Q2 2023 Occidental Petroleum Corp Earnings Call
Good afternoon, and welcome to Occidental second quarter 2023 earnings conference call. All participants will be in listen only mode should you need assistance. Please signal a conference specialist by pressing that Starkey followed by zero. After today's presentation, there will be an opportunity to ask.
Questions to ask a question you May Press Star then one on your Touchtone phone to withdraw your question. Please press Star then two please note. This event is being recorded.
I would now like to turn the conference over to Neil Backhouse, Vice President of Investor Relations. Please go ahead.
Thank you drew good afternoon, everyone and thank you for participating in Occidental second quarter 2023 conference call.
On the call with US today are Vicki Holt, President and Chief Executive Officer, Rob Peterson, Senior Vice President and Chief Financial Officer, and Richard Jackson, President operations U S onshore resources in carbon management.
Good afternoon, we will refer to slides available on the investors section of our website. The presentation includes a cautionary statement on slide two regarding forward looking statements that will be made on the call. This afternoon.
Also referenced non-GAAP financial measures today reconciliations to the nearest corresponding GAAP measure can be found in the schedules to our earnings release and on our website I'll now turn the call over to Vicki Vicki. Please go ahead.
Neil and good afternoon, everyone.
There are three things I'd like to drive home today.
Our portfolio of assets continued to set the table for record results.
Second our teams outperformed last quarters and last year's excellent operational metrics.
To make sure our investors see how that flows to the bottom line.
Third our strategic and operational improvements continued to support our ability to take actions to drive even better shareholder returns.
I'll begin with the portfolio we.
We had the highest quality and most complementary assets that I've seen has ever had.
They are a unique blend of short cycle high return shale assets in the Permian and the Rockies along with lower decline solid return conventional reservoirs in the Permian and our international assets.
60% of our oil and gas production is from shale reservoirs and 40% from conventional more than 80% of our production is in the United States.
International oil and gas assets that we operate are normally three countries.
One of the Dolby and Algeria.
Our worldwide full year 2023 production mix is expected to be approximately 53% oil, 22% Ngls and 25% gas.
70% of the gas is in the United States.
Our conventional oil and gas that's along with oxy can provide support during low price cycles, while the shell assets provide the opportunity for growth during moderate and high price cycles.
Our flexibility to adjust activity levels quickly if needed.
Combination of assets has generated record cash flows ROTC over the last couple of years versus the cash flow generated by the portfolio that we've previously had similar price environment from 2011 to 2014.
Midstream business provides flow assurance and has done so with exceptional performance during catastrophes in emergencies.
Hello, carbon ventures business will help us and others Decarbonize at scale in a way that provides incremental value to our shareholders.
To summarize we have a deep and diverse portfolio, providing the cash flow resilience.
<unk> built the necessary to support our shareholder return framework throughout the commodity cycles.
Let's shift now to operational excellence.
Strong second quarter operational performance exceeded the midpoint of our production production guidance by 42000 daily per day.
They bring us to again raise full year production guidance.
In the Rockies outperformance was driven by improved base production and new well performance along with higher than expected non operated volumes and a receipt of accumulated royalties.
Our Rockies teams drilled 32% faster on a per day basis than they did in the first quarter. The team's diligent work set several new Oxy records, including companywide record of drilling over 10400 feet of lateral and only 24 hours.
Just 10 years ago, it took the industry and averaging 15 days to drill 10400 feet.
Our Permian production delivered higher operability and better than expected, new well performance, particularly in our two new drilling spacing units in new Mexico hotspot impressions.
Our Delaware completions team shattered our previous record for continuous frac pumping time by nearly 12 hours.
Total of 40 hours and 49 minutes.
Four years ago, the same job would've taken about 84 hours.
What are the hours back then was unthinkable, but our teams have made this a reality.
We expect that the efficiencies generated by advancements in drilling and completions pumping will result in lower cost and reduce time to market.
Offshore in the Gulf of Mexico, we safely completed the seasonal maintenance activities focused on asset integrity and longevity.
Excluding the impacts of this planned maintenance, we delivered higher base production and benefited from improved uptime performance across multiple platforms.
Internationally, our teams continued to deliver strong results.
C L. Hudson expansion came online two months earlier than planned.
Result of Great team work with our partner add Marc.
This means that together, we have now successfully expanded the planning stages from one Bcf a day to 1.45 Bcf a day or very small incremental capital investment.
Hello, Martin Bloch 65, we drilled a near field exploration, well, which delivered 6000 daily per day, and a 24 hour initial production test.
And it is now on production to sales and less than a month from completion.
This was our highest AUM on initial production test in the decade, and we continue to show the benefits of our subsurface characterization techniques worldwide.
We were awarded the block in 2019 and in collaboration with the Ministry of Energy, we are positive about opportunities in the country, where we are the largest independent producer.
I'll take him also outperformed during the second quarter due to greater than expected Brazilian the price of caustic soda and reductions in feedstock prices.
I'll take him as one of our valuable Differentiators. It provides rich diversification to our high quality asset portfolio are consistently generating quarterly free cash flow, which provides a balance of our oil and gas business throughout the commodity cycle.
Now I'd like to talk about how our focus on operational excellence is enhancing our portfolio and extending our sustainability to maximize near and long term shareholder returns.
These wells are getting stronger and are supported by our deep inventory, which continues to get better.
Ian we have improved well productivity and seven of the last eight years.
The application of our proprietary subsurface modeling, we're starting to see the same results in the D J basin.
Improved well designs have delivered reserves at roughly 20% less cost.
The improved well design has resulted in about 25% improvement in single well 12 month cumulative volumes over the last five years.
So where we are on pace to significantly exceed that rate in 2023.
In addition, our teams are continuing to advance our modeling expertise, which has led to upgrades of secondary benches to top tier performers.
This was a key for our 2022, sorry, 212% U S organic reserves replacement ratio last year.
Let me try to make that point again [laughter].
Last year.
Because of these upgrades to our secondary benches to like top tiered benches, we were actually able to do.
Replace our production by 212% with reserve adds.
Secondary bench upgrades are progressing in 2023.
Overall in 10 of the last 12 years.
Have replaced 150% to 230% of our annual production.
Only exceptions being in 2015 with a price downturn in 2020 with the pandemic.
Converting lower tiered benches to top tier will further extend our ability to achieve higher production replacement ratios.
Not only are we adding more reserves than we are producing each year, we're adding reserves at a finding and development cost that is lower than our current DD&A rate.
Which will drive D D now you're down in earnings.
Our differentiated portfolio and the strong results delivered by our teams provided support for execution of our 2023 shareholder return framework.
The second quarter, we generated significant free cash flow.
425 million common shares and have now completed approximately 40% of our $3 billion share repurchase program.
On share repurchases, along with our dividend enabled additional redemptions of the preferred equity to date, we've redeemed approximately $1 2 billion of preferred equity.
I'll now turn the call over to Rob.
Thank you Vicky and good afternoon, everyone.
During the second quarter, we posted an adjusted profit of 68 cents per diluted share and reported a profit of 63 cents per diluted share.
This is between our adjusted and reported profit was primarily driven by our parents for undeveloped noncore acreage and deferred tax impacts from the Audrey a production sharing contract our PSC rule.
Partially offset from an environmental remediation settlement.
In the second quarter strong operational execution enabled over $1 billion of free cash flow for working capital despite planned maintenance activity across several of our oil and gas businesses.
Following nearly $1 billion of preferred equity redemptions and premiums $445 million of subtle common share repurchases and approximately $350 million really the ltvs investment net power, which include the second quarter of approximately $500 million unrestricted cash.
We experienced a positive working capital change during the second quarter, primarily driven by reductions in commodity prices and fewer barrels and ship it over quarter end.
Interest payments on that are generally paid semi annually in the first and third quarters, which also contributes to a positive second quarter working capital change.
During the second quarter, we made our first U S. Federal cash tax payments this year up $210 million and state taxes of $64 million, which were netted out of working capital.
We anticipate a similar federal cash taxes, when we made it in subsequent quarters. This year the state taxes are paid annually.
Our second quarter effective tax rate increased from the prior quarter due to a modest change in our income jurisdictional mix.
Proportion of international income, which is subject to a higher statutory tax rate grew during the second quarter.
We were therefore guiding to a minimum adjusted effective tax rate of 31% for the third quarter.
Our effective tax rate going forward will be more closely aligned with the second quarter rate.
I will now turn our to our third quarter and full year guidance as Vicki just discussed our technical and operational excellence continues to drive outperformance across our oil and gas businesses.
This has enabled us to raise our full year production guidance mid point, just over $1 2 million barrel per day anticipation of a strong exit to the year.
Rockies out as much service the largest catalyst our full year production guidance range and is also a primary driver in a slight change to our for your oil mix guidance.
Reported production of Rockies is expect to reduce its lowest point this year in the third quarter before beginning to grow in the fourth quarter.
The Gulf of Mexico, we were guiding to slightly lower production in the third quarter compared to the second quarter due to contingency for seasonal weather the third quarter weather contingency as well as planned maintenance opportunities brought forward to reduce downtime or expect the result of our highest domestic operating costs between basins here when normalizing to less than $9 50 sets for viewing.
The fourth quarter.
Internationally, we expect higher production compared to the first half of 2023 due to plant turnaround and expansion project timing as well as impacts from various international production sharing contracts.
As we have previously mentioned the increase your NASA production will be slightly offset by the new Algeria, PSC, which decreases the reported production, but the reduction of imported barrel is not expected to have a material impact on operating cash flow.
Overall, the first half of 2023 was characterized by strong production in the Gulf of Mexico, Permian and Rockies with latitude business is also benefiting from nonrecurring production of it.
Good better anticipated wells and time to market momentum year to date, which we expected.
Getting from in the second half of the year.
Third quarter will be the only quarter in the year, where we production averaged below $1 2 million Boe per day.
Reduce production is mainly driven by the previously mentioned weather continues to be applied to the Gulf of Mexico. The decrease in third quarter production will likely result in total company production was lower in the second half of the year when compared to the first.
However, the change in expected production does not represent a shift in our volume trajectory, we anticipate fourth quarter production will be similar to the first two quarters of 2023, and we expect to enter 2024 with a strong production cadence.
Furthermore, our full year guidance implies a fourth quarter oil cut of approximately 53% largely due to improved gone production absent a third whether whether contingency.
Shifting now to oxy, Kevin as anticipated in our original guidance, we continue to see weakening of PVC and caustic soda pricing during the second quarter.
However, our full year guidance remains unchanged at a pre tax income midpoint of $1 5 billion, which would represent our third highest pretax income ever and another strong year for oxy Kim.
We also expect our chemicals business to return to a more normalized seasonality compared to recent years means that the fourth quarter will represent the lowest earnings for the year as we have mentioned on previous calls the fourth quarter is typically not a reliable roll forward for the year ahead due to the inherent seasonality in the business.
Yeah.
We've revised our full year guidance from Michigan and marketing due to expected market changes over the second half of this year the margins generated by shipping crude from Midland to the U S. Gulf Coast are expected expressed further following the annual FERC tariff revision, which has increased our pipe cost approximately $2 55 per barrel over.
Over the same period of pricing to market long haul capacity is expected to decrease. Additionally, we anticipate fewer gas market opportunities as spreads across multiple basins have continued to narrow or opportunities generated in the first quarter.
Also pricing for sulfur produce al Hogan is expected to soften in the second half of the year.
Capital spending during the quarter was approximately $1 $6 billion, we expect capital a slight decreased slightly in the third quarter with a more pronounced the reduction in the fourth quarter. The expected decrease was primarily driven by reduced working interest and gross activity in the Permian, which is in alignment with the original business plan.
We anticipate receiving $350 million during the fourth quarter associated with the second quarter and Barbara remediation settlement. While this settlement will drive up reported overhead down our full year guidance of overhead expense on an adjusted basis remains unchanged.
Turning now to shareholder returns as Vicki mentioned, we further advanced our shareholder return framework during the second quarter and to repurchase $425 million of common shares which enabled additional preferred equity redemptions.
After a strong start in the first quarter, we triggered the redemption of over $520 million of preferred equity in the second quarter.
Year to date <unk> been approximately $1 2 billion or 12% of our preferred equity that was outstanding at the beginning of the year with 10% premium payments to the preferred equity holder or approximately $117 million.
Preferred redemptions to date have resulted in the elimination of over $93 million of annual preferred dividends.
As of August 2nd Rolling 12 month, common short distributions totaled $4.08 per share.
Due primarily to the concentration of share repurchase in the third quarter of 2022, coupled with the current commodity price curve is likely that the cumulative distributions will fall below $4 per common share during the third quarter.
We dropped below the $4 different trigger our ability to begin redeeming the preferred equity again will heavily be influenced by commodity prices.
The API price would likely need to be higher than what the forward curve presently indicate restaurant rain above the trigger for the remainder of 2023.
Even if we are unable to continue redeeming the preferred equity for a period of time, we remain committed to our short term program, including our $3 billion share repurchase program.
Our basic common share count is now the lowest since the third quarter of 2019, it's already in our per share earnings and cash flow accretion to our common shareholders.
Sustained efforts to significantly deleverage over the past several years have improved our credit profile culminated in a return to investment grade status when Fitch ratings upgraded oxy in may.
We believe that our investment grade credit range reflect our exceptional operations.
First of all is a high quality asset portfolio and our commitment to pay down debt as it matures.
Our second quarter results and our full year guidance demonstrates solid progression towards another strong year for oxy look forward to reporting additional progress as the year advances I will now turn the call back over to Vicki.
Thank you Rob.
Before closing today, we'd like to briefly mention to low carbon ventures announcements that we made this week.
We're glad to announce that Japan.
A N a airlines became the first airline in the world to sign a carbon dioxide removal credit purchase agreement from IRA subsidiary 1.5.
We're excited about that and happy to work with them.
Also pleased to announce a first of its kind agreement with our long standing partners add not evaluate investment opportunities and direct air capture and carbon dioxide question sequestration hubs in the U S and the U a E.
With this agreement we intend to develop a carbon management platform that will accelerate our shared net zero goals.
Many exciting developments taking place in L. T D and we look forward to providing you a more comprehensive update towards the end of this year.
That we will now open the call for questions.
We will now begin the question and answer session.
Ask a question you May press Star then one on your Touchtone phone. If you are using a speakerphone. Please pick up your handset before pressing the keys.
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Please limit questions to one primary question and one follow up.
If you have further questions you may reenter the question queue.
At this time, we will pause momentarily to assemble our roster.
The first question comes from Doug Leggate with Bank of America.
Please go ahead.
Oh, Thanks, good morning, good morning, everyone.
Vicki I wonder if I could.
I'm focused on.
Activity.
Which you know your latest slide deck, you're showing you referred to as the wedge wells.
Would that quite frankly stunning step up in performance relative to prior years.
My question I guess is is the repeatability of that on the impact on how you think about your strategy because then to summarize.
You've suggested you would not seek to grow production meaningfully.
If I'm interpreting that correctly, but this productivity would suggest that either you're going to drill production as you did with your step up in guidance.
Youre going to cut your capital budget to hold the production slots or level. So I'm curious are you prepared to take the production or is it going to get more capital efficient with lower capex.
Well, we intend to keep our capital plan as we had it or at least the activity plan as we had it.
I can tell you Doug I'm incredibly impressed with what our teams have done.
You know I've been in this industry for a very long time and I've seen them.
Lot of extensive work done to model conventional reservoirs over the years and when we started our shale development. Some thought it was more of a statistical play where you're just going to drill 100 wells and maybe 25% of it would be really good and 75% would be okay, but we took the time and.
2014 to step back and say that we were going to put together a team that could do to kind of work that needs to be done in shale, it's much more complex than conventional.
So we we really focused on trying to make sure that that we've put together a team that could do it.
The most sophisticated work on the subsurface possible in and they've done incredibly.
Incredibly well and I would say in the past two to three years.
Thinking that we were getting close to a plateauing on our learnings and what we can do but the teams continue to surprise me continue to go beyond what I thought we would ever be able to do in this industry with respect to not only understanding the subsurface as well as we do but but also.
Being able to understand how to get the most oil out of it and so where we are today is I have now asked the teams to stop talking about it.
We for years, where we're sharing things that we're doing and we've shared some things on the slides in the slide deck, but but they had prepared a lot more to share with you today.
To highlight and and map out the pathway that we're using to get to where we are but it's just too important to our company inside into our shareholders too.
To keep that proprietary because this is something that's pretty phenomenal I think in <unk> now.
Now, we're taking this and we're going to apply it to the Permian I went to the powder River basin or using that they've done incredibly well in the Permian. We've also taken learnings from the team and the D J and move those to the Permian. So we're sharing ideas across business units are the next one will be the powder River base.
And we're while we did take an impairment on some noncore areas. They we are excited about the powder River and I think Richard I'll say, a little bit more about that later, but instead.
Southern powder River and so we're seeing good results there and our appraisal team is beginning to work in the northern part of the the powder River and we're gonna take it also the same sort of concept about how to do it we want to take to other areas, but then oxy and we think that by using a similar methodology.
Oh with what our phenomenal team in the Gulf of Mexico has been able to do they've they've done amazing things in terms of being able to let's say below the salt and to improve our our success rate there, but I think you bet you bet. This subsurface team for our shale development.
The approach they take the methodology that they use with the ideas that are gone team has generated and start really exploiting the various strengths I think we take this and apply it to conventional reservoirs and applying this to conventional when the expertise that we have working those conventional reservoirs today I think that.
It would be even more cross those learnings from conditional to Sheldon Sheldon conventional I think it's a it's beyond what anybody in the industry.
I've seen or heard about it it is doing today, so but that said to get back to your question on capital and introduction, we're gonna them, we're going to execute our program.
It looks like it is going to result in a production increase and we're happy with that we never said that we didn't want to grow we just don't want growth to be the target, but the target is value creation in that value creation comes from doing the development.
We're ready to do them at the pace that that generates the most net present value and and our teams are doing that and they're doing it incredibly well. So we will take what we're getting here.
Okay.
I can say that you've got the answer. Thank you I've got a very quick follow up and it's kind of hard spiked as somebody who was talking about before which is that the legacy Anadarko portfolio. We know it dips in the second and perhaps the third quarter.
My question is when you rebound out of the fourth quarter for US is ordinarily the case and not profile.
You lost any production capacity do you what do you think the production capacity is today and presumably those are the highest margin assets in your portfolio I just wonder if you could confirm that so we can anticipate what happens to earnings and cash flow in Q4.
And then the legacy Anadarko assets are in the Texas, Delaware are I'm really really top tier we had when we were working to do the acquisition. When you that they were really good we thought they would come in and they.
Almost equal to our our southeast New Mexico.
I'm going to get myself in trouble here I think there. They they were I thought for a while better than southeast New Mexico, I think I happened to say that in the hallway, one day and the southeast New Mexico team decided they would prove me wrong on that so I would say that southeast, new Mexico, and Texas, Delaware above incredibly.
To us there.
High quality and they're both are part of our program going forward. Richard you had something bad yes, maybe just to help add onto that we can talk about assets in the portfolio and even.
Legacy Anadarko I think the Rockies trajectory, while very strong in the first half of the year I think whats impressive we talked about knowing we would decline kind of through the first half of the year and then grow and I think if you see on our guide for <unk> and then implied guide for <unk> that not only was the first half better but the circa.
Half was better as well.
All the new wells are.
You know certainly core how do we think about deploying capital and creating the efficiency I'd like to also recognize all of the team that works on our base production I think the Rockies is a great example of being able to.
Rethink our surface infrastructure, they've been able to kind of lead the industry I think in some of these tankless designs, but they've migrated to more efficient bulk in test they've been able to think about.
Artificial lift earlier things like gas lift earlier in the.
And the cycle of the well and a lot of that beyond creating the most EUR per dollar spent is really helping.
Our production and so when you look year on year that base production is another one that I think we're really proud of from the teams no doubt as this is the Permian and the in the Rockies in the Rockies actually applying artificial.
Intelligence to they their they're pops up there, which has been very very impressive and as well as the management of the gas lift in the.
Permian, Texas, and new Mexico. So if these are exciting things for us and learn we have two less definitely give kudos to the teams they've gone above and beyond expectations.
The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.
Yes.
So much I'm thinking team wanted to start off on the return of capital.
Just I was curious on your thoughts on on the commodity price level or the oil price level at which you believe you can get back to taking out the preferred and just in the absence of that how aggressive can you be around buying back stock.
Well.
Certainly we have the capability at almost any price environment, there, there's a lower limit to where we would probably not.
Too much share repurchases that $60.
But at 70 way, we could continue a common share purchase program.
And certainly at 75 and above we've got the cash to do both but well well we feel like with our current shareholder framework is that no share repurchases are a big part of that because our and common share repurchases because what we're really trying to do is we're trying to create value per share.
And for our investors.
And to create value per share. It does not only means that we need to grow production a bit again, that's the cash flow is the main thing we're trying to grow and when we're growing production and that's an outcome of our capital program. So this year, we will get incremental earnings growth from Hum.
Mental volumes, but also developing our reserves at the lower cost like we've talked about it and like I talked about in the script and like we've been talking about here, but the teams are doing that's so important is to develop reserves replace our production every year by at least you know 130% to 50% and again we've seen.
Ours up to 230%, where the DD&A or are they finding and development cost is $6 or less in some cases and and we were able to do that with the DD&A rate of what we have today.
Versus that that's that's creating value for our shareholders, creating earnings and then the last thing is two coupled with the cash flow growth and income growth from the volume creation and the reduced cost of those finding and development. Our reserves is to buy back shares and especially given the.
That we feel we're very undervalued right now.
Repurchases, whether or not it triggers the preferred is really important to us.
But in the near term level do is we will.
Probably a way to a little period of time here to watch what's going to happen with the macro and if it's the macro plays out the way we expect we should be able to do both to to buy common and to get back at some point within the next.
A few months to.
Doing that is buying are not only comment that triggering the preferred could take into next year before we're able to get a program going but we do believe that we can it at seven.
75 or above have a program that will do that.
Yes, and I'll just add to that.
Part of the challenge that we have as a program last year was very back end weighted we did $2 $4 billion of share repurchases.
Non traded across the second half of the year of $1 8 billion of that just in the third quarter alone and so I would say, it's the pace at which we were able to retire shares last year.
Matched up against the commodity price that we have this year, which really makes it difficult to stay about the four consistently.
Last year gas prices you realized over $7 in Q3 oil prices were $95 realized in Q3, and so that's a big change year over year that we're seeing.
Thanks, Thanks team and then as a follow up it's congrats on getting the outflows in gas expansion on this year.
Just would love any perspective or thoughts on on your middle East.
Is this and how we should think about the incremental cash flow associated with the asset that just came online.
Yeah, the al husband project.
Adding to the 1.45 Bcf a day at and very little capital I'd say definitely a good project for us and would that just having gotten that back on we expect that the certainly on the production are looking good towards the rest of this year from al Hudson.
And also the fact that lever in in Oman, unable to get an exploration well that was record setting for us online and to production in less than a month Oh. It was another good sign for us for healthy production coming out of the middle East.
We do have incremental opportunities in Oman, four additional wells that are similar to that and lock 65. So and then this year this past year.
And Ah soccer field in the North the Oman, we set production records there and that's the sale of its been in operation for over 40 years, and we're still finding you things to do there and also when I talk about innovation and subsurface modeling I know within and Richard brought up the guys that are worth.
Really hard on a base maintenance on base production. One I mentioned two that are there's been quite a bit of innovation coming out of Oman as well one being a process called Odyssey getting where we go into a you can do at the new wells are existing well to go in and jet through the formation.
And with that.
Proprietary process, we use there and get incremental production and that's part of the reason that we were able to achieve record production from that area. This.
This year, so a lot of good things happening in our middle East operations, and where as I mentioned in my script focused on three countries and we feel like it's best not to be spread over a lot of countries that too. We flagged. The fact that we are here in the U S. In three countries.
Countries internationally and will focus on being the best we can be in those areas and and eliminate or minimize distractions from anything else.
The next question comes from Neal Dingmann with Truest. Please go ahead.
Good afternoon, and thanks for the time it makes my question's on the Gulf of Mexico production and incremental operations continued to look quite solid and I was just wondering how would you classify just.
Current operating opportunities today in the golf and could we see any notable change in activity there in the coming quarters.
I would say that I have my my thoughts about the Gulf of Mexico are actually changed a bit over the past year. Originally when we made the acquisition or our plan was just too to keep production flat and and use the cash flow to invest elsewhere.
I do believe now.
Again based on the Tech technical excellence of our team working at AR and the and the fact that artificial intelligence I believe is going to be and advanced data analytics. I believe is gonna be a game changer for the Gulf of Mexico, and I believe our team has been the.
The capability and expertise to you optimize the use of those tools.
So I think that not this year or next year, but I do believe that looking forward in the next three to five years, the Gulf of Mexico could become more of a growth area for us rather than just a a cash generator.
That's great to hear I agree I like the opportunities there and then secondly, just you talked around this already but maybe just a little more details on your slide down on the D. J, maybe about just well spacing and completion design. There I'm. Just wondering have your thoughts you guys have been ramping that up and I'm. Just wondering as you as you have been ramping up at the thoughts on spacing and completion designs change going forward.
Word.
I think like in recent months I believe get us another pads or what about 12, well spacing and so I'm just wondering if theres any thoughts to change any of that.
Yeah.
Yeah great.
This is Richard I'll try to take a few pieces of that I mean, very excited about the DJ like I've described both the new well performance in the base, but I would say.
Consistent with really what we've done across our reservoir positions and especially in the unconventional really starts with the challenge on the subsurface in terms of.
All the things you described spacing.
Any wells per <unk>.
The teams continue to look.
At those opportunities and as we noted really thinking about less I think moving from 18 to eight to 12 wells per section you know allows us to deliver.
Same EUR for less cost.
Just like we've done in the Permian.
That's the right recipe, we have been able to use completions and really frac intensity to kind of turn up the lever.
To help capture those reserves without having to drill additional wells. So we've gone up to 500 pounds per foot, which is up about 30% I think from our prior designs as we think about spacing in inventory you know the thing I would say is you know not every drill spacing units the same so.
The geology changes the.
Development sequencing changes and so there'll be areas where that might be different.
Just.
Kind of contrast, a little bit we highlighted the.
The performing <unk> use in the in the Delaware Basin, and those are actually opportunities where.
We added a wells per section and we were able to do that again by looking at the unique attributes of that drill spacing unit against the reservoir.
We're cautious with that but.
We've been able to have real success, both horizontally and vertically.
Adding those wells, where it's warranted but.
Just the last maybe couple of points on the DJ again.
It's sort of a holistic design that the operations teams put together.
It's done a lot to reduce time to peak production, so eliminating those surface constraints, where they can really allow those wells to optimally flow.
And then you know as Vicki described longer term new these wells go from gas lift plunger lift and being able to use analytics to not only be quicker in terms of our optimization, but actually predict failure mechanisms. So that we can deploy operations teams quicker you know these are the top of <unk>.
Things are just really excited us about how our teams approach.
Really adding production at the right cost.
The next question comes from Michael Schiavone with Stephens. Please go ahead.
Yeah.
Yeah.
Thank you and good afternoon everybody.
You talked pretty extensively about the improving well productivity and I know a lot of companies have been talking about.
Service costs are softening here.
Looks like 'twenty 'twenty four consensus estimates right now anticipate you're going to spend about 4% more next year than you did this year.
Keep production flat with the current level. So no. It's too early to give guidance for 'twenty four but just wanted to get your your view on that outlook.
What we're seeing is we're seeing some things start to plateau in terms of cost.
Saying labor.
Labor being still a bit tight, but but there's a also around labor, though we're not seeing as many people wanting to change them jobs. It's just a matter of getting the skills that we need in the field and that's where the big challenge is to get truckers to drive trucks and people to do the in welding and in those.
To fill jobs are so important to us, but I would think that what we're not we're not while we're not saying.
Any reduction again as much reduction in service company costs, we don't expect that but I don't think we've settled on expecting any kind of increase next year.
And I can add maybe just a few I agree with Vicki I mean were you know one really pleased with the efficiency of our operations. That's always our focus and so really the rigs we've added over the last year and a half.
How about some of the kind of individual goals, but we're seeing productivity just from reduced nonproductive time improve.
Improved.
The efficiency of the operations continue.
But as we think about going into next year.
T G.
Seeing some relief, but that generally lags Sam.
Sand kind of similar.
And fuel obviously is a component which has been lower for us. So we're seeing those type of things come in a little bit lower but we've got you know really the opportunity to continue to work with the fleet. We have we're pretty steady operational pace at this point, which is very different where we've been the last couple of years and so for US it's really an opportunity to.
Trying to utilize that.
The resources, we havent really get that optimization down. So if we look next year, that's going to continue to be the challenge we hope.
There is some you know.
Pricing that can benefit both operator and service company as we look at longer term, but we're really anxious to keep working on the efficiency.
And Michael This is Neil I just wanted to add.
Well always encourage our coverage group not to rely too much on consensus for whatever time period as you know the further out it goes the more sales data that can be in there. So just continue to have the conversations with us.
At the appropriate time.
Got you I guess, just summing all that up though I guess based on those numbers that would suggest you'd need to spend more to keep production flat is it fair to say that that feels conservative based on what you know today.
I I I would say, we don't know that because we're continuing to to get more barrels I mean, just look at the graphs, where our teams are getting more production from.
From the wells for either.
Either the same or lower cost, where we're doing both we're increasing our efficiency ease of execution.
So getting more recovery out of the wells.
I don't think I'd be prepared to say that we'd have to spend more capital just to stay flat and we will look at that and again the efficiencies that are being gained I think you have to take all that into account and and bill them. We're starting to look at some of that now, but I've been impressed with what we've been able to do with the dollar should we still think of that I think.
We still have them for four our wedge of production the lowest capital intensity on a per barrel basis are in the industry I believe at least the last time, we checked it now we havent done that number in a couple of months and so what we do.
We need to check that again to know for sure.
I appreciate the detail on that that's all I wanted to follow up on your agreement with AD knock does that cover stratos.
Do you have any sense for what kind of capital of the company is looking to spend with you at this point.
It doesn't cover stratus, but it does cover other things and it could cover things that we currently have today not.
Not the first DAC at the at the King Ranch.
But what we had done as we put together a work group that worked with us and not too.
Can you talk about what the possibilities are for direct air capture and sequestration here in the United States versus all the Derby and the big focus was to to try to help each of us to achieve the goals that we've set out in the end I had not just set a another gulf for themselves to get to net zero.
About 2045.
They and their own emission they have.
And we also do and.
We can given the fact that we collaborated on them, making them building. The what is now the largest and what was it even at the time the largest ultra sour gas processing plant in the world ever.
Several companies that walked away from that that didn't want to try to attempt that so we have a track record of working with that not to do difficult things or to do things that are different than the software you sulfur recovery units and now husband, our serial numbers wondering for so that's that was a bold step for us and now we're taking this bolt.
Step two to go into looking to help each other and also to help our shareholders because the way we're doing this in a way that it's not going to be a cost for us for us over time is gonna be it's going to deliver returns and and had not focused on that as well so.
We have a very similar objectives.
Our objectives around all of how we're doing this and so the work team now will continue and start looking at sites here in the U S and the UAE and pick the one that's it gives us the best chance to ensure that right out of the gate, where we're starting with a good project.
The next question comes from Roger read with Wells Fargo. Please go ahead.
Yeah good morning.
I guess I'd like to follow up on some of the carbon capture you know we saw transaction occur.
I guess now about a month ago.
On.
Conventional sort of C O two E O R and I was wondering as you look at your own operations there.
Anything you can look at or are examining along those lines or have you had any inquiries from others about you know trying to expand the opportunity there.
Hum.
I can't comment too much on what what's happened, but I will say that there's probably not any.
Carbon capture or C. O two vor things that are happening in the U S or even worldwide that we don't follow very closely one of which we had followed probably for a few decades or at least a couple of decades.
But when we look at it we believe in.
And Richard can build on this.
The way we have now a structured what we're doing so that we can focus on the things that we do best and the things as we've talked about in this call. The things that we do best one understanding the subsurface and since we have our U C O two for EUR four mm for almost 50 years.
What we're doing now is it's just a different way a different kind of reservoir to put the C. O two into sort of different different type of modeling, but all of them. All the same work goes into it and all the same probably the same techniques and approach go into looking at how we handle the C O two and how we get it sequestered whether it's in an AOR reservoir in the <unk>.
<unk> or elsewhere or whether it's a N a saline reservoir. So that part of it is our expertise we don't really feel the need to own pipelines because pipeline returns are generally not the kind of returns that we can get with our dollars invested in and they either the upstream business or.
Our shell business or conventional so what we wanted to do is make sure that our capital dollars are going to the things that that we do best we are partnered with midstream companies and the sequestration hubs that we've developed and and again, but we do have as you mentioned and referred to.
Significant infrastructure and we do have 2500 miles of C. O two pipelines in the Permian robbery operating their 13th C. O two processing plants and so we have the basis to do a lot of work and a lot of sequestration in the Permian, where I think the Permian as a whole I think the they they capacity.
It's estimated to to be large enough to sequester all of the emissions from the United States for 28 years, and we have a big footprint in the Permian there are multiple zones, we can not only.
<unk> C O two for you or Beth or for straight sequestration. So we were doing partnerships that give us the.
That's returned and collaborating because theres going to be a lot of capital required for these projects over time.
And we don't want all of that capital coming from Oxy, obviously, we want other companies doing what they do best to Richard do you want to comment on some of the secrets Oh sure Yeah just buildup.
A minute I think.
Even and especially in our Permian and your Permian position, we continue to work many carbon capture opportunities. We continue to think because of that legacy position, we have especially in the subsurface that that's going to present.
Economic and real opportunity for us in our mirrors in terms of being able to capture and retired C. O. Two in terms of the Gulf Coast.
I know, we've talked about it before but I want to reiterate like Vicki said to be very focused on the sequestration of the subsurface piece of that that's really.
<unk> learned where we can best add value.
It's around that position and we have our.
Hubs that are going into the Gulf Coast, We've got.
Several of our class six wells better permitted and moving well through the.
Process may have up to six by the end of the year, we're drilling strat wells really in every hub continuing to be prepared.
We think.
These capture projects are going to be put together and come online over the next few years. So we we really think we are positioned to be the low cost.
Of sequestration.
Certainly.
Providing security realm, so youll too because of our history. So great partnerships with midstream companies, we've announced before and they are an important piece, but we're really focused on that both in the Permian and in the Gulf coast around really developing that subsurface for sequestration.
That's really helpful. Thank you.
The next question comes from Paul Cheng with Scotiabank.
Please go ahead.
Hi, good afternoon.
Micky and the team.
With the improvement that you've seen in the D. J, what should we expect from a cheap at the end of the production trajectory for the next several years in the past that Ah I think within limitation on the inventory or that may be concerned about regulatory ER that production.
That would be calling it should be assumed that the decline will continue but at a slower pace or that you think you may be able to do better than that.
First question.
Okay, I'll turn it over to Richard Richard than are actually looking at that up.
Closely sure Yeah, Let me, let me just kind of walk you through where we were this year. Obviously, we were significantly under invested the last couple of years.
You know coming out of the downturn really focusing capital on the shorter cycle, we really restored capital back back to the Rockies This year back to more <unk>.
Sustaining.
Levels, but the teams continue to outperform and so what really has happened. This year is a shallower decline in the first half of the year, we had expected growth in the second half of the year, but the growth is actually a bit better. So if you look at kind of where were at first half to second half I think we're growing about 6000 barrels a.
A day so the.
In terms of rigs we're running.
Capable run been running two capable for three.
And we continue to work on these well improvements to see really how that asset and that production competes for capital in our portfolio going into next year, but I think really the sort of the capital that you are seeing deployed in the Rockies.
This year it takes us from a decline into <unk>.
Really a flat to moderate low low end growth.
Oh rich can we assume that that's the minimum that you would be able to do for the next several years that flat to may be modest growth.
Look the teams have continued.
We challenge everybody, but I think the Rockies team have really done a great job on this.
Getting upfront in terms of land development permits really getting the <unk>.
Midstream position in place to be able to do more but again it needs to fit our capital allocation. So they do.
High returns even at lower gas prices. These are very competitive returns I would call them.
Bit longer cycle than the.
So the Delaware.
In Texas, but they also are a bit lower decline and so for us they fit really well, we will have capability to do more but it really needs to fit the sort of cash flow outcome that the company needs as we put capital together for next year, but we can do more as that fits.
The next question comes from Devin Mcdermott from Morgan Stanley . Please go ahead.
Hey, Thanks for taking my questions.
So I wanted to go back to Stratos. The first DAC plant in Texas, you've made some progress.
And contracting some of the offtake there I was wondering if you can just talk at a higher level on the demand that youre seeing for off take from that DAC facility and then I think signing offtake was one of the key factors driving some of the ranges and capital spending for lower carbon ventures. This year could you just talk about where we're trending within that range as well.
Yes, great.
I'll start with the C D. Our sales I think you know as we've.
<unk> continued to talk about.
We believe in the market and believe the really the formation and sales are following.
Our expectations I mean, clearly pleased with strategic strong strategic customers like a N a.
But recognize really the fit of our product, which is a CD or into a larger.
<unk> de carbonization, so while there.
We think about broadly sustainable aviation fuels, we feel like <unk> fit well into that market. So if you look at some of the equivalents.
Probably a better marked market in terms of sustainable aviation fuels. Those may range 800 to $1000 a ton and we believe we're going to settle in.
Into that market market well.
Really the key for us, though as we continue to talk is driving the innovation and cost down and DAC and so we remain focused not only the construction parts going on in Permian with Stratos, but also on our King Ranch development, but very pleased with the progress carbon engineering makes with their innovation.
It centers, so I didn't I didn't want to talk about just the market because we do believe that cost down and it's important for us.
To make this affordable long term.
The other Mark I'll give you just in terms of thinking about.
Sales and how to CVR spit on our price ranges.
In April .
European Parliament.
Put together.
Some things around requiring 2% SaaS mix, starting in 2025, and some of those penalties or $550 per ton of C. O. Two so when you look at how we can compete.
Directly offset that at a lower cost we think that's another mark there really helps us think about how we can be competitive.
Great. Thanks, and then just on the lower carbon spending and your plan. This year I think the offtake and the ability to finance off balance sheet was one of the swing factors can you just give us an update on that process as well.
Yeah, No I think look we remain optimistic that.
We're going to have good partners as we think about financing. This long term we've we've been.
Strong and our ability to be able to carry the near term, but we understand.
Longer term that we need financial partners.
Come into this with us and we continue to make progress.
Talk about the capital we've stayed with the range 200 to 600.
For the year and really that reflects that.
Room to bring in that capital partnership.
By the end of the year, so yeah, and I would say Devin I. Appreciate your interest and we will have a bit more of an update in November .
I want to get anybody to thinking into some sort of major announcement, it's not as just a and I'd say just like what Richard gave now because things are continuing to change with respect to demand for C. D ours and that sort of thing. So we'll give you a little more of that in November yeah, I think construction progress I should say, we're about 23.
I think today. So we'll have more construction progress we think we can point more to the market and just kind of follow up on that deep dive, we had last year kind of giving some updates on how these pieces come together.
In the interest of trying to allow a few others, who get questions in kind of a limit yourself to one question.
Next comes from Scott Gruber with Citigroup.
Please go ahead.
Yeah.
Yes. Good afternoon, just had one question just following up on that last point.
You know that a doctor in the U S is quite encouraging, but whether it's AD knock or another partner.
And in terms of just thinking about making that equity investment in DAC do the partners that you're talking with.
Do they want to see the learnings from Stratus manifests into lower capital and operating cost you know a DAC to a doctor either to pull the trigger on an investment or do you sense that you know just showcasing progress in constructing stratos and getting it up and running will be sufficient to attract equity funding into the program.
I would tell you that not all they know that our track record of building major projects and they they know Ken Dillon, well who's actually manages our major projects, so they've seen us and how we not only we're innovative in how we build how Hudson, but we were also innovated in this just racist.
Expansion to to expand the plant by almost 50%, we'd probably spend a way under 10% is phenomenal and so I think that add not we'll be prepared to move forward with us.
Sooner than waiting on what happens with the Stratus I think they all understand that technology is going through a cost down. It's there's never been a technology that that's worked and been adopted.
And a.
Large way without having gone through the same kind of thing that will go through with our with our direct air capture.
Yes, the only thing I would add there.
Definitely is different capital I think as we were able to move down that cost down over the next decade, we really you know.
Like the partner with strategics like add knock or others that can be a part of not only the near term, but the long term.
But obviously, we want to get.
The right value and set up the right economics for both parties as we bring them in and so I think of course long term.
We bring costs down in the market forms we expect that to.
Open.
Really capital and that's a big part of our ability to scale development.
So.
To answer your question, Yes, I do think that changes our presents more opportunities over time and one final comment on it is.
Partnering with AD not we know their capabilities and expertise to so we know what they bring to the table and so that's the other exciting aspect of this is having their knowledge their experience their expertise combined with ours to to do whichever we do or combination of both the C plus and the.
Direct air capture.
The next question comes from David <unk> with TD Cowen. Please go ahead.
Thanks, guys I'm going to try to ask one perfect question.
Thanks for squeezing me in.
Was curious you mentioned before obviously with what the curve where it is now you need to see it a bit higher to start prosecuting more preferred redemptions.
As the cash flow priority change given the fact that it's harder to to achieve that milestone in the coming quarters or should we expect sort of similar pace or a distribution of free cash via buybacks sort of irrespective of where the curve is in the back half of this year and does it change how you think about capital allocation.
<unk>, yeah, perhaps into next year relative to sustaining capital versus growth capital.
I would say that we're not going to.
To execute at a large growth program and our and our.
Stream oil and gas business, so well, but I will say that.
Our intent is to too.
To keep a moderate capital spend what we what we considered to be something similar to the activity level that we have on a whole year basis lots of secondhand then take the second half of this year and projected into next year is what our oil and gas activity level would be.
But what we want to do is we just want a program that delivers the best returns a bet. That's net present value. So that doesn't mean that we're going to take our capital.
Framework, right now and dramatically change it.
Share repurchases as a part of that and that's an it's an important part of that is what we do will depend on the macro but from the what I would tell you what we see with the macro now.
I wouldn't discount our ability to do both to to repurchase common shares all of also being able to redeem some of the day our preferred next year, because I do see it better.
Price environment I believe than then.
And then let some realize it's going to be so I think there are a lot of reasons pointing to a pretty good environment. So I wouldn't discount it yet I do believe that we'll have the opportunity to do both but share repurchases will always be a part of our framework.
I think I'll add to that David too is in 2023 because of our share repurchase program is.
Thus far far more ratable in our concentration limit purchases last year, we are creating a foundation for 2024, we don't have as many slots to overcome with us.
Acetate spikes in oil prices or whatever to get there. So we are laying the groundwork for next year, even as we continue to buy share repurchases this year, whether or not we're retiring.
Preferred along with it or not.
In the interest of time. This concludes our question and answer session I would like to turn the conference back over to Vicki Holt for any closing remarks.
I would just like to say thank you all for joining us and have a great day.
The conference has now concluded. Thank you for attending today's presentation you may now disconnect.
Okay.
Yes.
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