than other people do, and we've secured that going forward. So I feel quite comfortable that, for a long time, we'll continue to grow the Permian rates similar to what we've seen with the acreage we have today.

Thanks so much, for details.

Your next question comes from Jeffrey Campbell with Tuohy Brothers. Your line is open.

Congratulations on the quarter. Doug, Slide 10. Maybe you've kind of touched on this a little bit, but I just wanted to ask this. On Slide 10, the 2020 production guidance shows modest liquids growth and a decline in natural gas. I was just wondering, are there any specific areas within the portfolio that are being prioritized to create this mix?

Yes. No, well, it is - it's interesting, when we plan the business and model the business, literally gas is just an outcome. What we're targeting is efficient crude and condensate growth. So that actually is - the fact that it's down or essentially flat is just the result of where we're putting the capital today. And what you see is - is when we've talked about it, it's really about the capital efficiency of the ability to grow the liquids production, but recognizing certain things like differences in royalties across the different regimes. I mean, it's one of the reasons why, even though, obviously, we produce less condensate per well or less high-quality liquids per well in the Montney than other areas, but these are actually very low-cost wells and they have a much lower royalty rate and basically have incredibly low operating costs. So that's how they get to that point. So that's what it's driven by. By the way, NGLs are the same thing. We don't target NGLs, they're an outcome of the plan to efficiently grow crude and condensate.

Okay. Thank you. On Slide 14, I was just wondering, what's the average lateral length in the STACK these days? And how do the pacesetter wells compare lengthwise?

When we talk about these numbers, it's all on a 10,000-foot lateral. That's what we target. And that's essentially what we're averaging out there, it's 9,800, 9,900 feet. But that's a 10,000-foot lateral on the cost we've been quoting.

Okay. And if I could sneak one last one. Going back to the Uinta, our understanding was that the area has historically had some transportation issues. I'm just wondering if that's something else to tackle if the appraisal effort passes muster.

Yes, Jeff, it's a really insightful question. If you go talk to refiners, they will tell you this is probably the most valuable crude in North America because of the product slate that comes out of it. But because of where it sits, you actually don't get a price that reflects that. So as we think about appraising that asset, Renee and her team are also doing a lot of work about, how do we actually get the true value of that product? And at this point, we're not prepared to talk about what we're thinking about there. But we're working it hard, because we think that, that could add more than $10 a barrel on the price of the crude received out there by thinking about that. So when we think about appraisal, clearly, the subsurface has to work, but we also want to get something considerably better than today's price for that crude.

Okay. Well we'll look forward to hearing more about that when you're ready to discuss it. Thank you.

Your last question comes from Richard Tullis with Capital One Securities. Your line is open.

Thanks. Good morning, everyone. Just two quick questions Doug, so our recent analysis points to really healthy returns for your Eagle Ford acreage; I realize that's a much smaller position than your core areas. But based on year-end reserves review, what's your remaining locations inventory in the Eagle Ford?

Yes, that's a great question. Recently, we went back - and you may remember, we entered the Eagle Ford in mid-2014, and we went back and looked at our analysis of what we thought that asset would do over time. And today, by that analysis, you'd be producing half of what it's producing today and would have no remaining locations left to drill. So today, it's producing twice what we forecast it would be. And at the time, we said there were about 400 wells to drill, and we still say there are about 400 wells to drill. And of course, a lot of that comes from - it's in the best part of the Eagle Ford. You can see today, a lot of our acreage that we're focused on now is what's called the Graben. We clearly had some technical challenges early, but we've been chipping away at that, as has a few other people in the industry, and we've seen some very strong results recently. So when we look at that asset and think it continues to have similar scale or very small decline and generate a lot of free cash flow going forward. It's also, as you know, got very high margins in that asset because it's got great product mix, you can receive good prices for all the products relative to what's available across North America.

Thank you. That's helpful. And last item, housekeeping, what's the oil component in the 2020 guide of the 229,000 to 239,000 a day oil plus condensate?

It's roughly 80%.

Okay. Alright, that’s all for me. Thank you.

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

Thanks, operator, and thank you, everyone, for dialing in this morning. We sincerely appreciate your investment in our company and look forward to seeing you on the road very soon. Have a good day.

This concludes today's conference call. You may now disconnect.