Q3 2022 EOG Resources Inc Earnings Call
Source potential not necessarily calculated in accordance with the SEC reserve reporting guidelines.
Participating on the call. This morning are as her Jacob Chairman and Chief Executive Officer.
Billy Helms, President and Chief operating Officer, Kim <unk>, EVP exploration and production, Jeff Leitzel EVP exploration and production.
Lance <unk> senior VP marketing and David Streit, VP Investor Relations Here's Ezra.
Thanks, Tim Good morning, everyone. The quality of Eog's diverse multi basin portfolio of high return assets continues to grow and improve yesterday's announcement of the large position we captured in the Utica combo play demonstrates yet again that eog's robust exploration pipeline delivers results.
Over the last two years, our organic exploration efforts have brought forth Dorado, our premium dry natural gas play in South Texas the.
The emerging northern Powder River basin oil play in Wyoming, and now the emerging Utica combo play in Ohio.
The value of our multi basin portfolio can't be overstated with the addition of the Utica combo. We are now positioned to operate seven premium resource basins, which reinforces several of eog's competitive advantages.
First our decentralized cross functional operating teams innovate independently, but collaborate to compound the impact of learnings and efficiencies across the company.
Second our flexibility to allocate capital optimizes reinvestment across our portfolio, enabling us to develop each asset at the right pace to maximize returns.
And third our geographic and product diversity gives us the ability to plan around basin level market dynamics.
Our goal is to expand and improve the overall quality of our portfolio by identifying higher return inventory our.
Our approach is to build a diverse portfolio of premium assets predominantly through low cost organic exploration, which adds reserves at lower finding and development costs and lowers the overall cost basis of the company.
The end result is continuous improvement to Eog's companywide capital efficiency, our track record of successful exploration coupled with strong operational execution is how EOG has continued to improve over time and position the company to create shareholder value through industry cycles.
We demonstrated our confidence in eog's, improving cost structure yesterday by increasing the regular dividend, 10% our peer leading annualized dividend is now $3 30 per share competitive with the broad market.
We also delivered on our commitment to return at least 60% of annual free cash flow to shareholders with our fourth special dividend of the year by year end. We will have returned $5 80 per share special dividends combined with the regular dividend, we will return $8 80 per share or $5 $1 billion in cash to share.
Holders, which exceeds our 60% cash return commitment using current forecasts.
Looking forward, we expect 2023 will remain dynamic with respect to the supply chain oil and gas prices and other global macro drivers are.
Our diverse low cost asset base puts us in an excellent position to capitalize on opportunities no matter the environment.
EOG continues to consistently execute lower our cost structure through innovation and efficiencies and grow the quality of our portfolio to improve capital efficiency and free cash flow potential.
Our transparent cash return strategy is anchored to a sustainable growing regular dividend and backstopped by an impeccable balance sheet.
EOG is in a better position than ever to deliver value for our shareholders through industry cycles and play a leading role in the long term future of energy.
Next up is Billy with an early look at our 2023 plan followed by Tim who will review our financial performance.
Ken will then provide background and details on the Utica combo play.
Here's Billy.
Thanks, Andrew.
Once again EOG delivered outstanding results in the third quarter.
We exceeded midpoint of production guidance, while capital expenditures be forecasted targets.
Like to thank our employees for their perseverance and execution to be the expectations.
Realized oil and natural gas prices also beat their target benchmarks in the third quarter.
Our marketing teams are doing an excellent job executing our long term strategy of diversifying across multiple transportation outlets and sales points.
This strategy is also enabling the company to navigate the recent bottlenecks transporting natural gas out of the Permian.
We hold a significant transport position with the ability to move up to a Bcf a day out of the basin.
In total less than 5% of our domestic gas production is exposed to wahhab pricing in the Permian.
In fact.
We anticipate fourth quarter realized prices to remain strong for both natural gas and crude oil sales overall.
Our crude oil and natural gas export capacity is serving us well in this regard in the fourth quarter, we expect to sell over 250000 barrels of crude oil per day at Brent linked prices and 140000 Btu per day of natural gas.
Jay Kingham linked prices both on a gross basis.
Year to date through September export based pricing of crude oil and natural gas has added nearly $700 million of revenue uplift compared to the alternative domestic sales.
Yes.
One of the major topics of the year continues to be the inflation story.
Price pressure, we're seeing on steel fuel and labor continues to be persistent.
Our employees are maintaining their focus on finding ways to mitigate inflation through innovation and efficiencies in our operations.
Through their efforts, we now expect our average well cost to increase a modest 7% as compared to last year.
As a result, we have narrowed our full year capital guidance to $4 5 billion to $4 7 billion.
Given the elevated and persistent inflation pressures, we have experienced this year I am proud of our employees' efforts to mitigate the majority of this impact to our capital plan.
We continue to evaluate and shape our plans for 2023.
Production growth and infrastructure investments will remain guided by capital discipline.
We expect low single digit oil growth similar to this year.
We currently forecast all equivalent growth, including gas and liquids at a low double digit rate.
Somewhat higher than this year.
Largely driven by increased activity in our highly productive dorado gas dry gas play.
Once again, we plan to leverage our activity across multiple basins.
The secure services and manage cost pressures.
Our initial plan includes a modest increase in activity.
Utilizing on the order of 28 to 30 drilling rigs, including one offshore rig in Trinidad.
This would be accompanied by 8% to 10 Frac fleets.
This would represent a slight increase of two to three rigs.
And one to two frac fleets over 2020 to activity levels.
We are seeing opportunities in different basins to lock in services at favorable rates for next year and currently expect to secure 50% to 60% of our well cost by the start of the year.
This is within our typical range and compares with 50% of cost secured for the start of 2022.
All in all we expect higher Capex in 2023.
Driven by four key factors.
First we are assuming that persistent inflation pressure continues.
With the cost of materials and services, increasing our initial 2023 budget is likely to reflect another 10% well cost to increase on top of the 7% increase we expect this year.
We will continue to work to identify additional savings and efficiency improvements to offset the impact of inflation just as we did this year.
Second we see several opportunities to advance development of particular assets in our portfolio in areas that are less exposed to the most severe inflation and supply chain pressures.
The increase in activity in emerging plays like Toronto, The powder River basin and the Utica combo are examples.
Third.
We expect to accelerate some infrastructure projects to take advantage of market opportunities.
In Dorado, we've begun construction of a new 36 inch gas pipeline from the field to the Agua Dulce sales point near Corpus Christi, Texas.
This will ensure long term takeaway.
Fully capture the value chain from the wellhead to the market center and aligns with our focus on being a low cost operator.
Fourth.
We plan to continue to progress our investments in environmental projects.
Including expansion of our carbon capture and storage or Ccs projects.
Our first Ccs project is progressing and we expect to began injecting cotwo early next year.
This is yet another step toward our goal of being among the lowest cost highest return and lowest emission producers of oil and natural gas.
We recently released our latest sustainability report for 2021, which highlights our progress.
We achieved our near term 2025 methane emissions percentage target of 0.06% last year.
And 85% reduction from 2017 levels.
We captured 99, 8% of natural gas produced at the wellhead meeting our 2021 gas capture targets.
We discussed our latest initiative to further reduce methane emissions through our continuous leak detection system named <unk>.
We improved our safety performance with lower total recordable and lost time incident rates.
And we reduced our freshwater intensity rate by 55% since 2020.
We are proud of our employees progress on our sustainability goes, but we still see tremendous opportunities for continued improvements.
Altogether infrastructure spending, including environmental projects typically amounts to 15% to 20% of our Capex budget.
This year is running right about the midpoint of that range, whereas next year, we expect it to be towards the higher end of that range.
We've continued to develop our 2023 plans as we approach the new year.
And provide a more detailed complete outlook in February .
Now here's Tim to discuss our financials.
We are very pleased to increase the regular dividend by 10% to $3 30 per share annual rate.
This increase reflects two things.
First the improvements we've made to the cost structure.
Efficiencies and technology continue to sustainably improve eog's capital efficiency.
Furthermore, we expect the advantages of operating in multiple basins will drive additional improvements eog's cost structure and returns in the year ahead.
Lower the cost of supply and lowered the breakeven oil price to fund the dividend.
Second this dividend increase reflects our confidence in eog's expanding portfolio of premium plays to grow the companys future income and free cash flow potential.
Over the last several years our success in organic exploration continues to add low cost reserves and consistently drive down our DD&A rate, enabling EOG to create value through industry cycles.
We also remain committed to returning at least 60% of free cash flow to shareholders each year.
As a reminder, we look at this on an annual basis not quarter to quarter.
Based on current commodity prices, we estimate the $1 50 special dividend declared yesterday.
Bring free cash flow returned to shareholders to about 67% for 2022.
We will start 2023, and an exceptionally strong financial position.
We ended the third quarter with $5 $3 billion of cash on the balance sheet.
Against $5 $1 billion of debt.
We generated $2 $3 billion of free cash flow during the quarter, along with inflows of another $1 $3 billion of cash from working capital.
Primarily from the drawdown of hedge collateral.
Now here's Ken.
Thanks, Tim.
We're excited to announce our new oil and natural gas combo acreage position in Ohio, Utica shale, we've accumulated 395000 acres in this play predominantly in the volatile oil window across 140 mile trend running north to south.
Our cost of entry was less than $600 per net acre for leasehold demonstrating the benefit of organic exploration one of our most distinct competitive advantages cap.
Capturing highly productive rock through our organic exploration and leasing efforts is the primary way of improving the quality of our premium inventory at low cost, which leads to a lower companywide cost basis.
The Utica is a well known and prolific gas resource to the east of our acreage several years ago, our exploration team operating out of the Oklahoma City Office took a fresh look at the basin from a petroleum system perspective, we knew there was an oil room with varying gas oil ratios present.
Using our experience in other basins and our technical workflows and proprietary reservoir engineering modeling tools, we anticipated that this could be an area that would be additive to our inventory.
When we considered our advancements in precision targeting and stimulation technology, along with our low cost drilling and completion operations. It became clear that this area has the potential to compete with our premium and double premium plays across the company.
Through leasing and acquisitions, we acquired 18 legacy wells with varying geologic and production data, which supported our assessment of the area.
Over the last 12 months, we've confirmed our model and the economic viability of this prospect by drilling three delineation wells in the northern part of our acreage and one in the south.
These first four wells already earned premium and double premium returns when normalized to our development plan, which assumes three mile laterals.
As a reminder.
Our premium hurdle rate assumes $40 oil $16, Ngls and $2 50 natural gas.
These exceptional results are due primarily to the high productivity of the interval and the large amount of liquids in the product mix from the volatile oil window.
In addition to the well performance. We also want to highlight our embedded mineral interest in the southern portion of the acreage we've acquired 100% of the mineral rights across 135000 acres of our leasehold for about $800 per acre, which is in addition to the $600 per net acre for the leases.
<unk>.
This mineral interest significantly enhances the value of this play by adding 25% to our production and reserve stream for no additional well costs our operating expense.
This area is also where we've drilled our most prolific well which is initially produced over 2500 barrels of oil per day.
And 3500 barrels of oil equivalent per day from a 12000 foot lateral.
The total value of this mineral interest across our southern development area is significant, especially since EOG will dictate the pace of development as operator.
Next year, we plan to drill approximately 20 wells in the northern and southern areas.
And utilize our multi basin experience to climb the learning curve faster by leaning on the best targeting drilling and completion techniques that apply to this area.
We expect our 2023 Utica combo plan will accomplish two goals first to deliver double premium returns while second further delineate delineating the play to help assess resource and inventory.
We will invest in incremental gathering infrastructure.
To prepare for a larger development program and anticipate being able to take advantage of existing processing infrastructure in the area for the foreseeable future.
This is the advantage of the timing and economic efficiency of successfully unlocking potential in an existing basin.
<unk> entry into the Utica combo play is a textbook example of why our decentralized organization that operates in multiple basins with wide ranging geology lends itself to successful additions to the upper end of our premium and double premium inventory.
We applied what we learned over the past decade, and developing our portfolio to identify and unlock this overlooked resource now here's Ezra to wrap things up.
Thanks, Ken.
The takeaway from today's call are centered on EOG is fundamental value proposition first eog's multi basin organic exploration focus continues to improve the quality of our inventory.
Capturing tier one acreage across multiple high return opportunities provides geographic diversity product diversity and the flexibility to allocate capital across each asset at the correct pace to optimize returns.
EOG is a low cost operator, we use technology to increase operational efficiency and capture select pieces of the value chain to keep both capital and operating costs low, thereby helping to reduce our breakeven and increase our free cash flow and income generating potential.
Third Tim highlighted our financial performance and commitment to financial discipline and that results in a 10% increase to our peer leading regular dividend a commitment to additional cash return with our announced special dividends and our best in class balance sheet.
Fourth our recently published sustainability report illustrates our progress to reach near term greenhouse gas and methane emissions intensity goals and our commitment to develop new technologies and pilot new projects, such as our Ccs project to help reduce our environmental footprint and fifth it.
It is eog's employees and unique culture that continues to drive our success.
Thanks for listening, we will now go to Q&A.
Thank you.
The question answer session will be conducted electronically if you would like to ask a question. Please do so by pressing the star key.
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Questions are limited to one question and one follow up question.
Take as many questions as time comes.
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We'll pause for just a moment to give everyone an opportunity to signal quick questions.
The first question comes from the line of Neil.
You May proceed.
Good morning team and congrats on a nice result.
My first question is on jump right to the Utica combo play specifically looking at slide 10 years. It appears that you've talked about this.
I mean, you guys talked about this already.
The primary Pope's looks like it's on that volatile oil section or window I'm. Just wondering if youll identified this is how the economics look in this window and sort of Wi focus here and secondly, maybe just talk about the takeaway situation for you all there.
Yes, Neal this is ezra thanks for the question.
I'll, maybe make a couple of comments and then hand it ended too.
Can you shed a little more lights on the economics, and then Lance I'll provide a little more commentary on the on the takeaway, but when we think about this basin.
<unk> been a bit of a sleepy basin, everyone knew that there was a liquids window, there, obviously and it hasnt really been revisited in a number of years as part of our.
Recent exploration efforts.
We went back in.
Really applied as Ken said, some some of our data from outside from other basins. Some of the things that we've learned in the past few years, we really evaluated it from a geologic level looking at the way the prostate manifests itself between the north and the south the mechanical stratigraphy that we've talked about before how our completions interact with the rock we had better data.
To better define the <unk> and the phase across this area and then really we made a lot of progress modeling the over pressure across the play and when you combine that obviously with technology on the operational side, that's what gets us so excited about the opportunity here.
It's really.
Almost reminiscent of what we saw.
Nearly a decade ago happening in the Delaware basin, whereas a bit of a sleepy basin with a lot of show wells It really required some.
Industry, and EOG technology, and knowledge kind of brought in from the outside really make make things work. Ken do you want to you want to talk a little more about the wells sure.
As <unk> mentioned, we are in the volatile oil window, and we do expect oil gas and NGL production will vary some across that window, both from north to south but more so from from east, which will have a higher a higher gas cut to west which is already there on.
On an ultimate recovery basis, we expect that there will be 25% to 35% oil and similar percentages for natural gas liquids and residue gas.
So when you think about that this play has really focused on the 60% 70% liquids.
Development and.
From that as far as the economics go it gives us premium and double premium.
Numbers, thats $40 oil $16 NGL and.
$2 50 gas.
The other thing to note on these wells is it is early but we are expecting depending on where we're at in the play.
Two to 3 million barrels of oil equivalent for an EUR with a three mile lateral so that type of that type of performance to really leads us to.
Our low finding cost and will definitely be additive to our cost basis.
And then Neil and good morning. This is lance I'll comment a little bit for you I'll start at a high level, two and maybe kind of drill down for you. Just as you think about kind of infrastructure and also takeaway, but really when we think about our plan and it's going to follow the same strategy that we've done and all of our plays and I mean, one marketing is always aligned and integrated upfront and all of our exploration efforts.
Hertz.
You've heard us many times talk about just multiple connections is critical we want to have control of the market and then firm offtake. We're always disciplined in that manner that is going to be very commensurate with our plans, but when you think about the nat gas and especially like evacuating the Nat gas you got to remember like Ken just highlighted the Utica wells will have less gas volumes.
In the oil window is the liquids rich play like Ken highlighted 60% to 70% liquids. So when we look out here. We looked upfront there is significant available capacity. That's just adjacent to our play and also if you remember it's been built out for a long time much of that has been overbuilt I would say like in the last 10 years. So this also.
For for opportunities. So we've aligned we've really aligned ourselves with with the current midstream operators that are in the area are very strong we have great relationships with those we've developed strategic relationships into the Interstate pipelines too at the plant Tailgates and I can tell you. The liquidity is very strong in this area. It's much different than you can look into the Marcellus.
But when you get into this area liquidity is very strong and so we don't see any issues at this time with sales.
On a go forward basis.
Fantastic detailed guys or people coming.
Coming back there my second question, maybe just a bit on capital allocation, specifically I realize you won't have detailed 23 guide could be more.
I'm just wondering.
If you all talked a bit I think on the plant today about maybe a bit more activity next year I'm. Just wondering is that just to keep production stable or are you still kind of considered a maintenance plan next year and I'm wondering if you would consider a bit more growth.
Prices continued to be strong and maybe cost would back off a little bit. Thank you.
Yes, Neal this is Billy Helms.
Luckily you had said in the prepared remarks, there it's still early to talk about what we think 2023 actual specifics will be.
But in the prepared comments also mentioned the fact that we will have more activity, we do anticipate growing our oil production somewhere in the similar to this year somewhere in the low single digits.
And on the equivalent growth it'll be probably in the low double digits.
So thats kind of how we see the play in shaping up as we as today with the macro environment, we see today.
One company that would entail probably adding.
Two to three rigs over and above this year's activity level in general with probably another one to two frac fleets.
So it kind of gives you an outlook of what that might look like so I guess.
Maybe just to scale it up.
On the Capex side.
We kind of gave you some guidance this quarter for what we think our capex burn rate will be and if you kind of normalize that through next year, and then add the cost of a little bit more activity and some infrastructure costs to kind of get you Directionally, where we're thinking.
Okay.
Thanks, Bill and thanks team.
Thank you Mr Backman.
Question comes from Leo Mariani, you May proceed.
Hi, I wanted to dig a little bit more into the Utica you all talked about a well that had a 2500 barrel a day rate I guess it was 3500 on an equivalent basis.
Now I just wanted to clarify is that like a 24 hour rate.
Is that more of a 30 day rate and then also I guess, that's one of the four wells can you, perhaps provide a little bit of color around the other three.
And the base in there as well and when you talked about kind of two to 3 million Boe recoverable.
While lateral can you also help us out with maybe what you think that eventual targeted well cost would be there that three mile lateral.
Yes, Leo this is Ken as far as that 2500 barrel a day rate.
We highlighted there we produce that for a couple of weeks. So we're very comfortable with that rate as far as the other four wells go they had varying lateral lengths.
We can move those to do it.
Three mile.
When we move those to a three mile development plan, there definitely double premium.
Type economics.
That 2500 barrel a day well that's got the 12000 foot lateral is the longest lateral we have drilled to date the others do do have a shorter lateral as we.
As we drilled them one thing I really wanted to highlight on that 12000 foot lateral well as the operations team that we have in Oklahoma City. It was the longest well that we've drilled and once they got into the lateral they drilled at 12000 feet and a little over six days and stayed 99% and an eight foot target. So just outs.
Standing operational.
Performance, there as far as well costs go we've really just highlighted that we anticipate being less than $5 a barrel on the on the F&D costs.
Okay. That's helpful.
I wanted to follow up a little bit on Dorado.
<unk> mentioned that Youre constructing a 36 inch pipe.
Obviously, a pretty good sized pipe so it sounds like you've got some pretty grand plans for that play and it sounds like it's driving a lot of growth in.
2023.
Just curious as to when you think that pipe is going to be ready.
I imagine that take a little while to get constructed and perhaps there is a even kind of larger wave of growth at a dorado as we get towards mid decade.
Assuming that maybe there is some LNG type ambitions associated with that so any color would be great.
Yes, Leo this is Billy Helms, let me maybe start with the answer and then maybe Lance can give some more color on it.
So the 36 inch pipeline yes.
It's an effort to try to not only get that gas to market, but also make sure. We continued our focus on keeping our cost as an operator low.
So that's part of our longer term plan, we've recognized that the value of installing infrastructure is really helping lower the long term cost basis of the company and so this is just another step in that in that vein.
The 36 inch pipe will be constructed over a couple of years. So it's not all being done in one single year.
Important to be taking it to the market center, where we are.
And then.
The LNG that we certainly recognize the value of of having the gas in this areas in South, Texas, where all of the LNG demand is so its advantage from that standpoint.
So that's kind of how this kind of works into the overall market dynamics.
With this play so I'll, let lance maybe add a little bit more color on the pipeline itself in the market Yeah sure Hey, Leo Good morning, It's Lance I think right add onto what bill talked about as well. It's just it is very complementary and it's an integration of our operations, but again like you heard and one of my answers earlier the control of the market is very important and so as we build out this infrastructure.
<unk> ended the Agua Dulce market, we will have we're anticipating for downstream market connections and I know you kind of asked a little bit about LNG, but I think the bigger point is just the demand pool. That's that's.
<unk> at our South Texas.
Could be up to five Bcf a day just from kind of the South Texas region. When you think about power Gen and industrial load and also in the Mexico and the demand pull is really real right you've heard us talk about Corpus Christi stage, three we're going to have a 720000 <unk> days sale. Once that's kind of in service. We got the 140000 Thats today, but you also have Goldman.
Assets under construction and several other facilities that are getting very very close to <unk>, which is which is excellent and so maybe one other thing to add is that we've also contracted for a large transport position on an interstate pipeline expansion, allowing us to reach essentially all of the LNG demand pool, along the Gulf Coast from South Texas to Louisiana.
And that will have a direct connection off of our 36 inch so we're thinking very tactically strategically in setting up dorado for the long term.
Sounds great. Thank you.
Yeah.
Thank you Mr Mariani.
The next question comes from the line of Doug.
You May proceed.
Yeah.
Thanks, Good morning, everybody.
Guys I wonder if I could jump on the Utica as well.
Just curious about.
I guess the back story as to how you accumulate the dispositions because there's clearly.
A lot of players I guess, a little east of you guys some of which might characterize their acreage is non core I know.
M&A is not your your bailiwick, typically, but a little background as to how you establish disposition and whether you'd be looking to continue to expand it.
A follow up on that please.
Yes, Doug this is ezra thanks for the question.
Like anything we allowed the.
Our geologic model to kind of drive where we're interested in acquiring acreage.
We were able to get in there and put it together in a variety of different ways.
Probably the most noticeable one is that we were able to purchase the minerals down to the south that Ken highlighted earlier, it's about 135000 acres of minerals that we purchased.
As part of a transaction, but in general I would say it fell right in line with our strategy of identifying where we want to be in the base and trying to capture tier one and tier two acreage counter cyclically. If you will so we can continue to have a low cost of entry which of course is critical as not only as you get out and delineate the plays but also obvious.
As you really think about full cycle economics.
And these resource plays.
Thanks, Ed I noise.
You guys have typically been organic annuity of course these things, but my follow up is really about capital allocation then I guess.
A follow up to <unk> question about the Dorado pipeline, you're building now you've obviously taken out I guess, you could see another step back to gas with Utica.
What is your what is your thinking in terms of.
Is this a pivot to gas in terms of how we should think about capital allocation I know you typically agnostic or not I'm. Just curious if we're seeing a bit of a pivot back here.
Yes, Doug the short answer is we're agnostic based on our premium price deck of $40 and $2 50 natural gas pricing that we use to measure our investments, but in general I would say, we do have a bullish view long term on natural gas and Ngls, obviously on oil as well, but specific to <unk>.
<unk>.
And some of these combo plays were seeing natural gas. We think we'll continue to see increased demand from power Gen. Some of the coal switching that we've seen this year and also it's going to have.
The upcoming year's continued exposure to the international markets with LNG development, there along the Gulf Coast.
<unk>, obviously span the entire.
A broad spectrum of the economy from plastics and rubber to heating fuel blending and so on.
That's not to say those two wont experience volatility at times, where supply is.
Potentially outpacing demand.
Likewise demand has to be outpacing supply, but that comes back to our approach as a disciplined operator.
First you know we evaluate like we just talked about based on the premium price deck that we use internally and.
And that means that we're investing based on returns first and foremost.
Second, we evaluate that macro supply and demand fundamentals.
For short medium and long term signals and I'd say, it's it's one reason we are excited about the way we enter some of these some of these positions, especially the Utica by owning a 135000 acres with the minerals, we can control the pace of development and the remaining leasehold in that play is dominantly held by production.
So that again is another lever that allows us to really optimize our pace of development and investment.
Well look for news at the end of the month. Thanks. Thanks, guys appreciate it.
Thank you Mr. <unk>. The next question comes from the line of Scott.
Sir you May proceed.
Yes, good morning, and congrats on the organic resource play addition.
Generally what's the.
Great.
Utica acreage that is prospective for double premium versus single premium and Jimmy.
Jimmy what spacing assumption you guys are using across the acreage.
Yes, Scott this is Ken.
As far as the split it's really early in the development of the Utica, We have four wells in it we want to do some additional drilling and testing across the acreage before we really come up with.
Some kind of a resource or a well count or a well spacing estimate.
As far as premium versus double premium, we actually think that we are double premium.
Potential across the entire acreage position. So we're really just excited about the play and look forward to develop developing it next year.
Yeah.
Got it.
Just back on the capital allocation question.
For the medium to longer term, how you're thinking about ramping.
Yes.
Further down in your kind of development curve.
I mean, obviously you have optionality in Dorado would be but yes.
Relative to the younger players and you'll be ramping up.
Utica fits in.
Well. This is Ken this is Billy as Ken just mentioned.
The Utica, we're very excited about the potential of the play to be double premium and so it definitely competes on a on a capital allocation standpoint, but.
But we are early in the play so as we see things today, we'll plan on drilling somewhere on the order of 20 Wells next year and then from that determined on how what the go forward plan looks like.
As far as capital allocation for next year, we're still early and it's still developing our plans, but as we see things today the benefit of having these multiple basins is it gives us a lot of flexibility to move capital between the different basins, we don't have to leverage our all of our activity in one basin.
In particular, we're going to try to keep from seeing a lot of activity increases in areas, where we're seeing the most inflation and supply chain constraints.
That exists mostly in the Permian basin today, So I would expect our activity levels there to remain fairly consistent with what we're seeing what we're doing today.
We can pull levers in the other plays to meet whatever objectives, we set forth as we move towards the end of the year.
Got it appreciate the color. Thank you.
Thank you Mr <unk>.
The next question comes from the line of Carl You May proceed.
Good morning to you and the whole team there.
I'd like to ask.
About these four wells that you drilled in the Utica can you can you talk about.
What you did differently perhaps from from.
From previous operators, whether whether it's up targeting of a zone or your completion design and also perhaps did you did you test different concepts across those four wells.
Yes. Charles this is this is Ken as far as what we've done differently in this area. It really has to do with with having a.
A number of years of experience in all of our other basins that we can bring to bring to bear here in the Utica. If you think about it boils down to four main things one of them is targeting being able to identify the target across the acreage position. The other one is understanding the phase looking at that phase not getting into the gas window and not getting too.
Far into the.
The black oil window. The third one is pressure and how that pressure varies across our acreage position and then the other is the operational execution that we can bring that has both.
The drilling and the completions design that we see.
That all rolls into through what I would call the Jim mechanics, and when you roll all that together it really gives us confidence in that in that area that we'll be able to develop that without low finding cost and then double premium returns.
<unk>.
Got it got it.
That's helpful detail.
20 wells next year that looks like it's maybe should we be thinking about two rigs.
It.
It might take a while to drill these three mile laterals on it over pressure setting.
Yes, Charles really right now these wells arent, taking that long that 20, well program would really be done with one rig at this point in time, we may end up having two rigs if they are available at some point and then not at another time, but the average would be one rig for next year.
Got it thanks for that detail.
Thank you Mr. Meade.
The next question comes from the line of Bob Brackett You May proceed.
Hey, good morning.
Higher level question, and then I'll get some nitty gritty on the Utica is a higher level question as you all versus your peers have run a fairly aggressive exploration budget. This year call it $450 million or so what are your thoughts for 2023 and beyond and keeping the scale of that exploration budget given that its yielding.
<unk>.
Good morning, Bob This is Ezra.
This year Youre right.
As we as we talked at the beginning of this year, we had a number of different exploration plays at a number of different.
Yeah.
Places an evaluation this year, we're drilling some initial wells kind of Wildcats into play some of the.
Plays are a bit further along and we're trying to delineate because remember Rx.
Our exploration program, it's not really about producers in dry holes.
It's really about how or if these prospects are going to be additive to the quality of our existing inventory. That's what we're really looking for here.
Depending on how you bucket size.
20 wells, we're talking about here and point Pleasant is probably the most important thing.
It will basically be another delineation type of year for us across the <unk>.
Cross the 400000 acre position that we've put together outside of those 20 wells that will be the biggest part of next year, it's kind of exploration.
Delineation type of program, if I would put it there we have some ongoing prospects in other areas and we've talked about in the past.
Some of those other ones again extents.
Similar types of areas places that have been sleeping in the past places that are in known oil and yet natural gas producing areas places, where we're trying to bring modern technology.
Our advancement of horizontal drilling and completions technologies and combining them with our rock the understanding of the geologic environment and seeing if we can turn those into premium and double premium types of players that would be additive to us and we will just continue to evaluate as they go to give you a hard number right now, though it's just a little bit early as Billy said, but well.
Break that out in February .
Very clear and then kind of a bit nitty gritty you mentioned the importance of targeting you mentioned staying in an eight foot zone.
Is it a stretch to say the secret sauce here is staying in the point pleasant.
Bob This is Ken we do stay in the point Pleasant I think the secret sauce here is really a combination of everything its a combination of what we've learned in our other plays and then being able to operationally perform on that so getting the right Petro physical model to understand that targeting and under.
Stand how that targeting varies.
Across the area and then looking at the at the eight foot at the eight foot window that we've kept it in really really speaks to being able to do to perform well.
This really goes back to just our culture. It really is about the people.
And it's about our ability to always attempt to get better to work on getting better and try to make the next well better than the last so you put all that together and that really is the secret sauce for our entire company, let alone our exploration effort.
It's clear.
And the third one and I apologize you mentioned the importance of pressure in the old days reservoir energy in the Utica was all was something that was a challenge how have you overcome that and is there maybe a different artificial lift strategy out there to keep that tail producing.
Yes, Bob I think that's why we're in the volatile oil window, we have enough gas in the in the volatile oil window to help us lift our wells at this point in time, we don't see that we will need much artificial lift through the life of these wells.
It's being right on that the right portion of that phase window.
Perfect very clear thanks, so much.
Thank you Mr bracket.
Next question comes from the line of Jimmy Wang You May proceed.
Hi, good morning, everyone. Thanks, Sidney Thank you for taking our questions.
Our first question, maybe just following up on Bob's question here.
Seven premium operating basins, which is fantastic.
Centralized model has worked very well for EOG, so far but from an organizational perspective, how many basins would be considered too many basins, because you're clearly still evaluating other opportunities. Thank you.
Yes, Jeanine. This is Ezra that's a fantastic question here it really speaks to what we think is one of our core competitive advantages and that is the fact that we run a decentralized organization.
What allows us to kind of cross pollinate ideas between divisions.
In any industry you know the success of running a decentralized organization as being able to.
Push decision, making and accountability down to the employees, who are kind of touching the wells and closest to the value.
Creation every single day.
When you break it up that way.
And you think about it that way, we have eight operating teams and each of those.
<unk> has operated it's kind of a fully functioning oil company and a lot of ways. If you will they have a full complement of geologists engineers accountants land manns marketing people, so on and so forth each of these individual.
Asset teams can really handle working across multiple basins and in fact to a different type of scale you see the same type of leverage and benefits that we see at the corporate level is that by exploring in different basins.
Really adds to kind of their understanding I'll go back to how Ken started this the point pleasant or the Utica play.
And it's actually being looked at currently by members of our Oklahoma City team, who are quite familiar with the Woodford.
Over pressured oil window in the Woodford play and that play really landed a lot of expertise to our understanding of mechanical stratigraphy.
Again to reference what Ken was talking about and how the rocks actually.
Break and interact with our completion strategy and Thats. Some of the key characteristics that have helped unlock a number of our unconventional place.
Okay. Thank you.
And then second question in terms of operational momentum.
To provide any color on what activity looks like heading into year end and early 'twenty three.
Noticed that <unk> oil guidance is flat at the mid point quarter over quarter, Capex is up but that sounds like it could be timing related.
Yes, Jeanine this is Billy Helms.
You're exactly right. It's just a timing factor. We're currently running all the rigs that we plan to carry into next year.
It will start looking at adding rigs in different places as we go into next year based on our outlook for the 23 budget, which will firm up as we get closer to that time.
The quarter over quarter volume growth is pretty flat and that's just a function of completing wells late in the quarter that were really roll into next year.
And thats going to happen in several different plays the Permian.
The Dorado play.
A little bit in the Eagle Ford as well so that's just a function of timing of those completions.
Great. Thank you very much.
Okay.
Thank you Ms Wei.
The next question comes from the line of Kevin Mccarthy You May proceed.
Hey, good morning, just getting back to the Utica trying to do some back of the envelope math on spending there next year with a three mile lateral cost in the ballpark of around $15 million and I guess, if you did 20 wells that would kind of put you at around a $300 million.
Spend rate in the Utica next year is that.
Kind of the rate assumption for our rig add next year.
Yes.
Kevin This is Ken what we're talking about now is those are two two to 3 million barrel wells that we've talked about in less than a $5 F&D cost, we really havent given out a.
A number as far as what our development cost will be because we have some additional testing and we really do winter drove some of our wells on.
On pads and drill them in packages to see what that ultimate development cost will be so you can use the $5 F&D in the two to 3 million barrels to get to to get a reasonable estimate for well cost.
Great.
Digging into the marketing strategy, a little bit in the Utica I mean, you mentioned that you had plenty of gas takeaway it locally, but do you guys have a plan to get that gas out of basin, just kind of thinking about the knock on effect of the Utica grows that might have an impact to southwest VA basis and is that.
Of concern for your returns.
Yes, Kevin.
This is lance good morning, Thanks for your question.
Say, even like I talked about earlier, we like the marketing component of it is integrated very early on so I mean, we recognize that Nat gas like realizations are weaker but still when we look at our overall portfolio and then how the Utica combo competes very competitive and so your earlier question was just as it relates.
When you think about just kind of downstream takeaway and that again it comes to just the liquids focus that we have in anticipation I think theres. Some misconception on kind of the gas rates, that's usually going to look very similar to like the dry gas wells to the east and other competitors that are in the region. When we're going to see lower gas rates that are going to come out of.
Come out of our development and so when we look at that on a go forward and with the relationships that we have with the capacity that we see on the processing side, the gas sales and the takeaway we're not foreseeing an issue right now.
Great. Thank you for taking my question.
Yeah.
Thank you Mr Mccarty.
Next question comes from the line of none.
You May proceed.
Hi. This is <unk> can you hear me okay.
Yes, Neal we've got you.
Okay, I'm, sorry about that yes, it's Neil Mehta here from Goldman Sachs. So I had.
A more of a macro question here, which is we haven't seen U S oil production at least in the weeklies.
Move since April of 2022, they've been kind of hanging around this plus minus 12 million barrel a day range and are you surprised that we haven't seen.
The pickup in U S production that a lot of people were anticipating.
A painting and I wanted to tie that into slide nine of your deck, which is showing.
Relative maturity of some of the oil plays like the Bakken and increasingly the Eagle Ford and even the Delaware are we getting to the point, where shale is going to have a tougher time growing.
And we should be thinking about peak shale production in the United States in the foreseeable future.
Yes, Neal that's a good question.
Let me, let me take it one piece at a time here.
Early in the year, we've been talking about how we were anticipating a little bit less U S growth this year than what many people were forecasting.
The reason for that.
Clearly there is a little bit of.
Inventory exhaustion going on in these basins have been have been drilled for a number of years, but the biggest thing we based our models on this year was really what we're seeing with again what's turned into.
No.
Inflationary pressures throughout the year, it's the rig counts are the frac spreads and really the people side of it.
There is definitely north American discipline from the from the E&P sector out here, but there is also a supply chain constraints that have continued to kind of be felt throughout the entire year. This year I do think coming out of the pandemic, we've had a consolidation across the industry. What we have been left and this is something we've talked about.
Quite a bit to as you've been left with less companies and those companies that have the size the scale balance sheet things of that nature to be able to continue to drill and operate.
The majority of those companies are drilling and investing in a way.
It is more disciplined than what was in favor prior to the pandemic. So I think it's really three or four different things that are that have kind of come together.
To limit U S growth.
And quite frankly, a lot of those things I've talked about are not necessarily transitory in nature. Some of these things will really continue into 2023 as well.
And so thats why I'd say entering 2023 again I suspect our forecast on the on the oil side will probably be a little bit to the low end of many of the numbers that youre seeing out there.
Yes.
Helpful.
On the balance sheet together.
Clearly have a fortress balance sheet position in a net cash position now just talk remind us again, how you're thinking about minimum cash balances and what is the optimal capital structure.
If you think about the.
The leverage profile.
Yes, Neal thank you for bringing that up it's something that we're exceptionally proud of and we've always said.
That in a cyclical industry such as ours. The best thing you can have is not.
Not just a strong but a real pristine balance sheet.
There's never really been a cash target for us and Theres not one now we're thrilled to be.
As you kind of said in a unique position where were able to strengthen the balance sheet. This year, but at the same time returned just over 5 billion $5 $1 billion to our shareholders.
As far as the ultimate balance sheet, we have a couple of strategic things, we do have a $5 billion buyback authorization, we've talked about using that opportunistically.
Thats a compelling strategy to go ahead, and and carry a little more cash on the balance sheet and what we've done historically.
But really the strategy overall for the company is aimed at creating value in the long run and managing the balance sheet to make count.
<unk> cyclic investments is a big piece of that.
We've talked about having operational and reserve cash just to stay out of commercial paper, but at the end of the day. When we think about in a cyclical industry like I said the balance sheet provides a lot of optionality to create value.
We're committed to delivering on our free cash flow priorities and Thats.
It's founded in growing in <unk>.
Sustainable regular dividend, but it also contemplates the minimum commitment of 60% of free cash flow and both of those are supported by having a very strong balance sheet and just in general being focused on doing the right thing at the right time to maximize long term shareholder returns.
Makes sense. Thank you Eric.
Yes.
Thank you for your question.
That concludes the question and answer session I will now pass the call back over to Mr. Jacob.
No remarks.
Thank you.
We want to thank everyone for participating on the call this morning and.
And we especially want to thank our employees they've delivered another outstanding quarter for all of EOG shareholders. Thank you for listening.
Yes.
That concludes the conference call. Thank you for your participation you may now disconnect your lines.