Q1 2023 EOG Resources Inc Earnings Call
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Good day, everyone and welcome to the EOG resources first 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 Chief Financial Officer of EOG resources, Mr. Tim Driggers.
Please go ahead Sir.
Thank you and good morning, thanks for joining us.
This conference call includes forward looking statements factors 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.
This conference call also contains certain non-GAAP financial measures.
Finishing and reconciliation schedules for these non-GAAP measures can be found on Eog's website.
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>.
<unk> chairman and CEO .
Billy Helms, President and Chief operating Officer, Ken.
Kim Medicare EVP exploration and production.
<unk> EVP exploration and production.
Lance <unk> senior VP marketing and David Streit, VP Investor Relations Here's Ezra.
Thanks, Tim Good morning, everyone.
Strong first quarter execution from every operating team across our multi basin portfolio has positioned the company to deliver exceptional results in 2023.
Production Capex cash operating costs, and DD&A, all be targets, which underpinned our excellent financial performance during the first quarter.
We earned $1 6 billion of adjusted net income and generated $1 $1 billion of free cash flow.
Free cash flow helped fund year to date cash returned to shareholders of $1 4 billion.
Through a combination of regular and special dividends and share repurchases executed during the first quarter.
Combined with our full year regular dividend, we are committed to returned $2 8 billion to shareholders in 2023.
Or about 50% of our estimated 2023 free cash flow, assuming an $80 oil price.
We are well on our way to achieve our target minimum return of 60% of annual free cash flow to shareholders.
Our first quarter results demonstrate the value of Eog's multi basin portfolio.
We have decades of low cost high return inventory that spans oil combo and dry natural gas basins throughout the country.
Our portfolio includes the Delaware Basin, which remains the largest area of activity in the company and is delivering exceptional returns.
After more than a decade of high return drilling our Eagle Ford asset continues to deliver top tier results, while operating at a steady pace.
And beyond these core foundational assets, we continue to invest in our emerging powder River Basin, Ohio, Utica combo, and South, Texas Dorado plays which contribute to Eog's financial performance today, while also laying the groundwork for years of future high return on investment.
Our portfolio provides flexibility to invest with discipline and develop each asset at a pace that allows it to get better at.
It provides optionality to actively manage our investments to minimize impacts from inflation.
Diversity of our investment portfolio also translates to diverse sales market options, enabling us to pursue the highest net backs.
Our shift to premium drilling several years ago has helped to decouple eog's performance from short term swings in the market.
The result is an ability to deliver consistent operational and financial performance that our shareholders have come to expect and that drives long term value through the cycle.
Recession risk in the near term demand outlook for oil continues to drive volatility of prices month to month.
However, our outlook remains positive inventory levels currently near the five year average are reducing as we progressed through the year glue.
Global demand continues to increase and is forecast to reach record levels by year end and new supply has moderated from pre pandemic levels of growth.
Longer term with a reduced investment in upstream projects. The last several years, we remain constructive on future pricing.
For North American gas near term prices reflect high inventory levels due to this year's warm winter and reduced LNG demand during repairs at Freeport.
As such we are currently evaluating options to delay some activity at Dorado.
The medium and long term outlook for natural gas however continues to strengthen.
Currently U S. LNG demand is at record levels.
With an additional seven Bcf a day capacity under construction or through <unk> with expected startup between 2024 to 2027 that should position in the U S. As a leader in the global LNG market.
Our confidence in the outlook for our business as demonstrated by our capital allocation decisions in the first quarter.
Disciplined reinvestment in our high return inventory continues to lower our breakeven and expand the free cash flow potential of EOG.
We strengthened our balance sheet by retiring debt paid out nearly 100% of free cash flow in regular and special dividends and we utilized our repurchased authorization to buyback $310 million worth of stock late in the quarter during a significant market dislocation.
I'm confident that EOG has the assets the technology and the people to deliver both return on capital and return of capital for years to come.
In a moment Billy will discuss why we believe our foundational assets in the Delaware Basin and Eagle Ford will provide higher returns margins and free cash flow in the years ahead and why we remain excited about the progress we are making in our emerging assets powder River Basin, Ohio, Utica combo and south.
Texas Dorado.
But first here's Tim to review our financial position.
Thanks, Andrew.
EOG generated outstanding financial performance in the first quarter.
We produced $1 $6 billion of adjusted net income or $2, 69% per share.
And $1 $1 billion of free cash flow.
Timing differences associated with working capital accounted for an additional $661 million of cash inflow in the quarter.
Our outstanding financial results were driven by strong operating performance.
Compared with the prior year first quarter production volumes increased 2% for oil and 7% overall.
We mitigated most of the inflationary headwinds to limit the increase to per unit cash operating cost to just 3% or $10 59 per Boe.
Which was more than offset by a 12% decline in the DD&A rate.
Capital expenditures in the quarter of $1 $5 billion came in $100 million below target.
Our long standing free cash flow priorities and cash return framework remain consistent.
Our priorities are sustainable regular dividend growth.
Pristine balance sheet.
Additional cash return options and low cost property bolt ons.
We are committed to return a minimum of 60% of the annual free cash flow to shareholders through our sustainable regular dividend special dividends and opportunistic share repurchases.
We believe the consistent application of our free cash flow priorities and transparent enhanced return framework positions the company to create long term shareholder value through the cycle.
In March we strengthened our balance sheet by paying off a $1 billion to $5 billion bond maturity with cash on hand.
<unk> three $8 billion of debt from the balance sheet.
The next maturity is a $500 million bond due April 2025.
Cash at the end of the quarter was $5 billion.
Yielding a net cash position of $1 2 billion.
Up $300 million from December 31.
Yesterday, our board declared a second regular dividend of 82, and a half cent per share the same as last quarter and a 10% increase from the prior year level.
The $3 30 annual rate is a $1 $9 billion annual commitment.
On March 30, we also paid the $1 per share special dividend declared in February .
EOG also repurchased $310 million of stock in the first quarter.
At an average price of $105 per share.
For several days during the last two weeks of March March market volatility created a significant dislocation between the price of our stock and the value of the business.
We were able to utilize our strong balance sheet to repurchase shares at highly accretive prices.
We will continue to monitor the price and value of our stock and you should expect us to step into the market again, when there are significant dislocations.
We are off to a very strong start in 2023 to deliver on our full year cash return commitment of a minimum of 60% of annual free cash flow.
Altogether, the full year regular dividend along with the first quarter special dividend and buybacks reps.
<unk> represents $2 8 billion of cash return, which is about 50% of the $5 $5 billion of free cash flow.
We forecast for 2023, assuming an $80 oil price.
We will continue to monitor oil and gas prices going forward and we remain committed to delivering on our cash return commitment and look forward to updating you over the rest of the year.
Here's Billy to discuss operations.
Thanks, Tim.
EOG is operating performance continues to improve with the first quarter generating outstanding results.
Our first quarter volume capital expenditures and total per unit cash operating cost performance.
Came in better than our forecasted targets.
I'd like to thank our employees for their dedication and outstanding execution, giving us a great start to 2023.
Our full year 2023 capital and production plans are unchanged.
We forecast a $6 billion capital program to.
To deliver 3% oil volume growth and 9% total production growth.
We maintain the pace of activity from the fourth quarter of last year in the Delaware Basin and Eagle Ford are core foundational plays.
And continue to expand development in our emerging.
Powder River Basin, Ohio, Utica combo, and South, Texas Gerardo place.
Well productivity and cost performance are meeting or beating expectations across our portfolio.
<unk> sustained sufficient activity to support continued innovation.
As <unk> mentioned, our foundational assets in the Delaware Basin, and Eagle Ford are performing exceptionally well.
And we're a big part of our overall strong first quarter results.
Sustaining a consistent level of activity in these core plays.
Is driving operational improvements and continues to be one of the primary hedges to offset areas of cost inflation.
We are excited about the outlook for these assets in the years ahead.
Even as these assets mature, we can apply technical learnings operational innovation and leverage prior infrastructure investments to.
To continue to improve the operating margin and capital efficiencies.
These world class assets.
In the Delaware Basin, we expect well performance will continue to improve this year.
Delivering productivity and returns well above the premium hurdle rate.
Last year, our Delaware Wolfcamp wells delivered an average six month cumulative production.
Of about 34 barrels of oil equivalent per foot.
And are expected to improve this year.
See slide 10 of our updated investor presentation for details.
While well mix can impact the relative contribution of all.
Ngls and natural gas.
Overall performance is improving in large part due to continued innovations like our new completion design.
We have now tested 39 wells in the Wolfcamp.
That are yielding an average increase of 22% in the first year production.
With a 20% uplift in estimated ultimate recovery compared to the similar wells and targets using our previous completion design.
With these encouraging results. We are now we now expect to deploy this new design.
On about 70 wells this year.
This new design is continuing to show promise as we expand the number of wells and test the design across different targets and basins.
Operationally, maintaining a consistent level of activity in the Delaware basin.
Combined with our culture of continuous improvement is generating noticeable results.
Drilling times continue to improve and are generating peer leading performance.
Added by our drilling motor program and high performing staff.
The amount of footage drilled per motor run improved by 11% in the first quarter as compared to last year.
Similar progress is being achieved with our completion operations with the expansion of our Super Zipper technique.
These efforts combined with the opportunities as co development co developed multiple targets.
In the stacked pay resource by using our existing surface footprint and infrastructure.
Are expected to drive significant efficiency gains and continue.
To improve our margins in the Delaware basin for years to come.
The first we first introduced the Super Zipper completion technique in the Eagle Ford in 2020.
Since then we have expanded its use throughout the play and.
And they have more than doubled completions efficiency as measured by a completed lateral feet per day.
As indicated on page 12 of our quarterly Investor slides.
The amount of lateral completed per day year to date has.
<unk> has increased by another 18% compared to last year.
In the first quarter, we also set a record in the Eagle Ford.
Drilling our longest well to date, reaching a measured depth of nearly 26500 feet.
With a lateral length of over 15500 feet.
We expect to continue to see completion efficiency improvements.
As we extend laterals in the Eagle Ford to three plus miles where feasible.
As a core operating area that has been under development for more than a decade.
The Eagle Ford also benefits from our existing infrastructure from over 3700 producing wells.
Leveraging existing investments made in strategic water oil and gas infrastructure and minimize future capex needs and lowers operating costs.
Ongoing improvements to completion operations and leveraging the benefit of existing infrastructure.
Enable our Eagle Ford, finding and development cost to continue to decline.
Last year in the Eagle Ford is rate of return was the highest in the place history.
Longer term, we have over a decade of drilling inventory in the Eagle Ford.
Following us to maintain the current production base, while generating high returns.
And lowering breakeven.
As previously mentioned.
We are maintaining activity in our core plays and progressing our newer or emerging plays.
This year this year's plan in Dorado contemplates eight additional wells completed compared to 2022 and.
In order to achieve a consistent level of activity.
To drive performance improvements.
Our drilling operations are realizing a 29% improvement in the footage drilled per day since 2021.
Completion operations will be conducted on a few wells in the second quarter. However.
We are evaluating options to delay additional completions.
Recently scheduled later this year due to the current natural gas price environment.
To date operational progress towards improvements and Toronto as well performance is meeting or exceeding our early expectations.
Activity in the Utica combo play is just commencing yet we are already witnessing the compounding effects of sharing technology across our multiple plays.
For example drilling performance for our recent wells is improving on the order of 20% to 30% compared to last year's results with the benefit of our proprietary drilling motor program and precision targeting.
We expect similar levels of improvement from our completion program. Once we began completing wells in the third quarter.
Now for a little color on inflation and industry service cost.
As we had anticipated and building this year's plan.
The upward inflationary pressure that we witnessed last year.
Appears to have plateaued, which still leaves us confident that our average well costs should increase no more than 10% compared to last year.
Early indicators are showing signs of service cost moderation.
Which is more prevalent in some basins and less in others.
We would expect that any softening of service in tubular cost will be slow to manifest into lower well costs and cash operating cost.
Until much later in the year or more likely in 2024.
As the year unfolds, we will continue to look for opportunities to leverage our scale and the flexibility of our multi basin portfolio.
To manage cost across all operating areas.
We also remain highly focused on sustainable cost reductions through innovation.
Operational performance.
And execution improvements to mitigate inflation and further drive down our cost structure now.
Now I'll turn it back to <unk>.
Thanks Billy.
In conclusion I'd like to note the following important takeaways.
First strong execution from every operating team across our multi basin portfolio has positioned the company to deliver exceptional results in 2023.
Thanks goes to our employees for delivering a great first quarter with our outstanding execution.
Second our foundational assets in the Delaware Basin, and Eagle Ford are performing exceptionally well and were a significant part of our first quarter result results.
Third our first quarter performance demonstrates the value of Eog's multi basin portfolio.
We have decades of low cost high return inventory that spans oil combo and dry natural gas basins throughout the country.
And fourth our long term outlook for both oil and gas remains positive and our shift to premium drilling several years ago has helped decouple eog's performance from short term swings in the market.
The result is an ability to deliver consistent operational and financial performance that our shareholders have come to expect and that drives long term value through the cycle.
Thanks for listening, we will now go to Q&A.
Thank you.
<unk> and answer session will be conducted electronically if you'd like to ask a question. Please do so by pressing the star key followed by the digit one on your Touchtone telephone. If you are using a speaker phone. Please make sure. Your mute function is turned off to allow your signal to reach our equipment questions are limited to one question and one follow up question, we will take as many questions as <unk>.
Time permits.
Once again, please press star one on your Touchtone telephone to ask a question. If you find that your question has been answered you may remove yourself by pressing star two or the pound key.
We will pause for just a moment to give everyone an opportunity to signal for questions.
Our first question is from the line of Paul Cheng with Scotiabank. Paul Your line is now open.
Yeah.
Thank you good morning, everyone.
Two questions. Please the first one is probably for you Paul about the Permian the.
Good well productivity just can you give us a bit more detail.
In terms of it.
You are doing over there and whether you are increasing especially as you start to do more co development and how many different landing zone.
Oh.
Oscar.
Danielle photograph.
Second one that just kill it.
I think.
In the law.
A couple of months.
Why.
Go ahead with the expansion.
And I think last quarter conference call management.
Looking for the long term so just curious that what may at trick.
Your line.
<unk> changed your view about the pace on that.
Thank you.
Yes, Paul This is Billy let me give you a little.
Highlights maybe of the Permian program and what we're seeing there and then I'll probably ask Jeff to give some more detailed color. So you can help explain some of the improvements we're seeing.
Overall, we're very pleased with the progress our Permian.
Plans are showing in general our results are playing out just as we anticipated.
And our plans we had planned all of our type curves are modeled and forecasted and the results are meeting or exceeding our forecasted results, including the co development of different targets at the same time, but I'd like to go ahead and turn it over now to Jeff maybe talk a little bit about the new completion design. The results. There we are seeing and then some of the productivity improvements.
<unk>.
Yes, Thanks, Billy Paul This is Jeff, Yes, we're extremely happy with our productivity out of the Delaware and just to give you a little color one of the big things that is really improving that is our new completion design or I should say.
Our improved completion design, so as Billy stated to date, we've tested around 39 wells in the Wolfcamp in that we're seeing an uplift of about 20% or so in the well productivity and that's in both the early and late life performance of that I'll also note that the uplift and we're not just seeing that in one phase we're seeing both in oil and gas so kind of across the board.
So with these outstanding results. What we've done is we've really expanded this program and we're planning on completing about 70 additional wells in the Wolfcamp. This year. So that's going to be about two five times increase from last year and we definitely went ahead and taking this into account in both our drilling plans and guidance for 2023. So so looking forward with this design.
Fine.
We've had a lot of success in our deeper formations our team really plans to continue to kind of test and some of the shallower formations to evaluate its benefits. One thing that we have observed with this design is that theres varying performance uplift depending on the rock type and the depth of the target and the design does come with a little bit of a cost increase so we just want to be mindful about.
How quickly.
We're testing it and be strategic at the pace that we're going ahead and putting these in the ground also I'd like to point out that the design isn't really new to EOG. It was actually first tested down in our Eagle Ford asset and this is just an example of the technology transfer in the company of our multi basin operations, it's really helped us accelerate our learn.
Throughout the company and then lastly, with the success that we've seen in the Delaware Basin. We're actively testing it in all of our emerging plays throughout the company and really look forward to evaluating those results throughout the year.
And then Paul the other part of your question was on Dorado in and really what triggered the change of pace that we're thinking about.
We put together our plan originally just to remind everybody that really it was not a huge acceleration in activity planned for we are only adding eight wells. So the plant never contemplated a huge amount of growth and the drought or to start with.
However, we're always remain flexible on our program.
But that's the benefit of having a multi basin portfolio is we can move activity around based on market conditions or other factors as they present themselves.
Naturally with gas prices remaining weak and.
And moving into the year, it's only natural to think about options that we might be able to explore withdraw to activity and we are exploring the option to delay some completions that were scheduled for later in the year.
And we will we will give more color on that as that unfolds.
Thank you Mr Cheng.
The next question is from the line of Leo Mariani with Roth Capital Partners.
Your line is now open.
Yeah.
Yeah, Hi, I, just wanted to follow up a little bit on the buyback versus the special dividend. Obviously, there was no new special dividend I guess announced this quarter. Instead, you guys certainly weighing on the buyback as you described in March I, just wanted to kind of confirm your thinking around this I mean it is still.
Sounds like the buyback is going to be reserved only for kind of very opportunistic situations, where there is this dislocation and generally speaking, it's probably more reasonable to expect.
The special going forward, where the buyback kind of maybe every once in a while is that kind of how to think about it.
Yes. Leo this is this is <unk> good morning.
I think you've summarized it pretty well our strategy hasn't really changed.
We are committed to returning at least 60% of our free cash flow on an annual basis.
Year to date.
As Tim had mentioned our cash return commitment is $2 8 billion, that's approximately 50% of our.
What would be our fiscal year free cash flow.
At the assumed $80 oil price there.
And just to recall the cash return priorities for us It really begins with the regular dividend is the first priority the excess free cash flow as you said will either come back in the form of special dividends.
Which we've paid seven of the last eight quarters, we've distributed a special dividend or opportunistic buybacks and what we saw in the first quarter when we executed.
Our repurchase was we really saw a dislocation dominantly associated with the banking crisis, and we were able to step in to repurchase approximately $300 million.
The stock so as you pointed out really in line with our strategy now.
What I would say has changed over the last 18 months since putting the repurchase authorization in place.
Really the strength of our company our primary value proposition of course is investing in high return projects.
Adding lower cost reserves to our company's profile.
Which thereby reduces our breakeven and expands our margins and so as we continue to execute on this strategy and we continue to strengthen the company.
The way, we consider dislocations certainly evolves as well.
Okay. That's helpful and I just wanted to see if theres any more of a robust update around the Utica I think last tiny guys kind of rolled that out I think you had four wells on production.
A fair bit of history, just trying to get a sense of there.
Our wells are producing at this point in time in the Utica and just any thoughts around some of the longhorn performance of those prior wells have been on for over a year at this point.
Yes, Leo this is Ken.
We're making excellent progress on our Utica program. This year. We currently have a drilling rig actively operating on our northern area and we are progressing nicely on our gathering and infrastructure projects.
Before wells that you talked about that we drilled and completed in 2022 really do continue to deliver our our expected performance and we plan to drill and complete about 15 wells across both our north and southern areas. This year and we will have those production results more towards the end of the year. Another thing to note is as we also continue to add acreage in la.
For additional low cost opportunities to add to our position.
Thank you Leo.
Next question is from the line of Scott Hanold with RBC Scott. Please go ahead.
Yeah. Thanks, good morning, and congrats on the quarter.
Maybe if I could pivot back on on the.
The buyback conversation.
If you can give us some color on what were the key triggers on the decision to do buybacks was it relative valuation of EOG to peers was it just the.
Aggregate move or is there other things like intrinsic value assessments.
That kind of generated that process to really kick it off there.
Good morning, Scott, Yes. This is Ezra.
They are all.
Accurate to the tune of how we kind of look at these opportunities as we've talked about in the past.
It kind of begins with the macro first of all right, what's happening on both global and domestic supply and demand.
Balances.
As far as dislocations go we do measure.
We look at the intrinsic value of our business relative to different pricing scenarios, both short and long term and we do evaluate trading multiples not just at EOG versus the peers, but actually for the interior entire peer group and see what's happening.
And so one comparison.
There could be made is the dramatic sell off that the industry saw last summer, which was associated with a pretty dramatic pullback in oil prices that was really fundamentally supported by a change we felt in the macro outlook. There was a significant announcement there for roughly 300 million barrels of petroleum reserves that would be.
Hitting the market on the supply side from across the globe.
What we saw in the first quarter was not really supported by a big change in the forecast on the fundamentals.
Potentially really just triggered from the banking crisis potentially.
<unk> increased fear on the demand side from increased recession, but we really feel like <unk>.
Most of that has already been priced in.
To the market on the demand side and so when we saw a pullback there in a dislocation with the market really again associated in late March there was a banking crisis.
We really don't hesitate and were able to step into the market.
And do that $300 million share repurchase and we think we've really created a significant amount of value there for the shareholders.
That's great. Thanks for that and as my follow up one of the things I think tends to get lost or is underappreciated is the premium pricing you all continue to get on your commodities across the board and can you just give us a sense of as you kind of look forward do you find more opportunities.
<unk> ahead, where you can continue to raise the bar on that as well.
Hey, Scott Good morning. This is lance thanks for the question, yes, our realizations continue to be.
Excellent and I mean, when we think about it it's really just the capability that we have when you think about the multi basins that we have but just our transport position and then the capacity that we've taken out you hear us talk a lot about control and having control all the way to the water.
It's exceptionally important so I would just say as you think about our position in the price realizations to extracting additional premiums I think our ability to just transact very quickly.
And with the supply the scale that we have I mean, we can definitely walk in with further opportunities.
Yeah.
Thank you. The next question is from the line of Scott Gruber with Citigroup Scott. Please go ahead.
Yes, good morning, I wanted to circle back the Wolfcamp development strategy.
Looking at slide 10 here in the deck last year, you've layered in.
Wolfcamp <unk> wells this year.
As a percentage of them.
And we will be sliding back down so.
Does that impact.
You'll develop.
And deploy the new completion design or <unk>.
They tend to be more selective with.
Co developed Wolfcamp.
Got it.
Yes, Scott this is Jeff really what our co development strategy, it's pretty straightforward in what we're trying to do as well.
We're just adding in high rate of return targets to our well packages and really it's driven by the geology and obviously the geology across our acreage it changes.
Very quickly so kind of from development unit to development unit, we've really got a strategically dissect what our strategy.
Strategy is going to be there, but from what we're seeing right now and you can see that on slide 10, and 11 in our deck by adding in some of those deeper targets in the lower wolfcamp or I should say the lower upper wolfcamp and in the middle we're achieving economics, well over our premium hurdle rates and.
We have some of the tightest co development spacing out there in the basin. So ultimately just did this approach I mean, it is improving our total recovery per acre, it's helping optimize NPV of the resource and its just adding those barrels finding costs below our current Delaware basin levels.
Got it and then just looking for some more color on the new completion design. You said it was initially developed and rolled out in the Eagle Ford does it become.
Dominic design in the Eagle Ford and will become the dominant device.
And.
How quickly can that can be rolled out.
Yes, Scott great questions. So yes, the design as I talked about it was first utilized in the Eagle Ford It was back in right around 2016, and we didn't see the same uplift that we see in the Permian.
It wasn't quite as extensive but it really has to do with the difference in rock type and a geological properties between the two plays but it did provide.
The application for really beneficial as far as helping lower well costs and reduce our completion time. So yes. It is something that we still do.
<unk> there in the Eagle Ford and as I said in a lot of our emerging plays and then as far as in the Delaware and our rollout. Our plan is to increase as I said the year over year number by two five times, what we did last year and I also did state Theres just a slight cost increase so we want to be cognizant of how quickly we roll it out and like anything in our program. We just don't want.
Outrun, our learnings and we want to make sure that we continue to evolve this technique as we learn.
Okay. Thank you.
Next question is from the line of Derrick Whitfield with Stifel. Please.
Please go ahead.
Good morning, all and thanks for taking my questions.
With my first question I wanted to focus on Capex cadence throughout 2023 with Q1 coming in better than expected in Q2 are projected to be heavier than expected.
Could you comment on the one to two drivers and separately if not part of the answer could.
Could you speak to cadence on non D&C investments throughout 2023.
Yes, Derek this is Billy Helms.
So yes, the second quarter Capex is guided to be a little bit higher than the first quarter.
And that's mainly due to some <unk>.
Non drilling and completion capital.
Indirect or infrastructure and those kinds of things that we put in our program.
It was originally scheduled to occur at the latter half of the first quarter it turned out to be pushed into the second quarter.
That's the reason in the first quarter was under one capex in the second quarter is a little bit higher.
And that really sticks to our original plan, we had always planned for about 52% of our capex to be spent in the first half of the year and so we're still on target for that and the 48% in the back half.
So thats kind of the way the program plays out.
Great and with my follow up I'd like to focus on your operational efficiency gains in the Eagle Ford.
Is your gain principally driven by increased Super zipper activity and if so are there are practical limitations on the amount of completions you could foresee utilizing this approach.
Yes, Derek this is Ken.
I'd like to start off by early crediting our team there in San Antonio for driving down that finding cost that you talked about.
By focusing on improving the efficiency of every portion of the process, we've been able to drive down costs over the past several years in increasing our lateral lengths, while improving targeting and focusing on bidding motor performance in conjunction with the advent of Super Zipper completion operations have really allowed us to improve efficiencies.
And.
We're really drilling completing more lateral footage per day compared to a few years ago naturally showing up in our lower cost basis in <unk>.
One thing to note is we do have over 10 years of high return drilling in this play that can sustain our current production levels and continued to expand our margins.
Thank you.
The next question is from the line of Doug Leggate with Bank of America Merrill Lynch Doug.
Yes.
Good morning. This is John Abbott on for Doug Leggate.
A quiet first questions are really on Dorado.
We understand that youre going to potentially delay activity this year, but one of the goals that you set out this year was to try to again get a greater economies of scale in the play.
When do you think you need to achieve that size and scale, noting that you have additional LNG capacity coming on exposure in 2026.
Yes, John this is Billy Helms.
So for grotto.
Yes, we are.
Creasing activity there mainly from the drilling side. Originally we had planned to also bring in additional completions.
On the drilling side I would add that we are seeing a tremendous improvement in the efficiency gains there.
There has done just an excellent job.
Being able to.
Improve our drilling times, lower our well cost and just increased efficiencies overall. So we're very pleased with the progress we've made and so I think that that increased activity. We're seeing on the drilling side is playing out what we're seeing on the drilling results and given us insights into how we can continue to lower well costs going forward on the completion side.
We have.
Some planned activity here in the second quarter, but beyond that.
We're looking at ways, we can with the flexibility we have in our program to to delay the completion of any wells that beyond in the second half.
And really just thinking about how we can leverage some of the learnings from our other programs in place and combine that activity with.
Activity, we havent dorado by sharing equipment and people and those learnings across our portfolio.
So we don't really feel the need to jump in and complete those wells, but we are.
We are evaluating options as they rollout and we'll we'll see how those present themselves.
And then as far as activities for I guess.
LNG demand I guess.
The play the unique thing about this play it doesn't take a lot of wells. The wells are very prolific. So we're well ahead of any timing that we would need to add LNG capacity in the future.
And then we also have the flexibility to move in gas.
From other operating areas multi basin portfolio to the Gulf Coast. So don't think of the Dorado is just simply applying itself to the LNG market. It's got the opportunity, but looking at gas from other plays to the Gulf coast as well through our marketing arrangements.
That's extremely helpful, which leads to the next question.
Assuming there was not an issue with gas prices.
How do you think about the optimal level of production for that play or activity long term.
I mean, how big does it kind of get to how do you think about that.
The efficiency program longer term.
Yes, John this is Kate and I think the.
Yes, John This is Ken I think the real thing in Dorado is is it doesn't take a lot of wells to generate significant volumes out of that place. So I don't know the exact rate pace, but what we wanted to do is we wanted to develop is that at the right pace, where we don't outrun our learnings, we're making significant progress.
Is it really get those operational synergies together that bill talked about and so that pace of development is really going to be dictated by not out running our learnings.
Thank you. The next question is from the line of Neal Dingmann with the Truest Neil. Please go ahead.
Yeah.
Okay.
Thanks for the time My first question just on the Powder River I'm, just wondering had heard too much on that I'm. Just wondering how do you still feel this competes versus your other premium plays and I know at one time you suggested you had almost 17 other locations that I'm just wondering your thoughts about this.
Yes, Neal this is Jeff no, where we have outstanding results there in the powder right now and at some of the lowest finding costs that we're seeing there.
In the whole portfolio so yes.
Yes, we still have between kind of our full south powder River Basin, and then moving up to north of about 600 net on drill premium locations. So just looking at our program everything is on pace. This year. The wells are performing as we expected Q1, we've completed about 15 gross wells, which two thirds of those where Mallory and we're seeing a lot of benefits also by <unk>.
Some consistent activity up there in the powder, we're running a consistent to two to three rigs and one full frac spread with that which is really allowing them to kind of push their efficiencies.
And then we also have a lot of confidence in the play.
Just with just with the overall performance and stuff is where the Mallory and then from there as we talked about we want to go ahead and gather the data and the upper overlying formations like the Niobrara. So we can develop that later in the future and then also.
Additional confidence in the play I think would be really.
<unk>.
Should be said is that the infrastructure acquisition that we had we had noted that in our 10-Q.
We acquired evolution and I'll go ahead, and let maybe Lance say a couple of things on that.
Yes, no. Thanks, Jeff Yeah, just to add to that on our confidence and when we think about the powder River basin. We did make a strategic investment there that was about $135 million and we view that as a bolt on acquisition and Thats really midstream footprint Theres, a plant and gathering system that just overlays our southern acreage the plants a first class asset.
It was completed in 2019 and when we think about this is just really complements our existing gas gathering infrastructure build out as we have connections in place. So we really look at that as value because we can load that plant until the plant very quickly and there is also other benefits that we see a long term as well. So we think about just lowering cash operating costs gathering processing expense.
For third parties will have control and redundancy, but then also to the confidence we can expand that very quickly.
So the last thing I'd, just let that plan to help the gifts there as well.
Just wondering you mentioned that plant would that boost the desk they are a little bit as well.
When we think about that we think about actually the gathering processing transportation expense. So it's absolutely when we think about loading it with our equity gas into that facility and haven't been control, we're definitely going to see better net backs.
But its more of as we think about just controlling our costs and lowering our cost basis of the company that's going to absolutely make the powder River basin and the southern acreage Theyre more competitive.
Thank you. The next question is from the line of Bob Brackett with Bernstein Bob.
Good morning back to the Wolfcamp co development, if youre hitting two plus targets in the Wolfcamp versus say Cherry picking the best zone, all things being equal you would expect wells to get worse, yet youre seeing wells get better is that attributable completely to the design change.
No I'd say, it's attributed to our co development strategy I mean, it's.
Really it's been a process over time. So if you look at back in 2016 in the Wolfcamp I should say our strategy through the whole Permian, we had six unique targets and kind of fast forward here, we're up to 18 unique targets and obviously with that the spacing has changed both in zone and from <unk>.
Article perspective, so our teams have methodically obviously tested this taken into account the actual spacing how they interact the depletion to it and we've come up obviously with the best co development strategy really to maximize the overall production of those intervals and then obviously maximize.
The economics related to it.
Great I guess the follow up would be so it sounds like the co development strategy is driven by that desire to maximize the lack of communication between zones or is it more driven by just the logistics of having that kit sit in one spot for a longer time.
No. It's really it's about maximizing the overall resource there as you said so we do have the optimal amount of communication to we're actually able to.
Optimize the recovery and then like I said really maximize those economics.
Thank you.
Next question is from the line of Arun <unk> with Jpmorgan Arun. Please go ahead.
Yeah. Good morning, I wanted to come back to the new completion design.
You highlighted how you've tested this on 39 wells and you plan to go to 70 wells.
My question is was the 20% uplift relative to wells in the same area of relative to the to your type curve.
And maybe the follow up is are the 70 wells contemplated for this calendar year and whether that.
Was that.
Part of your guidance does that include that or would that reflect an upside risks to your oil guide.
Yes, Arun this is Billy.
So the the uplift we're seeing.
Part of that was actually baked into our guidance, we didn't bake in the entire amount. So when we put together our plan we understood that there were going to be some uplift. We did plan on 70 wells to be part of that calendar year program.
And we baked in some of that into our production guidance knowing that we would see some uplift I think the uplift is surprising us a little bit more to the upside, but I would.
I would say that's already.
Factored into our guidance that we've issued.
And then as far as the what we're doing there.
What we're finding that that the target is.
Is critical so the rock type as critical to why it works in some areas and so we're cautiously moving through our program to make sure we test.
As we go to understand which.
<unk> targets lend themselves best to this design change and which ones don't because it does cost a little bit more and we wanted to be very disciplined on how we apply that.
Across the fields that we maximize as Jeff as Jeff was saying the economics of the play.
Okay and just my follow up is any update on beehive in Australia timing.
Yes, Arun on behalf, we're still excited to be able to drill that well, but it's.
It's going to be probably in the first half of next year before were able to get that well drilled.
And Thats, just really due to some timing on permits and those kind of things.
The next question is from the line of Charles Meade with Johnson Rice Charles Please go ahead.
The next question is from the line of Charles Meade with Johnson Rice Charles Please go ahead.
Okay.
Good morning, David Bailey, Ken in the whole EOG team. There I think just a couple of quick ones for me.
Touching on some of the common themes that you've already spoken on for a while.
The Toronto evaluating the slowdown.
Can you give.
Some exciting Youre thinking is this is this about the natural gas price falling below your $2 50.
Double premium or is this is this about the contango you've seen in the curve and just the value.
Of just waiting a few months or is it I recognize those arent exclusive but just some insight what really Keith.
Keith you guys still went up.
<unk> in that.
Yes, Charles this is Billy.
It really has not triggered on a specific gas price, but just the overall softness we see in the current market conditions and the need to <unk>.
Simply bring more gas on in this current condition.
Near term, we understand the near term softness in the market, but longer term medium and longer term, we're still very bullish on the long term outlook for for gas. So we do look at.
The different flex the flexibility we have in the program and we're evaluating options to be able to to.
Successfully pushed those back in the year and we're just for continue to remain disciplined on our investment to make sure we're maximizing the value to the company over the long term.
Okay. That's helpful. And then just one more quick one on this on this wolfcamp completion design.
Yeah.
I got the message I think in your last.
<unk> response to the last question that this is not done. This this is not going to be an across the board.
Shift that you'd want to make but presumably you've confirmed I think if you're talking about 16 targets. It works and can you give us a sense does it work in a quarter of the targets and maybe upside to the half or three quarters or what is it what's it look like do you guys right now.
Okay.
Yes. This is Jeff again, yes that is correct.
It's not necessarily a one size fits all across it really does have to do with the geology that we're applying it to and when looking particularly there in the Permian, we primarily just apply to down in the deeper wolfcamp targets. So that would basically be just kind of the upper down through the middle in a co development standpoint, now we are testing I don't know shallower targets, but there are.
Quite a few different rock types. So.
Right now I'd say, it's area by area.
From a percentage basis, you kind of hate to put an actual percentage on it but.
Right now, we're still evaluating that and there will be a case by case basis.
Thank you.
Question is from the line of Neil Mehta with Goldman Sachs Neil.
Hey, good morning team.
My question was on the natural gas liquids market, where realizations, obviously have been trending lower yeah. Just curious on your perspective on what gets.
Ngls to firm up relative to <unk> and what are you seeing real time in.
In the export markets.
Yes.
Danielle good morning, it's Lance.
I think what youre going youre continuing to see absolutely the <unk>.
Export.
<unk> that are getting built out I think as you you kind of have to think of those kind of as we think about them kind of more on ethane and more on propane so continuing to see healthy propane exports. We continue to see that build out that's accompanied with that youre continuing to see the demand as you think about the far east demand Thats.
Going to be the demand pool for those barrels so continuing to see that there can be some firming up there kind of maybe more longer term ethane, obviously is going to float a little bit more with gas prices and thats kind of like what youre seeing today.
Great and then.
Just curious on your guys' perspective on.
On the gas markets as well you've talked a little bit about.
Its slowing down potentially in terms from a drilling perspective, but how do you see the balances moving from here and a weather normal way over the course of the year.
Yeah.
Yes, Neal good morning, this is Ezra.
As stated.
Say it again in the opening remarks, we still remain constructive on kind of the longer term gas story for the U S. We think that the U S, especially.
<unk> being a big piece of it has really captured.
Low cost of gas supply that can really compete on a global scale.
With the amount of LNG.
The U S is exporting right now, which is which is at record levels right now for the for the U S. Combined with the number of projects have made it through a financial or a final investment decision and then the additional projects that are still being kind of planned and discussed the U S will be long term position to be really a global leader.
In the LNG market now gas is always difficult because it is highly volatile when it comes to things like the short term pricing on weather and it's one reason you've heard this morning.
From both myself, Ken and Billy.
The most important thing we look at when we developed Dorado is to really invest in that at the right pace for the long term, we want to make sure that we're not out running our learnings.
Appropriately invest to be able to keep our costs low and at the end of the day really keep our margins why we wanted to put in the correct infrastructure to keep our our low operating costs because the margins are always pretty skinny on gas and the low cost producer.
For gas is going to be able to be exposed to the global market here in the U S for the long term.
Thank you.
The next question is from the line of Josh Silverstein with UBS, Josh. Please go ahead.
Yes. Thanks, good morning, guys, maybe sticking with gas first.
I mean, usually wide gap on your differentials.
Even after reporting our first quarter results can you just talk about.
How you think that may favor over the course of the year, what youre looking for to come in towards the high.
The high end versus the low end there.
Yes, Josh Hey, good morning. This is Lance I believe when we think about our guidance I think we were just just below the midpoint of the guidance on our realizations. So from a cash standpoint, and then you've seen kind of our guidance for the full year and we expect a lot of that is going to be driven obviously, we have the diversification.
We have with our California exposure, we have you can see on our supplemental slide slide eight you can obviously see the large exposure that we have into the Gulf Coast and then obviously, our <unk> exposure as well. So I think we're going to hold with existing guidance that we have.
Got it and then just as far as the shareholder return profile I know you've been thinking about it from a percentage of free cash flow.
But how would you think about it from managing a cash balance standpoint, you've been.
Over $5 billion now for the past few quarters, including paying down the debt maturity in the first quarter.
Is $5 6 billion and the right level of cash for EOG, what level of cash would you not want to get over.
Because it feels like there are certain periods, where you can return over.
100% of cash or free cash flow to shareholders. If you really wanted to thanks.
Yes, Josh this is Ezra when we came out with that cash return guidance with a minimum of 60%. We really did just mean that that it's a minimum in fact last year, we returned excess of 60%.
Free cash flow to our shareholders and we started with that 60% because we feel confident on that especially when we roll in.
Yeah.
Kind of an almost.
Our peer leading regular dividend that we'd be able to compete.
Compete and deliver that through the cycles. So when we think about.
Specific target for cash on hand, I wanted to say that we have real target we have spoken about some.
Some indicators and things that we strategically think about as far as holding our cash balance. The first of course is we like to have a bit of cash on balance just to run the business to make us allow us to stay out of commercial paper and historically, that's around about $2 billion kind of depending on at what point you are in the cycle and then in addition to that we do like.
To have cash on hand, so that we can be strategic and counter cyclically invest in opportunities as they arise whether thats.
At times, investing and casein or line pipe or last year, we were able to step in and do an acquisition in one of our emerging plays there in the Utica, where we actually purchased approximately 130000.
Mineral rights and then lastly of course, just the stock repurchase, which we exercise here in the first quarter.
We've talked about being able to utilize that opportunistically and.
Really part of our strategy. The reason that you can you can actually step into a dislocated market and have the confidence to do.
Our buyback is that you've got the strength of the balance sheet, which includes cash on hand.
That's really what we're going for and so I think that provides another compelling reason to carry a.
Potentially a higher cash balance than the company's historically done.
Thank you.
That concludes our Q&A session for today I'll now turn the call back over to Mr. Jacobs for any closing or additional remarks.
I just wanted to thank everyone for participating on the call. This morning.
And I, especially want to thank our employees for the outstanding results. They delivered in this first quarter. Thank you.
That concludes the EOG resources first quarter 2023, earning results conference call. Thank you all for your participation you may now disconnect your lines.
Yeah.
Yeah.
Okay.
Okay.