Q4 2019 Earnings Call

February 20, 2020

Doug Suttles: Thanks, Corey. As we've said a few times today already, we expect that 2020 will be our 3rd 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 than 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.

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 all vintage of Dot com.

Doug Suttles: 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 hit 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 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 rank near the top in both lists and are one of the largest independent producers on both liquids production and EBITDA generation.

Before we get started today. Please take note of the advisory regarding forward looking statements founded 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 US GAAP and report our financial result.

It's in US dollars. So references this morning to dollars mean us 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.

Ill now turn the call over to our CEO Doug Suttles.

Thanks, Stephen Good morning, everyone and thank you for joining US. We finished 2019 very strong and are off to a great start in 2020.

Doug Suttles: 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 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.

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 Bruce.

And Mccracken, our executive Vice President of corporate development, an external relations Cory code, our Chief Financial Officer, Gregg Givens, our SVP and Chief Operating Officer, David Hill, who is our SVP and head of exploration in Renasant block Who's our EVP and head of marketing and midstream.

Please note that we plan to reference to slides, we issued yesterday and we will take your questions. After our remarks.

We believe that old vintage defines the new MP and our 2020 outlook, we will discuss for the two days 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 so.

Doug Suttles: This took hard work at every level and from both companies, 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 low-leveled full 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 five times in the quarter.

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 achieved this strategic outcomes that we target for our business.

Our assets are top tier we have scale in 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 in proprietary data set this leaves us with a long runway of future opportunity.

Greg Givens: In 2019, the Permian team delivered once again and grew crude and condensate production by 10% with a low-leveled full 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 five times in the quarter.

And this is a key advantage.

We have a culture of operational excellence, which extends across all aspects of our business, including ISG, our use of cutting edge technology in our unrelenting unrelenting focus on innovation has positioned us as an industry leader everywhere, we operate in lastly, but very important in today's volatile commodity price.

Doug Suttles: 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 costs because many of the services in our business are built by the number of days on location. 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 1/3 of our total activity in Howard County.

Greg Givens: 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 costs because many of the services in our business are built by the number of days on location. 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 1/3 of our total activity in Howard County.

Environment, we have shown our ability to effectively manage risk. This is part of our sustainable business model that is yielding superior results through the 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 some of the highlights.

Both our financial performance at the corporate level and our operating performance at the field level for excellent in 2019, the earmarked 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 600.

Doug Suttles: Our recent Howard results have been strong and have outperformed expectations by more than 10% over the first six 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 five 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 in 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.

Greg Givens: Our recent Howard results have been strong and have outperformed expectations by more than 10% over the first six 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 five 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 in 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.

And $15 million, 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 two times annual production.

And you can take a look at our reserve information in todays deck as well as in our 10-K, which will be filed later this week.

Certainly one of the most significant highlights with the quick and successful integration of our Newfield acquisition closed just over one year ago, we rapidly cut well costs in the Anadarko and demonstrate our ability to implement proven practices from other areas into a new region.

Doug Suttles: To summarize, in the first year, we took $2 million out of our STACK well cost, double the original target. We're not done. Four recent pacesetters in the play have achieved drilling and completion costs of $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 Q4 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 Q4. We recently drilled a nine-day pacesetter well, and drilling rates through the lateral were over 60% faster than our previous best-in-class well.

Greg Givens: To summarize, in the first year, we took $2 million out of our STACK well cost, double the original target. We're not done. Four recent pacesetters in the play have achieved drilling and completion costs of $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 Q4 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 Q4. We recently drilled a nine-day pacesetter well, and drilling rates through the lateral were over 60% faster than our previous best-in-class well.

The play as competitive across our portfolio and industry.

In a savings nearly doubled our original target and when combined the best and brightest of both organizations to form one team.

Our business model is sustainable and we have unique combination of profitable liquids growth and free cash generation.

We're one of the largest producers of high value crude oil and condensate and over the last two years returned $1.7 billion to our owners.

Let's look a little closer at our 2019 summary results. Our release has all the details unhelpful 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 81 cents per share.

During the year, we returned $1.25 billion of cash to shareholders through our share buyback program.

Doug Suttles: 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.

Greg Givens: 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.

Said another way, we bought back about 13% to for 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% is pardon me increased to 60% liquids and totaled approximately 2.2 billion be Lee.

And our total proved reserve life index has grown to more than 10 years.

Fourth quarter total production was 593000 barrels of oil equivalent per day, including crude and condensate production of 226000 barrels per day.

Doug Suttles: Our program was focused on the 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 two-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 generate some of the strongest returns in our portfolio.

Greg Givens: Our program was focused on the 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 two-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 generate some of the strongest returns in our portfolio.

This ranks as one of the largest crude and condensate producers in the sector today.

Pro forma total production was at the upper end of our revised guidance at 589000 barrels equivalent oil per day, including crude and condensate production of 228000 barrels per day, our crude and condensate volumes were up 9% year over year adjusted for asset sales.

Our pro forma liquids production was 317000 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 will hitting our original capital plan of $2.8 billion on a pro forma basis.

Doug Suttles: 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 it out.

Greg Givens: 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 it out.

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 5000 believes that day.

Before I hand, the call back to Doug.

Want to reinforce the confidence we have in our balance sheet.

First of all our businesses sustainable and we're generating free cash flow for a third straight year, while growing our high value of 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.

Greg Givens: 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 non-strategic assets, reducing leverage and commitments, and creating a strong multi-basin portfolio with significant scale. We're proud of our track record. We've 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 an 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.

Doug Suttles: 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 non-strategic assets, reducing leverage and commitments, and creating a strong multi-basin portfolio with significant scale. We're proud of our track record. We've 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 an 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.

We've recently renewed our credit facilities. The total 4 billion with a maturity date of July 2024.

These credit facilities have only one 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 base covenants. There is no quarterly determinations and no leverage coverage ratios. The 4 billion credit facility capacity is set for the next four and a half 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 borrowings.

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.

Greg Givens: On the flip side, if prices are higher, we will not accelerate growth. We will see additional free cash flow expansion and accelerated delivery. Our results are the product of our quality asset base and our great team. Thanks for your investment in our company, and we'd be more than happy to take your questions. Operator?

Doug Suttles: On the flip side, if prices are higher, we will not accelerate growth. We will see additional free cash flow expansion and accelerated delivery. Our results are the product of our quality asset base and our great team. Thanks for your investment in our company, and we'd be more than happy to take your questions. Operator?

We remain committed to our 1.5 times leverage ratio target just to be clear our balance sheet is not at risk.

Ill 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.

Operator: Ladies and gentlemen, as a reminder, you can join the queue to ask questions by pressing star one. We will now begin the question-and-answer session and go to the first caller. Your first question comes from Arun Jayaram with J.P. Morgan. Your line is open.

Our capital will again be targeted to specific programs that drive our long term trajectory generating profitable if liquids growth improved capital efficiencies lower cost strong returns.

Arun Jayaram: 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 three areas. Perhaps maybe you could discuss that on a payback basis in terms of what are the paybacks and investment looking like in the Anadarko, Permian, and Montney?

In growing margins.

We have high confidence in our ability to consistently innovate to deliver results you've heard us refer to this as the event of edge. Our liquids mix will continue to increase in in 2020, which increases our margin our outlook has liquids, making at 56% of our total estimated production or 200 basis points higher.

More than 2019 at our size. This rep represents the addition of about 4 million barrels of liquids produced in count in calendar 2020. This is meaningful since it translates to more than $120 million of incremental cash flow.

Doug Suttles: Yeah. 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 had been running 11 rigs, and we've now rebased that to a more continuous program at kind of five to six rigs now. I think what you're seeing is a very balanced approach to distributing capital across the portfolio. Another question we commonly get is, Well, how's the performance of capital across that asset base? As we've consistently indicated, it's very, very similar. Wealth and the ability to predict. They all get there in a different way. Places like the Montney have very low cost and very low royalties. Of course, they produce a product which sells for the price of crude oil.

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 29 team, we're budgeting a $175 million less capital recall that in 2019, we hit a 75 million.

$1 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 distinct advantage to manage the volatility in our sector here. We show 2020, consistent consensus estimates for liquids production in EBITDA for our appears in the S&P 405 hundred we rank near the top in both live.

Doug Suttles: Whereas 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. What we see running across the portfolio is very similar financial performance. Whether we look at that on a returns basis or we look at it on a payout basis, at mid-cycle pricing, they're all generating something around 50% return in payouts in the two-year or less window.

And our one of the largest independent producers on both liquids production and EBITDA generation.

We are crude and condensate focused company it makes up more than 70% of our liquids production, we don't invest into our legacy assets assets were run those parts of our business incredibly efficiently.

Arun Jayaram: Great. My follow-up is I was wondering if you could discuss, call it the oil price break-even. Doug, you mentioned in the press release it's less than $50, too. 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.

[music].

Our multi basin portfolio and deep unconventional experience gives us an edge to drive inner 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.

Doug Suttles: 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. It's not just about a hedge book in 2020. We believe that's sustainable. Depending on how you define break-even, we could keep this business flat, continue to fund the dividend, and maintain cash flow neutrality well into the '40s.

It will consistently create value overtime world class execution, when coupled with scale is a winning combination.

31 in 2019 was effectively integrating our newfield acquisition. This meant ensuring that we could we quickly achieved our targeted gionee synergies and rapidly reduced well costs in the Anadarko.

Not only did we achieved these targets we beat the annualized DNA synergies by 60% and nearly doubled the expected well cost reductions.

Arun Jayaram: Great. Thanks a lot.

Doug Suttles: Yep.

Operator: Your next question comes from Gabe Daoud with Cowen, your line is open.

This took hard work at every level and from both companies and today, we are clearly one team.

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

We know the importance of returning cash to owners and have is having 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%.

Doug Suttles: Yeah, Gabe. Great question. 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. We're doing that in a multi-basin portfolio, and it competes even with single-basin players. 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 two rigs for six months than one rig for 12. 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.

I'll now ask Gregg Givens, our COO to talk about few of our operating highlights in 2019.

In 2019, the Permian team delivered once again grew crude and condensate production by 10% with a load leveled four rig program.

This highly efficient operation generated $209 million and upstream operating free cash flow in 2019.

We continued our track record of exceptional drilling performance and the team beat their own pace setter lateral performance five times in the quarter.

Average flowed to rig release now sits at less than 11 days and our overall cycle times continued to improve.

Our penetration rates are more than 20% faster than our Midland peers.

Gabe Daoud: Got it. Thanks, Doug. 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?

Driving down cycle times are critical for several reasons first it's just revenue earlier in time, which increases returns. It also results in lower cost because many of the services in our business are built 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.

Doug Suttles: You know, Gabe, I think we tried to touch on 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's largely followed us, that there are very few single-basin players left in the sector, particularly as people recognize the importance of scale. We've got a very long runway. I think we highlighted what happened with reserves year-over-year and the depth of it. 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 EBITDA.

In addition to outstanding operational execution, our supply management team continues to generate additional savings over the last two years, we've seen the 10% reduction in drilling 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 expectations by more than 10% over the first six months production.

Although the majority of our program will continue to be in Midland Martin an upturn counties, we expect the folks to focus roughly a third of our 2020 development that Howard.

We are running five 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 Havent review that Doug It's on our website and told a great story of cost reduction and competitive returns.

Gabe Daoud: Got it. Thanks, Doug.

Operator: Your next question comes from Greg Pardy with RBC Capital Markets, your line is open.

Corey Code: Thanks. Good morning. Is there any update just on the implementation of wet sand in the Anadarko? I know that's something you've been working on.

Greg Pardy: Thanks. Good morning. Is there any update just on the implementation of wet sand in the Anadarko? I know that's something you've been working on.

The Anadarko generated $263 million and upstream operating free cash flow in 2019.

Doug Suttles: 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.

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 stock while cost double the original target and we're not done.

For recent Pacesetters in the play of achieved drilling and completion costs of 2.5 point $2 million.

Arun Jayaram: Yeah. Greg, this is a yeah. It sounded kind of like an on-answer, but that's okay.

Greg Pardy: Yeah. Greg, this is a yeah. It sounded kind of like an on-answer, but that's okay.

We have doubled returns and made the stack competitive with all other plays today, both in our portfolio and across the industry.

Doug Suttles: Well, yeah, Greg, I'd just add, I think we kind of highlighted even at the Anadarko day that in areas where now seeing delivered sand is low as less than $0.03 a pound. What's interesting, we recognize the supply chain has to, over time, make money. Otherwise, it's not sustainable. 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. Of course, as you know, then we bring it out to our location, and we mix it up with water again. I think, as we shared with you, this was an idea that was hatched between our supply chain organization and our operations folks. We actually patented the idea.

In Anadarko, we saw 18% crude and condensate growth over last year with fourth quarter production of 164000 Boe per day.

During the second half of the year, we maintain flat production levels and a consistent oil and condensate coat. Despite dropping from 11 rigs at the time of the deal closed in February to five rigs in the fourth quarter.

We recently drilled a nine 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 wells cycle times.

The improvements we've made in the stack are now being applied to skew.

Doug Suttles: If other people want to do it, the nice thing is they get to pay us a royalty as doing it. It's been one of the things we've done to continue to drive capital efficiency. Yes, we are looking at using it in places beyond the Permian and now the Anadarko.

In a recent Cuban the Scoop, we took the drilling days down 20%.

We have an act of 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.

Corey Code: Okay. Perfect. You mentioned the four-pay center 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 DNC on a go-forward basis in the Anadarko?

Greg Pardy: Okay. Perfect. You mentioned the four-pay center 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 DNC on a go-forward basis in the Anadarko?

Our oil and condensate production in the Montney increased 27% over the previous year, the montney generated $199 million and upgrading operate to upstream operating free cash flow in 2019.

Doug Suttles: You know, Greg, I should buy you a beer for that because now I get to help set another target for Greg and his team. 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. 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. I think as we go through the year, you're going to continue to see the average move there and the pacesetter go below that point.

Commodities rapid growth was driven by a step change in liquids deliverability when compared to the 2018 program.

We optimized spacing and increased completions 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 our industry leading cycle times overall, the improvements to Montney program are resulting in less than two year payouts.

Corey Code: Okay. Terrific. 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? 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 and whether it'd be reasonable to expect at some point that that could move out of the portfolio.

Greg Pardy: Okay. Terrific. 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? 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 and whether it'd be reasonable to expect at some point that that could move out of the portfolio.

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 and pipestone in early 2021.

Our base assets play a vital role than our portfolio today. They are comprised of high value oil producing properties, which generate some of the strongest returns in our portfolio.

Doug Suttles: Well, yeah, Greg. Actually, this kind of ties back to Gabe's question. 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. We're actually doing a cube there today. Actually, on an individual well basis, if you followed 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? This is a stack pay environment like places like the Permian. Like we've done elsewhere, the results will determine where this ultimately sits in the portfolio. 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.

For 2019 these assets the Eagle Ford Bakken you went to undo Renee produced more than 75000 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 Eagle Ford were significant cost reductions continue to be realized after multiple years of operating in these place.

Ill 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 non strategic assets, reducing leveraging commitments and creating a strong multi basin portfolio with significant scale.

Doug Suttles: The good news is it'll actually, we believe, generate competitive returns even in that role. If you think about it, by the time we get those results, those wells online, probably late Q2, then similar to what we did in the San Juan, we'll then have to see what their sustained performance looks like. That decision's still some time out.

We're proud of our track record we delivered delivered ahead of our promises across the board through disciplined capital allocation and operational excellence and we've returned more than one set $1.7 billion to our shareholders over the last two years, we have an approved we have a proven ability to manage risks through the cycle.

Corey Code: Okay. Terrific. Thanks very much.

Greg Pardy: Okay. Terrific. Thanks very much.

Doug Suttles: Yep.

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

Josh Silverstein: Hey, thanks. Good morning, guys. 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're getting rates in the 4% to 5% range. You guys have plenty of notes in the 6% to 8% range. Just wanted to see what the hurdle is there to doing some refinancings to lower your interest expense that way.

Our strategy is delivering strong corporate level performance. We believe this is sustainable on the road ahead in 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 de levering.

Corey Code: Hey, Josh. Corey here. Thanks for the question. 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, as I alluded to, the bond trading prices are at a premium. Really, for us, with lots of liquidity and generating free cash, it's a good option to watch. 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. Because our bonds traded at a premium, there is upfront cost to doing that. 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. We've got some time to decide that.

Our results are the product of of our quality asset base and our great team.

Thanks for your investment in our company and would be more than happy to take your questions operator.

Ladies and gentlemen, as reminder, you can join the queue at your last question by pressing Star. One we will now begin next question answer session and go to the first caller. Your first question comes from Aaron Jairam with Jpmorgan. Your line is open.

Yes. Good morning, Doug I was wondering if you could give us a little bit more detail on slide 22 on the percentage.

Capex a breakout by area.

And maybe help us characterize given.

Current strip prices.

What the relative returns look like in the big three areas and perhaps maybe you can discuss that on a payback.

Josh Silverstein: Great. Thanks there. I guess still just on the debt side and maybe from a strategic standpoint, I think you've mentioned previously in the past that to hold the Q4 liquids volumes flat, it would be around a $2 billion spend. With one of the key priorities or the key priority to get your balance sheet down to that 1.5x leverage ratio, why not just go there today? The growth rate is below where peers are today. Why not just go to the maintenance level just to accelerate that deleveraging?

Of basis in terms of one of the paybacks and investment looking like in Anadarko Permian and Montney.

Yes, no. Thanks for the question I think I think what you can see is that now essentially since we build 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 rebase that to a more continuous program that kind of five to six rigs now so I think what youre seeing is a very balanced approach to distributing capital across the portfolio and another question we common.

Doug Suttles: Yeah. 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. 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 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, it's actually the best way to get there.

Only get his will house the performance of capital across that asset base and as we've consistently indicated is it's very very similar wealth inability 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 produced a product which sells for the price of crude oil.

Whereas we move into places like the Permian we have.

Higher percentage of oil in the product mix, but the costs are higher in the royalties are higher so what we see a run across the portfolio is very similar financial performance and whether we look at that on our returns basis or we look at it on a payout basis Theyre all of.

Josh Silverstein: Got it. Thanks, guys.

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

At mid cycle pricing Theyre, all generating something around 50% return and payouts in the two year or less window.

Corey Code: Thank you. Good morning. You'd 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 paths to come on?

Brian Singer: Thank you. Good morning. You'd 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 paths to come on?

Great and my follow up is I'm wondering if you could discuss.

Call it the oil price of breakeven Doug you mentioned on the press release Thats, it's less than 52 I was wondering if you could give us a sense of what that number is on a on a.

Post head and our pre hedged kind of basis.

Doug Suttles: Yeah, Brian. What you're going to see is a small decline from 4Q to 1Q just because those activities came down in Q4, and then you'll see us grow through the balance of the year. 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. You should expect small decline in 1Q and then growth beginning in 2Q as the program, the effects of the startup here in Q1, show up in the production volumes.

Oh 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 in a 50 dollar 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 in defending.

On how you define.

Breakeven, we keep this business flat continue to fund the dividend.

Maintain cash flow neutrality well into the Fortys.

Great. Thanks, a lot.

Yep.

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

Corey Code: Great. Thanks. My follow-up is with regards to some of the productivity and cost efficiency outlooks 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? The same on the cost side, which is, is there scope? What do you see as the scope for further cost efficiencies and cost reductions in the Permian?

Brian Singer: Great. Thanks. My follow-up is with regards to some of the productivity and cost efficiency outlooks 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? The same on the cost side, which is, is there scope? What do you see as the scope for further cost efficiencies and cost reductions in the Permian?

Thank you good morning, Doug and everyone. Just an appreciate all the detail. So far was just wondering if you kid.

Maybe give us a sense of capital and production trajectory throughout 2020.

Just wondering if we should.

Expect a bit a little bit of Lumpiness.

As we've seen in years past.

Yes, I gave great question in and Greg kind of touch. This briefly were 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 its amongst the very best in the industry and we're doing that in a multi basin portfolio and it competes even with single.

Doug Suttles: Yeah. I think when you look, we show continued gains, and Greg kind of mentioned this, we show that capital efficiency will continue to get stronger and stronger even as we go from 2019 to 2020. Most of that is driven off cost. As Greg highlighted, in places like Howard County, we've actually had stronger well results than we had predicted. We're constantly working on that. 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-to-TD times in the industry in the basin, actually by a long way, not a short way. That drives cost reduction. We're still seeing it.

Based on players, but to make sure we get those levels of efficiencies in our smaller assets, we tend to half dub to front end load. The program in other words, we've talked about this in the past its more efficient to run two rigs for six months than than one 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.

Okay.

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 in general thoughts on how you look at right now inorganic opportunities against the capital allocation framework that you've laid out.

Doug Suttles: I think the one thing that people have missed is the value of shorter cycle times. Much of what we pay for in this industry, we pay for by the day. The less days it takes to get the total project completed from the first time you show up on location to the time you leave and turn on production, you actually lower costs. You also get learnings a lot faster, which means you can constantly tune your programs and optimize them going forward. We still see that continuing. By the way, it's not really driven off service cost deflation. It's really driven by greater and greater execution is what's driving it.

You know gave we have a and I think we tried to touch 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's largely followed us that there are very few single based employers left in the sector [noise].

Equally is as people recognize the importance of scale, but we've got a.

A very long runway I think we highlighted.

What happened with reserves year over year.

In 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.

Corey Code: Great. Thank you.

Brian Singer: Great. Thank you.

Operator: Your next question comes from Neal Dingmann with SunTrust. Your line is open.

Corey Code: Morning, all. Doug, my first question's on operations and financial priorities. Specifically, you all continue to generate healthy free cash flow. Just wanted 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 of your place?

Neal Dingmann: Morning, all. Doug, my first question's on operations and financial priorities. Specifically, you all continue to generate healthy free cash flow. Just wanted 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 of your place?

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. Your line is open.

Thanks. Good morning, if there is there any update just on.

Doug Suttles: Yeah. 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. That's where we're focusing free cash today, is to get to that point. We actually see we'll get there by actually having 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. Today, the priority and the use of free cash is to the balance sheet.

The implementation of 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 the 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 our continuing to see really good results and driving down cost and that basin, which make a competitive with not only the rest of our portfolio, but the rest of industry.

Yes, Greg.

Yes, it sounded like kind of like on all unanswered, but that's okay, well, yeah, Greg I'd just add.

Corey Code: That makes sense. Then just one last one. Secondly, could you speak to the depth, 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.

Neal Dingmann: That makes sense. Then just one last one. Secondly, could you speak to the depth, 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.

Yeah, I think we kind of highlighted even at the Anadarko day that in areas. We're announcing delivered sand is low is less than three cents, a pound that and whats interesting we recognize the supply chain hast overtime make money otherwise, it's not sustainable in the wet sand idea is a really cool.

Doug Suttles: Yeah. No, that's a great question. 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. With swaps and trades across the company, a lot of it was in the Permian, but it was across the company. I think we replaced 40% of the wells we drilled. Without spending a single dollar, we replaced 40% of the inventory we drilled. When we look at how we develop in the Permian, this is why we've consistently challenged this idea of upspacing is the right way to manage development, doesn't make any sense. Now, it does if you've obviously developed too tightly. If you're not approaching we call it cube.

Hi idea because it reduces the cost of the sand supplier.

Because they do spend a lot of money actually drawing the sand and of course, it's as you know than we bring it out to our location and we mix it up with water again.

I think as we shared with you. This was an idea that was hatch between our supply chain organization in our operations folks.

And we actually patented to the idea. So if other people ought to do it. The nice thing is I get face royalty is 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 at using it in places.

Beyond the Permian and now the Anadarko.

Okay, perfect and and you mentioned the four pacesetter wells at 5.2 million.

You have more is 5.2 million now the number that we should start thinking about in terms of DNC on a go forward basis in the Anadarko.

Doug Suttles: 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. I feel quite comfortable that for a long time, we'll continue to grow the Permian at rates similar to what we've seen with the acreage we have today.

You know Greg I should buy you bear for that does not get to help set another target for Greg and his team.

I'm not I'm, not we're not quite ready to say thats going to be the average well, but I'm also believed that it's not going to be our best well either that there's more potential.

Similar to everywhere else and.

It's it's 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.

Corey Code: Thanks so much for details.

Neal Dingmann: Thanks so much for details.

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

Jeffrey Campbell: Good morning and congratulations on the quarter. Doug, slide 10. You've kind of touched on this a little bit. 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?

But I think as we go through the year Youre going to continue to see the average move there in the pace at or go below that point.

Okay terrific and maybe just the last one from me is on the Uinta.

I know you've been an 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 Andy but maybe just some broad comments around whether that market is beginning to to thought and whether we could you know whether it be reasonable to expect some point that that could move out of the portfolio.

Doug Suttles: Yeah. No, all 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. That actually is the fact that it's down or essentially flat is just the result of where we're putting the capital today. What you see is, and 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. That's how they get to that point.

Well, yes, Greg and actually this kind of ties back to Gabes question. So we've got an eight well program in the UN to this year, which is which is testing and appraising. How these wells will perform in development mode. So it's we're actually doing acute there today.

Because actually on an individual basis. If you followed the play there has been so very strong wells drilled upwards of over 2000 barrels of oil a day. The question is.

Can you actually sustain that performance as you develop.

In acute because this is a stack pay 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'll actually we believe generate competitive returns even in that come in that role but.

Doug Suttles: 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.

Jeffrey Campbell: 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?

If you think about it by the time, we get those results those wells online probably late to Q.

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

Then as similar to what we did in the San Juan will then have to see what their sustained performance look like said decisions still some some time out.

Okay terrific, thanks very much.

Yes.

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

Jeffrey Campbell: Okay. If I could sneak one last one in, going back to the Uinta, our understanding was that the area has historically had some transportation issues. I'm just wondering, is that something else to tackle if the appraisal effort passes muster?

Thanks, Good morning, guys a couple of questions on on the balance sheet.

Through the few things right now you've seen a lot of debt refinancing going on particularly in amongst the investment grade producers and they're getting rates in the 4% to 5% range and you guys have plenty of of nodes in the 6% to 8% range. So just wanted to see what the hurdle is there to to doing some refinancings to lower your interest expense that way.

Doug Suttles: Yeah. Jeff, that'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. Because of where it sits, you actually don't get a price that reflects that. As we think about appraising that asset, Renée and her team are also doing a lot of work about how do we actually get the true value of that product. 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.

Hey, Josh Cory here. Thanks for the question. So I mean, obviously, we're paying close attention to what's happening in the market in some of the producers are getting.

Good rifai rates.

Obviously, the as I alluded to the bond trading prices are at a premium so really for us the 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.

Doug Suttles: 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.

As we keep demonstrating growth and free cash and having good good credit we can see the better side at some of those.

Rates relative to what we have today, but because our bonds traded a premium there is upfront costs to doing that so that's that's kind of the the trade today I guess I'd just point out too that our next maturity isn't until.

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

Doug Suttles: Yep.

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

Richard Tullis: Hey, thanks. Good morning, everyone. Just 2 quick questions, Doug. 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. Based on year-end reserves review, what's your remaining locations inventory in the Eagle Ford?

Mid November 2021, so we've got some time to decide that.

Great. Thanks, There and then I guess still just on the debt side and maybe from a strategic standpoint I.

I think you mentioned previously in the past that to hold the fourth quarter liquids volumes fly that would be around a $2 billion spend.

Doug Suttles: Yeah. That's a great question. Recently, we went back. You may remember, we entered the Eagle Ford in mid-2014. We went back and looked at our analysis of what we thought that asset would do over time. Today, by that analysis, it'd be producing half of what it's producing today and would have no remaining locations left to drill. Today, it's producing twice what we forecast it would be. At the time, we said there were about 400 wells to drill, and we still say there are about 400 wells to drill. Of course, a lot of that comes from it's in the best part of the Eagle Ford. You can see.

And so with one of the key priorities are the key priority to get your balance sheet down to that one and a half times leverage ratio wanted just go there today. The growth rate is is below where peers are today. So what I just go to the to the maintenance level just accelerate that that deleveraging.

Yes.

Josh if you kind of do the math and this is kind of why I highlighted the incremental cash flow from the growth.

Yeah, 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 in and given the combination of our confidence in 2020 cash flows and his Corey said we have.

$4 billion credit facility, which is rock solid we have a commercial paper program.

We have 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 it's actually the best way to get there.

Got it thanks guys.

Your next question comes from Bryan singer with Goldman Sachs. Your line is open.

Thank you good morning.

You do you discussed the capex trajectory a bit BMR, but more front end loaded earlier can you talk a little bit about how we just think about the quarterly production trajectory, particularly on a on oil given some of the volatility in capex.

And also the timing of when you would expect some of the Q2 pads come on.

Yes, Brian what you're going to see is.

Small decline from Fourq you to one could you just because his activities came down in the fourth quarter and then you'll see us growth through the balance for the year.

So good question there.

Don't expect a lot of production growth because as you saw even in Fourq. You. We had we had strong volumes, even though in places like the Anadarko I think we had 25 wells turned in line. So really modest number but you should expect small decline in one Q and then growth beginning into Q.

As is 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 and with regards to some of the productivity and cost efficiency outlet and in the Permian Basin can you talk about how you see that in Twentytwenty.

Through the life of the well do you see any changes in a in what we would expect on what we should expect from your well productivity or or type curve and and the same on the cost side, which is.

Is there is scope and what do you see it the scope for further cost efficiencies and cost reduction and the Permian.

Yes, I think that I think when you look we show continued gains in Greg kind of mentioned this we show that capital efficiency will continue to.

To get stronger and stronger even as we go from 1920 most of that is driven off costs.

But as Greg highlighted in places like Howard County, we've actually had stronger well results than we had predicted in we're constantly working on that but today, we have greater line of sight.

Capital efficiency gains from further cost improvements I mean, you know if you look at it and we've discussed this was a big drilling companies, we have the fastest spud to TD times in the industry in the base and 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.

Must 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. So the time you leave and turn on production unit you actually lower costs. 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. Your line is open.

Good morning up I'm done my first questions on operational financial priority, specifically, you will 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 general versus incremental growth either really Permian or any of your please.

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 thats where were focusing free cash today is is to get to that point, but we actually see we'll get there by actually having modest crude and condensate growth we've been talking about for a while thats somewhere in the mid to upper single digit growth ranges. The ride zone, we obviously have.

Almost complete ability to flex around that number and respond to market conditions, but today the priority in the use of free cash is to the balance sheet.

Makes sense and just one last one secondly could you speak to the depths you your thoughts today about your depth of your Permian inventory more specifically sort of comfortable the level now based on the plan and operations. Thank you.

Yes, I know that's a that's a great question.

Couple of things last year, we had we had very strong year I think we replaced across the portfolio, 40% of what we drilled by just doing swaps and trades by by taking acreage that we probably wouldn't develop because wouldn't meet our premium criteria.

And with swaps and trades across the company a lot of it was in the Permian budgets 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 challenge that this idea of up spacing.

He is the right way to manage development doesn't make any sense now does if you've obviously developed to tightly but if you're not approaching we call at Cubo. This call. It co development you fundamentally creating a problem for your inventory down the road because we havent done that and we've been consistently following a proven approach what it means is we have more in inventory.

Yeah on less acres and other people do and we've secured debt 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 detail.

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

Good morning, and congratulations on the quarter.

Doug Slide 10, if kind of touched on this all that I just wanted to ask this slide 10, 2020 production guidance shows modest liquids growth and a decline in natural gas I'm. Just wondering are there any specific areas within the portfolio that are being prioritized to create this mix.

Yes, no while it is it's interesting when when we when we plan to business in 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 potentially flat is just the result of where we're putting the capital today.

And what you see is and we've talked about it it's really about the capital efficiency.

The ability to grow the liquids production, but recognizing certain things like differences and royalties across the different regimes and 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.

Have a much lower royalty rate and basically have incredibly low operating costs. So thats, 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 NGL is there an outcome of the plan to efficiently grow crude and condensate.

Okay. Thank you.

On slide 14, I'm, just wondering what's the average lateral lines on the stack these days and how to the pacesetter wells compare likewise.

Yes, when we talk about these numbers, it's all on a 10000 foot lateral that's what what we target and that's essentially what were averaging out there. It's 98 9900 feet, but that's a 10000 foot lateral on the cost we've been quoting.

Okay, and if I could sneak one last one now gone back to the Uinta.

Our understanding was it the area has historically had some transportation issues I'm just wondering is that something else to tackle if the appraisal effort passes muster.

Yes.

Jeff that's what's it's really insightful question if you.

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 give price that reflects that so as we think about appraising that asset Rene and her team are also doing a lot of work about how do we actually get the true value of that product in 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 where we think about appraisal clearly the subsurface has to work, but we also award to get something considerably better than today's price for that crude.

Okay, well look forward to hearing more about that one year ready to discuss it. Thank you.

Yep.

Your last question comes from Richard that tell us with capital one Securities. Your line is open.

Thanks, Good morning, everyone. Just two quick question Doug.

Recent analysis points to really healthy returns for 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 Eagle Ford.

Yes, that's that's a great question you know recently we.

We went back you may remember, we entered the Eagle Ford in mid 2014.

And we went back and look to our analysis of what we thought that asset would do over time.

And today by that analysis it'd be producing half of what it's producing today in 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 than we still say there about 400 wells to drill and.

Of course, a lot of that comes from its in the best part of the Eagle Ford.

You can.

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