Q3 2023 EOG Resources Inc Earnings Call
Good day, everyone and welcome to EOG resources third quarter 2023 earnings results Conference call.
As a reminder, this call is being recorded.
At this time for opening remarks, and introductions I would like to turn the call over to the Chief Financial Officer of EOG resources, Mr. Tim Driggers. Please go ahead Sir.
Good morning, and thanks for joining US This conference call includes forward looking statements.
Sectors that could cause our actual results to differ materially from those in our forward looking statements have been outlined in the earnings release and Eog's SEC filings.
Conference call also contains certain non-GAAP financial measures.
<unk> and reconciliations for these non-GAAP measures can be found on Eog's website.
In addition, some of the reserve estimates on this conference call May include estimated potential reserves and estimated resource potential not necessarily calculated in accordance with the SEC reserve reporting guidelines.
Participating on the call. This morning are.
<unk> Jacobs, Chairman and CEO, Billy Helms, President and Chief operating Officer, Jeff Leitzel, EVP exploration and production Lamster vein senior VP marketing and Pearce Hammond VP Investor Relations Here's Ezra.
Thanks, Tim Good morning, everyone over the past five years EOG has increased production, 33% decrease per unit operating cost, 17% generated over $20 billion of free cash flow and over $20 billion of net income.
We've increased our regular dividend rate, nearly 350% and including both regular and special dividends paid and committed to.
Have returned about $13 billion directly to shareholders, all while reducing total debt by more than 40%.
At the core of our historical and future success, or Eog's employees, who embrace and embody the EOG culture.
In our third quarter results continue to reflect our employees outstanding execution.
Strong performance in our foundational Delaware Basin, and Eagle Ford assets as well as continued progress across our emerging plays have delivered production volumes capital expenditures and per unit operating costs and better than expectations and enabled us to raise our full year oil production guidance.
And reduce our full year cash operating cost guidance.
In addition to announcing third quarter results yesterday, we demonstrated our confidence in the outlook for our business by increasing the regular dividend 10%.
Announcing a $1 50 per share special dividend.
And raising our cash return commitment to shareholders beginning in 2024 to a minimum of 70% of annual free cash flow.
Our annualized regular dividend is now $3 64 per share, which represents the highest regular dividend yield amongst our peers and as competitive with the broader market. This dividend increase reflects two things.
First the progress we continue to make on our cost structure by leveraging technology and innovation sustainably improves eog's capital efficiency.
Furthermore, we expect the advantages of operating in multiple basins will drive additional improvements to eog's cost structure and returns and reduce the break even oil price to fund the dividend in the years ahead.
Today, we estimate that we can maintain our current level of production and fund the $2 $1 billion regular dividend commitment at an oil price as low as $45 W. T O.
Second this.
This dividend increase reflects our confidence in eog's expanding portfolio of premium plays to grow the company's future income and future free cash flow.
This quarter, we've highlighted recent well performance results in the newest addition to our premium portfolio of assets the Utica combo play.
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.
Beyond our regular dividend, which we've never cut or suspended we raised our cash return commitment to shareholders to a minimum of 70% of annual free cash flow beginning in 2024.
Alongside our portfolio of premium assets and our cash flow margins Eog's balance sheet continues to strengthen allowing us to supplement the dividend with a larger commitment of future free cash flow through special dividends and share repurchases.
In addition to the $1 50 per share special dividend declared yesterday, we executed additional opportunistic share repurchases for the third consecutive quarter.
For 2023, we estimate our committed cash return will be about 75% of free cash flow.
EOG continues to consistently execute.
Lower our cost structure through innovation of efficiencies and organically 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.
Here's Tim to review, our financial position. Thanks Ezra.
Oh, Gee delivered superb operating and financial performance in the third quarter oil.
Oil production increased 4% year over year, while total production was up 9% year over year.
Per unit cash operating cost declined by 5% from the prior year period.
The DD&A rate fell by 9% year over year, driven by the addition of reserves at lower finding cost compared to our production base.
Capital expenditures came in at $1.52 billion $140 million below our target, mostly due to the timing of non well related expenditures such as infrastructure projects.
Year to date Capex of $4 $5 billion is 75% of the full year guidance.
We earned adjusted net income of $3 44 per share in the third quarter and generated free cash flow of $1 $5 billion.
We announced a $1 50 per share special dividend and during the third quarter, we spent $61 million on share repurchases, bringing total 2023 share repurchases through the third quarter to $671 million at an average price of $108 per share.
In total we are on track to return $4 $1 billion of cash to shareholders. This year in the form of regular dividends special dividends and repurchases.
This equates to about 75% of our estimated 2023 free cash flow.
Higher than our 2023 minimum commitment of 60% of annual free cash flow returned to shareholders.
Overall, it was a strong quarter driven by solid operational execution and improving capital efficiency.
Here's Billy to review operations.
Thanks, Tim.
Eog's operational performance continues to improve and this quarter is another example.
We exceeded our third quarter forecast across the board on volumes per unit operating cost and Capex. Thanks.
Thanks goes to our employees for consistently delivering the EOG value proposition quarter after quarter.
Third quarter volumes exceeded guidance largely due to accelerated timing of activity within the quarter, driven primarily by improved efficiencies as well as some benefits from better well productivity.
Efficiencies in our completion efforts have reduced the time to bring wells to sales.
For example, in our Eagle Ford play the completed lateral feet per day has increased 19% year over year.
The team has also reduced nonproductive time by 31%.
Which has the added benefit of lowering total well cost.
In addition, our new completion design continues to drive performance improvements in the Delaware Basin.
With targeted laterals, realizing a 20% increase in productivity.
Well productivity improvements as the primary reason, we were able to increase the full year oil guidance.
<unk> thousand 500 barrels of oil per day.
Last quarter, we reduced our full year guidance for total unit cash operating cost, mostly due to lower lease operating expense and reduced transportation cost or.
Our third quarter performance continued that trend.
Our production teams are optimizing both production and cost through our many technology applications that allow for real time decisions to maximize production and reduce interruptions of third party downtime.
This cross functional effort by our production marketing and information systems teams continued to pay dividends.
Once again, we are lowering our guidance for full year cash operating costs by approximately 2% this quarter.
Bringing our total reduction since the start of the year to 3% or nearly 30 per Boe.
Capital expenditures in the third quarter were lower than expected due to timing of infrastructure projects as well as variances in activity across our multi basin portfolio.
We expect to maintain our current levels of activity for the remainder of the year.
And our full year capital guidance is unchanged.
For 2024, we are currently evaluating this year's results as we develop our plans for each of our plays.
As a reminder, we invest to generate returns.
And growth is a byproduct of the investments and our highly or economic multi basin portfolio.
We are very pleased that the levels of activity across our portfolio are at a pace that allows for continuous learning and improvements and thus would expect to maintain similar levels of activity through 2024.
With the strong results, we're achieving in our emerging plays we anticipate a few additional wells in both the Utica and Dorado.
As we typically do each year, we will remain focused on managing costs through the cycle by contracting for about 50% of services.
And leveraging our scale and consistent activity levels to build and maintain strong partnerships with service providers.
As a result, we're able to take a longer term view to sustainably lower well cost over time.
This year is shaping up to be another solid year performance for EOG and.
And I remain excited about the opportunities we see through the remainder of the year and into 2024.
Now here is Jeff talk about the updates on the Utica play.
Thanks, Billy in addition to sharing new well results I'd like to review a few unique characteristics of our Utica asset that provide distinct advantages, including our low cost of entry our mineral rights position held by production status geologic operating environment and downstream infrastructure status. This year, we added 20.
5000, net acres and have now accumulated 430000 net acres predominantly in the volatile oil window across 140 mile trend running north to south or.
Our leasehold cost of entry remains less than 600 per net acre. We've also acquired 100% of the mineral rights across 135000 acres of our leasehold mineral rights significantly enhance the value of this play by adding 25% to our production and reserves streams for no additional.
<unk>, well cost or operating expense.
Furthermore, over 90% of the Utica acreage is held by production and requires only a handful of wells to be drilled every year to maintain.
The result is more control over our development to allow us to invest in an appropriate pace to capture and incorporate technical learnings and continually improve the play.
Another unique advantage of the Utica is it geologic operating environment due to the plays favorable geologic properties the opportunity to drive down costs through efficiencies as significant the target zone is both shallow inconsistent, which lends itself easy to drilling three mile laterals, and we anticipate testing even longer lateral.
As we continue to delineate and collect more data.
Consistent geology also allows for precise targeting of the very best most productive rock, we're able to regularly drilled 99 plus percent in zone within a narrow 10 foot window. As a result. This play provides an excellent geologic environment for significant efficiency improvements and low cost operations.
On slide 11 of this quarter's investor presentation, we highlighted our strong and consistent well results expand our acreage position from the north and to the South our initial four well timber Wolf package was drilled at a 1000 foot spacing and has been performing well above type curve. These three mile laterals each deliver on <unk>.
<unk> 30 day production, averaging 2150 barrels of oil equivalents.
85% liquid cut.
With a large amount of liquids in the product mix all of the wells, we have drilled to date support double premium potential across our acreage position.
The Utica also has the advantage of abundant midstream infrastructure, the existing processing fractionation and residue buildout eliminates the need for significant newbuild commitments, which was a well recognized advantage when we evaluated the play in.
In the North we have placed into service a pipeline that runs east of our acreage into the market center in the South we have an established reliable third party building out a new pipeline that is expected to be in service late this year with these trunk lines in place investment will be limited to infield gathering as we prepare for a modest increase in active.
Next year, our current plans for 2024 are to run approximately one full drilling rig that will continue to test optimal well spacing and improve operational efficiencies.
Our Utica asset is another textbook example of our differentiated approach 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 company.
<unk> capital efficiency, our track record of successful exploration and strong operational execution has positioned the company to create shareholder value through the industry cycles, Here's Lance where the marketing update thanks, Jeff and our South Texas Dorado play. We recently completed two projects to service future gas flows from this premium.
Dry natural gas play and natural gas treating facility and the first phase of a 36 inch pipeline. The facility was recently placed into service to treat gas from the Dorado play prior to transportation through our 36 inch natural gas pipeline to sales near for your Texas. Both projects were delivered on time and under budget.
A testament to our operational team and foresight to procure a pipe counter cyclically along with other long lead time materials. The second phase of the natural gas pipeline will kick off construction in early 2024 and is expected to be complete late next year phase two of the pipeline will terminate and the Agua Dulce, Texas, which provides access.
To three other pipelines with connectivity to the growing demand along the Gulf Coast, and Mexico and potential premium pricing relative to Henry hub, our pipeline will be instrumental in expanding our gas sales options for the 'twenty, one tcf of net resource potential we've captured in Toronto, and perhaps more importantly saved 20 to 30 per M.
CF and transportation costs over the life of the asset versus third party alternatives now here's <unk> to wrap up.
Thanks Lance.
EOG continues to deliver on our value proposition and our approach remains differentiated for several reasons.
First our premium return standard investments are governed by one of the highest hurdle rates in the industry, 30% direct after tax rate of return using $40 oil and $2 50 natural gas pricing.
<unk> is organic exploration by prioritizing organic exploration, we add inventory and reserves at lower finding and development costs.
Third our assets are unique by remaining focused on the first two returns and organic exploration. We have built one of the largest highest return lowest cost and most diverse portfolios of assets in the business.
We operate in 16 plays across nine basins and have a mass resources of 10 billion barrels of equivalents with an average finding and development cost of just $5 per barrel.
At our current production level, that's equivalent to about 30 years of low cost high margin inventory and our assets continue to grow.
Fourth is technology, we have never considered that the manufacturing process, we leverage both in field technology and information technology to improve well productivity and efficiencies. Our goal is to lower costs and expand our margins to constantly improve our existing assets and new discoveries.
Thanks for listening now.
Now we will go to Q&A.
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Well pause for just a moment to give everyone an opportunity to signal for questions.
And our first question comes from Scott Hanold of RBC capital markets. Please go ahead.
Thanks, Good morning, congrats on the strong quarter.
I think it was pretty notable the way you all took a step up in your fixed dividend payment I mean, you've got a history of doing that but it was a good step up this quarter.
In addition to boosting the.
Shareholder return program to 70%. So can you talk about some of the more significant factors like why make those pretty pronounced moves now is there something in the business model you guys get more confidence and at this point.
To make those moves.
Yes, Scott Thanks for the question.
The decision to raise minimum cash returned to 70% overall it just demonstrates our commitment to our shareholders.
It reflects our continual improvements since the initial commitment was made nearly two years ago.
And really to your question on the business model change.
It's really just our ability to deliver that shareholder value. It's grounded in the fact that our strong cash return generation capacity continues to improve the strength of our industry, leading balance sheet continues to improve and our commitment again to just being disciplined with our reinvestment across the entire portfolio.
So we're in a position now where we feel very confident that and proud that we can increase that minimum commitment to 70% and we look forward to being able to deliver that to the shareholders.
So when you when you look at those breakeven points to do that is there sort of this base business is that breakeven point, then lowered from say, where you were a year or two ago to where it is now.
Yeah, that's right Scott as we continue to invest in these.
A higher return lower cost reserves and bring them into the base business. We continue to do some strategic infrastructure spending to lower the overall cost.
The company going forward that continues to expand the free cash flow potential of the company.
That in addition to strengthening the balance sheet as everyone knows we retired a $1 billion to $5 billion bond earlier this year and we've been.
<unk> been able to be not only net zero, but actually put a little bit of cash on the balance sheet.
All of those things are what gives us confidence in the base business going forward and the fact that we can continue to.
To increase the minimum rate of return minimum cash return to our shareholders from the 60% up to the 70%.
The next question comes from Leo Mariani of Roth and Kim. Please go ahead.
Yes, Hey.
You guys spoke about sort of similar 24 activity.
Versus 2023, but also kind of said that there might be a handful of more wells in the Utica.
The Dorado, so just kind of wanted to get a sense. There I mean do you see this as kind of a give.
Given take proposition, where if you do a little bit more than in someplace, he might have kind of a.
A few less wells than in some other plays and just trying to get a sense of how many costs are trending overall wells today.
Yes, Leo this is Billy.
Yes as far as 2024 is certainly it's too early to get into many specifics about the plan.
But I would say that our plan will be based on a couple of different factors one would be the macro environment kind of what that looks like going into next year.
The other one is really governed by what's the optimum level of activity across each of our plays that supports the objective of having continuous improvement and so on that on our core plays are I'd say, our foundational plays the Eagle Ford and the Delaware Basin, and we're very pleased with the activity level.
We currently have there.
And would you expect to maintain similar levels of activity in those plays we see the advantage of that as we are seeing continued improvement in each one of those plays as we've talked about already on this call.
And then for our emerging plays the Utica in the <unk> for instance.
Pleased with the results we're seeing to date.
And so as we move into next year, we certainly wanted to continue that.
That learning and you may see some a few additional wells in those plays on top of what we've done this year.
As far as the cost trends.
That's one reason we like to maintain these levels of activity allows us to improve our cost basis improve operationally of how we're executing these wells and were seeing the benefits of that play out.
So I'll, maybe leave it at that and see what your follow up is.
Okay. No. That's helpful. So maybe just to kind of jump over to the Utica. Obviously, you brought a new package of wells online here.
Sort of early days, but when you look at these wells.
Do you tell yourself that you've already be able to see some improvement over the last year I'm just trying to get a sense are these wells a little better than they were.
A year ago, and then on the cost side in the Utica are you starting to see maybe the costs come down a little bit here and maybe it's kind of early I think you've added targeted sort of sub $5 F&D, just not really sure kind of where youre at today.
Okay.
Yeah. Thanks, Leo No. We're really excited about the latest package that we brought on and Thats, our timber Wolf package that we highlighted in slide 11 isn't a 1000 foot space test and a note there as we've talked about a new completion design down there.
The Permian and the Wolfcamp well, we were able to go ahead and implement that on that and as you can see from the initial results that we talked about the 30 day Ips on that are 20 150.
Bo.
Per day and over that 30 day period, So really excited about how that is.
Turning out from the spacing test we have an additional package, we actually highlighted in our slide deck. The Xavier is we're going to tighten the spacing on that to 800 foot and we should have results coming on.
Here fairly shortly so we.
We're very excited with the results and you know with that application of new completion design. It is going to be tough to tell if that's really what the big mover is but we're extremely excited about.
The results that we're seeing so far and then from a cost standpoint, we really haven't disclosed specific costs in the Utica, we're still in the early stages as we've talked about and learning in this play and we've got a lot of room for operational efficiency gains we've got.
Some infrastructure small infrastructure to develop that we can install like water gathering reuse and sand to drive down costs and then as we said with the well results. We're seeing we feel really confident in supporting that sub $5 F&D costs.
Yeah.
The next question comes from Jay <unk> of J.
P. Morgan Securities. Please go ahead.
Yes, good morning.
I wanted to get your thoughts maybe at a high level in 2024.
The third quarter call of last year, you provided some soft.
I was wondering if you could maybe give us some thoughts.
Overall.
You see the year kind of playing out.
Consensus forecast.
It's for about $6 1 billion of Capex.
500, So let me get your thoughts if you could give us some soft guidance for next year.
Yeah. Arun this is Billy let me try to weigh in on that for you.
And I apologize if I missed some of your question you were breaking up a little bit there.
As far as 2024 as I said earlier, it's a little bit early to give specifics on the plan, but I would say.
You just look at our activity levels, we're seeing today and I would expect to see similar levels of activity on our core foundational players going into next year give you some hint as to what activity levels. We might have I would expect a few additional wells next year.
Our emerging plays such as the Utica and maybe Dorado.
And then as far as service cost, let me just weigh in a little bit on that while we're talking about that.
We certainly understand service costs have moderated.
And in the industry as industry activity has dropped throughout the year the magnitude of those declines certainly varies between the services and in which basins were operating in.
We remain focused on continuous improvement and we see in our efficiency gains throughout our operations. So we tend to use the latest technology in the highest performing crews, which includes super spec rigs and Frac fleets that equipment continues as you know to be in high demand with service pricing proving to be more resilient.
We have seen drops in tubular and casing costs for next year.
Will tend to reduce overall well cost, but again the magnitude of that effect on overall well cost is yet to be quantified.
So as we go into next year, certainly we expect to see maintain our activity levels that we see in our core plays a few extra wells some softening on well cost overall, I think thats kind of where we're headed.
Okay fair enough.
Maybe one for Jeff Jeff I wanted to get if you can give some more details you provided your Utica type curve.
On slide 11.
Just wanted to get a sense is that.
<unk> curve for the entire play is it for the volatile oil window only.
And would that be representative both the north and the southern portions of the play.
Yes that would just be the general type curve in mix across the 140 miles from north to South there theyre in the play so it's pretty consistent.
Can see on the slide that we put our first handful of wells on there and Thats really what a lot of the type curve was going to be built off and you can see the timber wolf package. The most recent one we brought on in the outperformance in that one.
The next question comes from Phillips Johnston of capital One Securities. Please go ahead.
Hey, guys. Thanks, just two quick follow ups for Jeff on the Utica.
First on the 55% oil cut whats sort of the API or are we talking about on that crude or is it more of them.
Condensate type.
Thank you Sir.
Hey, Phil Let's say this is lance yet what we're seeing is still early but what we're seeing is kind of Apis and kind of a 40 to 50.
Okay sounds good and then.
Well, so far is pretty much all been along the eastern edge of the acreage.
And Im pretty sure you guys have previously said that the black oil window.
The exploratory phase still but how does the geology changes.
West.
When would you expect to test other parts of the year.
Yeah. Good question. So just kind of start off why do we started off on the east really the big reason with that is just we had good quality seismic data over on the east side of it when we were first starting out and obviously that is really important and so you can get a really good look at the detailed subsurface any kind of drilling hazards to make sure you perform really really clean tests.
So where we started where that seismic that obviously, we started the delineation. We've got spacing tests in place and then as we start to zero in on that spacing, we will be able to kind of step out more to the west.
And be able to apply some of those spacing techniques to start developing out there, but we do know theres going to be variation in productivity and as you did state we do expect it to get more oily or as you do move out to the west.
The next question comes from Neal Dingmann of Truest Securities. Please go ahead.
Good morning, guys. Thanks for the time I'll, maybe stick with the Utica just my first question is typically.
Would you or am I in the eastern side of the play limit in any way thoughts about incremental activity or potential additional acquisitions in that eastern oil window.
Yes, Neal this is Ezra.
We're pretty happy with the footprint that we've been able to put together since we entered the play I think we highlighted on the call that we've added an additional 25000 acres.
Our total up to 425000 acres at very low cost and we also I mean just.
The highlight again that we actually own the minerals across 130000.
Acres.
Down mineral acres down in the southern portion of the play so.
So when we look at it right now as Jeff said, we're drilling some.
Initial spacing packages, some delineation tests, where we currently have seismic.
We're also this year acquiring seismic in a couple of different parts of the place where we can continue to to step out and gather results on that and provide a bigger.
Better estimate of what we've captured here for you guys as far as.
Being limited on incremental activity I want to think of it that way.
I said, we've put together a very large contiguous acreage position and really our activity right now as far as investment in pace.
Billy said is going to be determined on our ability to collect data.
And integrate the production data that we're seeing back into the front end of our geologic models. The activity is really always considered to be at a pace, where we can continue to learn and incorporate those learnings on the next set of wells.
Great details guys right and then just a follow up I'll make sure I'll stick with the Utica just sounds like you have more than ample takeaway here right on the southern Utica, but just want to make sure I was clear for plans on the northern portion.
Bill I think you are what are the guys who was talking about it and maybe just talk about the infrastructure plans and if that would capture.
Any of the upside if you decided to boost activity in that northern area, yes.
Yes, Neal this is lance good morning, I think what what makes this place. So unique is that it is just positioned to so much existing capacity I mean actually in fact win.
There's even some idled processing capacity and fractionation comparative idled processing capacity, that's that's near nearby on our acreage. So when we look at that just from an infrastructure standpoint, we've been focused on more just the gathering infrastructure and as Jeff mentioned.
We we.
We put it into service our pipeline in the North and then we're going to have a pipeline in the south as well. So we're going to have plenty of running room, just long term running around as we think about the infrastructure that we're putting in place along with third parties and then also the available capacity that's in place.
Okay.
The next question comes from Doug Leggate of Bank of America. Please go ahead.
Thank you and good morning, everyone.
Excuse me.
The new Diamond system.
But thanks for thanks for getting me on.
As well I wonder if I could hit two things.
The cost to turn change.
The evolution of the portfolio as you look forward so dealing first with the.
70% number.
That obviously is subject to whatever the level of capital is.
And I guess the the <unk>.
So on the machine is that 60% of free cash flow of 70% of free cash flow.
Still free cash flow, which means it's entirely dependent on what you decided this discretionary spending which to me it doesn't mean a whole lot so well.
What can go.
What commitments when you gave guidance or framework for what the level of spending looks like in order for us to interpret what the increase in free cash flow commitment actually means.
Yes, Doug that's a good question.
Based on our cash return model on free cash flow.
For a couple of reasons that simple, but it's also pretty dynamic and it's close to the intentions that we have over a range of different price scenarios.
The way, we're not entering into an area, where we need to modify the commitment going forward, it's something that.
Once we come out with that commitment.
Hopefully our shareholders.
You can see by our track record that once we come out with something.
We're very consistent with it.
The 70% return as a minimum of free cash flow is pretty consistent with our longstanding strategy.
Say to build shareholder value and position the company to be able to do it through industry cycles.
And that means that reinvestment at the right pace in our high return inventory. That's the best thing, we can do to create shareholder value ultimately the cash return strategy.
It begins with our commitment to a growing and sustainable regular dividend, which again, we raise that we increase that just 10%.
And that dividend has never been cut nor suspend it over the 25 years that we've been paying one in addition, we've committed now to return.
Either additional specials or buybacks to reach that 70% minimum commitment for us.
Hopefully the increase.
Increased commitment the reason, we like the 70% of free cash flow is it.
It's consistent with our free cash flow return in that it puts the emphasis on our regular dividend, which we think is peer leading and competitive with the S&P 500, and again, we can maintain our.
We feel that we can maintain current levels of production and cover that base dividend.
At WTS prices as low as $45.
I appreciate that your breakeven number that's done that's very helpful. Thank you my follow up is on.
Portfolio evolution, because I guess.
We all know that 10 years is not the number I guess for EOG, but yet your slide deck continues to discuss the 10 years of double premium. So if I assume that is dominated by the Eagle Ford and the Permian given that you're happy with that level of activity.
What is it how does it evolve if the next leg of growth is the rod or Utica in terms of mix and I guess, what I'm really driving at is.
Our channel checks on midstream suggests you could potentially be drilling north of 300 wells in the Utica in 2026 does that sound reasonable to you in which case, what's the implication for mix.
Yes, Doug I'm not going to speculate on 2026 as Billy said, it's a little bit early to be speculating on 2024, well what I'd come back to is our disciplined base of investment.
A lot of flexibility in the Utica.
Specifically.
We've got over 98 or roughly 90% of the acreage there is held by pre existing production.
I only have a minor drilling commitment there. So we're in a great spot, where we can actually develop that asset in.
And a disciplined ability to increase <unk>.
Activity commensurate with the increase of our learnings now overall your question as you know recently our exploration efforts have yielded very high return more combo plays or in <unk> case, a gas play and that is true.
And there is something to be said for that.
Our exploration and emphasis I would say is.
Dominantly more oil focused because the margins are a bit more forgiving on oil from what we see but ultimately with our premium investment hurdle rate and that's a bottom cycle pricing a $40 oil and $2 50 natural gas through the life of the asset we're somewhat agnostic to.
So the product mix now it does require a heavy lift by Lance.
Discover new market potentials for us to continue to invest in different parts of the infrastructure supply chain to lower our costs and lower our breakeven, but ultimately we are investing in high return assets and we continue to build out the inventory in our high return framework.
More than the 10 years of double premium drilling.
I think I would steer you towards the 10 billion barrels of equivalents overall that is at a finding and development costs lower than our current DD&A rate and as I said in the opening remarks that contemplates at maintenance levels at current levels of production roughly 30 years of production. So.
We're very confident in our high return inventory that we've put together and believe that it's going to.
Continue to deliver great shareholder value in the future.
The next question comes from Charles Meade of Johnson Rice. Please go ahead.
Good morning to you and the whole EOG team there.
Billy I.
One more run at the.
24 outlook I think.
I think you've laid out that the activity levels are going to be.
Pretty similar to 'twenty three if I look at there if I try to think about the big moving pieces, you're going to have some.
Some efficiency gains that some capital efficiency gains, especially as cost come down.
On the other side you have a slightly higher.
Base production so is it a reasonable.
Use reasonable stake in the ground to think that you guys are going to have similar results with 23 in the sense of a.
Low single digit oil growth in kind of low teens, NGL and natural gas growth.
Hey, Thanks Charles.
Yes. This is Billy.
For 24, we've kind of said, it's a little early to give specifics about things, but I would point you to the fact that.
We're running at a pretty decent level of activity now.
We're going to maintain that same level of activity going into next year. Now just a reminder, we're spending about $6 billion on our Capex program. This year and it's proved to be fairly ratable through the each quarter of the year similar levels of activity there'll be some upwards movement, maybe on efficiency gains like you said, we'll have a little bit more efficiency gains.
A factor in.
Maybe some cost reductions due to casing.
Casing costs those kinds of things, we will still have some infrastructure spans we may drill a few more wells in the Utica and Dorado plays and we're trying to quantify that as we go through or towards the end of the year, but.
And the Directionally that kind of hopefully point you towards a what next year might look like we're not going to see a big ramp up in activity in any play as we see today.
Small changes in capital efficiency and well cost as we go into next year with some infrastructure spend.
Got it thank you Billy and then.
Not sure who this would be best for but I'm curious about your your three mile laterals in the Utica. It seems to me like you're like you're pleased with the results because you mentioned that you're even.
Considering longer laterals in the Utica, but I'm curious if you could address that point and then also.
Weather.
Whether we can expect to see three mile laterals in other.
Other key place for you guys and.
If yes, where if know what's special about the Utica that it works there and not in other places.
Yes, Charles this is Billy again, let me give you a kind of an overview and then Jeff may add some more color.
The three mile laterals in the Utica, Yeah, we're very excited about that play and its ability to do these longer laterals.
Very efficiently on the operational side.
We're drilling these things in record times.
And making progress with each pattern of wells we drill.
And we feel we have line of sight on being able to continue to reduce cost over the longer term period as we apply learnings from other plays into this area.
So that's going to continue now we're also drilling longer laterals and some other plays we've drilled some three mile laterals in the Eagle Ford.
And we're drilling three mile laterals in the Delaware Basin.
So we expect that trend to continue in each of our plays now Jeff might want to add some colors on the on.
What we're seeing on performance there too yeah, just a little bit to add in the Delaware in the Eagle Ford and in Utica, We've had great operational efficiency with our three mile laterals and that's one of the things as you start.
Stretching out the length of these laterals you want to make sure that operationally you don't have any issues on the drilling side and youre able to optimally complete that and we've seen really really good results with that.
Other thing. We're also seeing is by drilling these longer laterals, we're able to supplement one vertical.
With a three mile lateral versus two verticals in a mile or two mile and a half laterals. So we're able to see substantial cost savings there anywhere from kind of 15% to 25%. So.
We're definitely excited about where we're seeing it obviously it ties in with our lease hold and we have to see where we can actually drill a three mile laterals, but we are looking to expand that across our plays moving into next year and beyond.
Yeah.
The next question comes from Scott Gruber of Citigroup. Please go ahead.
Yes, good morning.
The enhanced completion techniques in the Delaware appears to be a success.
20% uplift.
Productivity.
But there has been a question regarding portability I talked about in the past.
What's your latest thinking on how widely applicable the techniques across the play and will there be an increase in the number of wells completed with the technique next year.
Yes, Scott just Theres no major updates this quarter, especially just in the Permian with the Wolfcamp, we're still seeing the outstanding strong results that we talked about earlier consistently 20% uplift in the first year production and EUR. The thing I would say is there in the Permian, we do have a handful of test up in the shack.
<unk> targets and Thats really where our focus is shifting out there we hope to bring those on towards the end of this year and kind of the first half of next year and once we get those results. We'll go ahead and share those with you, but then around the rest of the plays.
We talked about in the powder River basin, we do have a test in the ground. We're currently evaluating there and then more so over in the Utica. Obviously, we started applying that with all of our new designs. There so <unk> seen good.
Results, but we're still just kind of collecting data and we'll see exactly what formations that we have success with moving forward.
Got it and then a follow up on the South Texas pipeline. This completion of phase two of the pipeline later next year influence, how you think about the cadence of activity and Dorado.
Clyde to add rigs into the play later in 2004 to set the stage for a strong.
Growth, what's the pipeline as quickly.
Yes, Scott this is Billy.
Phase II first of all we're very excited about that project getting that pipeline is going to give us access to multiple markets in that basin.
The pace of activity in <unk> is really governed by our learnings and results more so than the pipeline date, certainly we're excited about the pipeline because as Lance laid out is going to allow us to save 20, or 30 and Mcf over the life of those reserves, which is 21 tcf of reserves.
But the pace of activity is really governed by how we see the macro and our learnings as we progressed to play.
Really independent of the pipeline.
And then this is lance to some of the other strategic things. We've done as you think about phase III. Once we go in service just to start we already have existing capacity with other existing markets that are in place and as Billy mentioned really excited about getting to what we're going to potentially see us really premium markets. Because we've got offtake agreements already in place two of those which are very strategic.
One of those obviously as with with Cheniere and excited to see the development and the momentum we're getting with the stage III facility, where it will be a big piece of it.
Then just to the.
<unk> will have a strategic connection there and thats going to give us access up all the way up it's essentially the Gulf Coast corridor getting all the way into the premium market. So again really excited about that as well just from a offtake capability as well.
The next question comes from Derrick Whitfield of Stifel. Please go ahead.
Good morning, all.
Two questions related topics not covered yet so first question I wanted to focus on your Ccs pilot with the benefit of a year of experience in the pilot I wanted to see if you could speak to some of the learnings to date.
The flexibility of the policy and your larger operations as it means to achieve zero.
Yeah Derrick this is Billy.
Ccs pilot project, we're very excited about that project, what we've learned.
And how we can move forward with the play so as far as how we've learned there is a lot of operational.
Things, we've kind of been covered as we develop that project.
How we think about the cotwo or sequestering, how we store and how we move it.
The pipeline infrastructure or the equipment, we need those kind of things, but also technically.
What we've learned there as well one thing we bring to the table on all of the Ccs projects, we have an immense amount of understanding of geological areas to store of the carbon and our ability to map out those zones and then we're also very good at drilling wells. So applying those two things gives us some advantage on projects.
We can move forward.
But what we've learned in some of the monitoring we've done so far.
Is very supportive of our initial thoughts on the play and how we can.
Stored the Cotwo and observe its movement in the ground and being able to to have confidence that we can store that for a sustainable period of time. So we're learning a lot. We're very pleased with the results. We're seeing now we're also looking beyond our pilot project to see where else we can apply that technology in and it's early to say.
Yet, where we're going to take that but.
But needless to say, we're encouraged with what we're doing and excited about the opportunities moving forward.
Great and then second I wanted to lean in on your shallow water exploration schedule with offshore drilling rig rates approaching historic levels and industry messaging sustained strength.
Does that impact your views on the timeline for exploration wells and more importantly development activities assuming exploration success.
Yes, Derek this is Billy again.
Certainly for offshore as you mentioned there the rig utilization is pretty tight or I'd say, it's pretty high so the market remains pretty tight on offshore rigs.
We are very.
Happy and pleased with the activity we have ongoing in Trinidad.
But in the Trinidad just a reminder, we've been it turned out for over 30 years.
And currently we have line of sight on probably our one of our longest running programs we've ever had in the history of that play.
And so we've secured a rig there for that out that.
Operations.
And very pleased with the results we've seen to date, so now moving forward.
As far as our exploration activity certainly we're interested in pursuing other shallow water offshore opportunities in the company and mainly because we built quite a expertise that drilling these offshore wells.
Efficiently and cost competitively compared to the industry. So we think that gives us a strategic advantage.
Being able to pursue these kind of opportunities around the world.
So we're continuing to look for those opportunities and certainly those opportunities would factor in the cost of doing business today.
Current offshore rig environment and they'd have to be competitive with what we're doing in the rest of our portfolio. So looking at it that way, we see opportunities to continue to pursue that and excited about what that looks like going forward.
The next question comes from Nick Kumar of Mizuho. Please go ahead.
Hi, Good morning, guys and thanks for taking my questions I won't go back to the Delaware for a minute.
As I look at your slides.
There were two things that youre doing in the Delaware. This year you were also in terms of the mix of your Wolfcamp oil.
And the drilling schedule and then there will be.
Enhancements that you've made.
Could you breakout the improvement that you've seen between the mix and then the.
New technologies that you're talking about.
Yes. This is Jeff you know the first thing I'd say is you know in the Delaware. Our technical teams are doing an outstanding job of continuing to build on their understanding of the subsurface geology, there geologic models and really what they're focused on is increasing the value of each of our development units by maximizing the recovery and improve.
The overall NPV so.
So really we look at it from kind of a total bench standby.
Standpoint, when we go into development now when we're looking at productivity and you talk about that the wells are looking outstanding and we're kind of seen a marked improvement year over year. We've seen good increase in productivity across the majority of our benches and really the wolfcamp as we've talked about a lot is kind of leading the way due to that new completion designs. So.
But the one thing that we always want to go ahead and highlight is.
We have a large acreage footprint and over 400000 acres, we've got a high number of unique targets that we co develop you know based off the very unique geology in each one of these areas. So youre going to see when you look at individual well results or even just the rollout for the play you're going to see that quarter to quarter.
<unk>.
In productivity and well performance, but ultimately we're really happy with all the results that we see and it's hitting all the expectations and we have all that built into our forecast.
Great I guess the reason I'm asking this question is one of your peers in the play has talked about improving recovery rates and not just optimizing the well, but actually improving recovery rates with the application of technology and they've talked about 20% gains. So I guess given your experience.
In shale.
And of course your track record.
Curious to see if you have.
<unk> technologies are seeing technologies that can help that.
Covering factor increase not just optimizing the wells, but really a step change in what youre drawing from the rock.
Yes, Nathan this is Billy let me give you a little more color on that in general as far as the recovery factor.
We're constantly improving our working to improve the long term recovery in all of our plays and is something that goes really back to the foundation of the company and is something historically, we've done as you mentioned.
We leverage a lot of technology to help us understand how were.
Targeting those plays and Howard how we're completing each well and so it involves a lot of things and then let me just talk about that in a sense of how we think about it.
The unconventional plays the completion efficiency is.
It is really important how we.
Evolve over time, and so just thinking about how we've applied.
Applied new technology. It goes back several years, where we talked about.
The Frac design itself how we.
<unk> changed the way we attack the well from the type of sand, we pump the spacing of the perforations that cluster spacing the frac rate.
How we target the reservoirs are understanding geologically of how we understand the best place to place a target. So we can co develop.
<unk> zones, and those kinds of things so that evolution over time has caused us to.
See dramatic improvements in production, which is a proxy for a recovery factor over time in the most recent example is <unk>.
Jeff just talked about the improvements we've seen in our Wolfcamp play and you can readily see that 20% uplift. We're seeing in completions is bringing in production performance is due to the completion approaches. So all those things over time lead to improve recovery factor.
Okay.
The next question comes from Josh Silverstein of UBS. Please go ahead.
Hey, Thanks, good morning, guys.
On the updated 70% shareholder return level, how are you thinking about excess free cash flow beyond that will you look to increase exploration budget or could you in theory increase the shareholder returns to 90%.
It would be helpful. Here, just to get the cash balance and keep growing substantially next year and there's no maturity until 2025.
Yes, Josh this is Ezra.
Ultimately I think the answer to your question is that that 70% of the minimum hurdle in the last couple of years since we first came out with the.
The initial cash return guidance, we had a minimum.
Cash return commitment of 60% in 2022 were at 67% and this year you see that we're on we're on track to be north of 70, probably closer to 75%. So I think thats. The way you should be thinking about the guidance on there.
And really.
The big thing with our free cash flow commitment.
It's a minimum of that 70%, but again, it's really found it in and hopefully it doesn't remove the focus from our regular dividend.
The regular dividend, we feel is the best indicator of our company's ongoing performance the improved capital efficiency going forward and it's a commitment that we give to our shareholders.
Based on our ability to continue to lower the breakeven and expand the sustainable future free cash flow generation of the company, it's backstopped with a pristine balance sheet.
In this quarter when we raised it to 10%.
One of the ways that we raised is by looking at what does it take on a breakeven there and as we've talked about before we can.
We can support this new $2 $1 billion regular dividend commitment at a range of maintenance Capex scenarios.
The higher end of that range would be with a $45 <unk> price and when I say a range of maintenance capital scenarios, let me be clear when I say that for a company like ours that has multiple basins.
Different amounts of year over year or infrastructure spend or exploration.
Different product types, we look at maintenance capital through the lens of.
What does it take to keep production flat for a five year period, but also across those different investment scenarios are we investing in the health of the company longer term with exploration or are we really just.
Narrowing it down to just a focus on <unk>.
Maintaining production and so we ended up with a basically a range of maintenance cap capex between a $4 2 million a $4 $8 billion. So a midpoint of about four five and as I said at the higher end Thats, where we can maintain that level with a $45 <unk>.
Got it and left for me.
Guys are thinking about the portfolio how are you.
Thinking about any kind of long cycle or conventional opportunities like Trinidad.
Relative to <unk>.
Bringing on some additional international growth opportunities. Thanks.
Yes, Josh This is bill let me give you a little bit enhanced maybe if kind of what we're looking at certainly we have a deep portfolio of unconventional plays and that things were currently drilling today, but our active exploration program is continuously looking for all opportunities and theyre geared towards first of all generating solid returns.
And being competitive with what we're investing in today. So it doesn't include.
Things that are conventional or unconventional offshore onshore.
You asked or not so we're looking at all kinds of things that are competitive with water portfolio generating today.
Yeah.
This concludes the question and answer session I would like to turn the conference back over to Mr. Yakov for any closing remarks.
Yeah, I'd just like to say that we appreciate everyone's time today, one final takeaway I'd like to leave you with is that Eog's cash return announcements in the third quarter demonstrate our commitment to creating long term value for our shareholders.
We've increased our free cash flow payout minimum to 70% and increased our regular dividend, 10% and we're confident in the sustainability of our regular dividend due to the consistent execution of our value proposition that improves the company year after year.
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.
<unk>.
The conference has now concluded. Thank you for attending today's presentation and you may now disconnect.
Okay.
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