Q4 2022 EOG Resources Inc Earnings Call
[music].
Yes.
Good day, everyone and welcome.
The fourth quarter.
Kikuchi unexercised and scopes.
Cool.
Okay.
Right.
Gotcha.
Great.
Okay.
Please go ahead Sir.
Good morning, and thanks for joining us.
This conference call.
Thanks, Dave.
Okay.
Perfect.
Okay.
Okay.
Please go ahead.
Okay.
This conference call also contains certain non-GAAP financial measures.
Sure.
Reconciliations for these non-GAAP measures can be if the company achieves website.
For each of our restaurants.
Okay.
Yes.
And estimated resource potential.
We calculate it.
The SEC's reserve reporting.
<unk>.
Participating on this call.
That's a pretty big chairman and CEO Bill.
Billy Helms.
Chief operating officer.
Okay.
VP exploration and production.
Whitestone EVP exploration and production.
<unk> senior VP marketing and David Streit, VP Investor Relations Here's Astra.
Thanks, Tim Good morning, everyone.
<unk> growing portfolio of high return assets delivered outstanding results in 2022, we earned record return on capital employed of 34% and record adjusted net income of $8 1 billion generated a record $7 $6 billion of free cash flow, which funded record cash returned to shareholders of $5 1 billion.
We increased our regular dividend rate, 10% and paid for special dividends paying out 67% of free cash flow, beating and our commitment to return a minimum of 60% of annual free cash flow to shareholders.
And we strengthened what was already one of the best balance sheets in the industry, reducing net debt by nearly $800 million, we continue to deliver on our free cash flow priorities. This year by declaring an additional special dividend of $1 per share yesterday.
<unk> our financial results were achievements made by our operating teams working in a challenging inflationary environment.
Credit goes to the innovative and entrepreneurial teams working collaboratively across our multi basin portfolio.
Together, we leveraged the flexibility provided by our decentralized structure to deliver exceptional operational performance.
Production volumes Capex and per unit operating costs were within guidance set at the start of the year.
We offset persistent inflationary pressures that exceeded 20% during the year to limit well cost increases to just 7%.
Our exploration teams uncovered a new premium play.
<unk> Utica combo.
Vance two emerging plays.
South, Texas, Toronto, and southern Powder River Basin.
We progressed several exploration prospects, including the northern Powder River basin.
We expanded our LNG agreement currently estimated to take effect in 2026 to 720000.
Mmm Btu per day, which will provide JM linked pricing optionality for 420000 Btu per day.
Last year, the revenue uplift from our current 140000.
Btu per day, LNG exposure was more than $600 million net to EOG.
Preliminary results indicate that we reduced our ghd intensity and methane emissions percentage of achieving our 2025 targets and we initiated an expanded deployment of our new continuous methane leak detection system called <unk>.
Led by the tremendous performance in our Delaware Basin and Eagle Ford plays our operating performance and financial results. In 2022 are a reflection of our asset portfolio and the unique organizational structure in place to support it.
Seven teams in North America, and one international team operate 16 plays across nine basins are decentralized centralized structure empowers each operating team to make decisions in real time at the asset level to maximize value.
This differentiates EOG and enables us to consistently execute our strategy and produced outstanding results year after year.
Our multi basin portfolio provides numerous high return investment opportunities and we remain focused on disciplined investment across each of our assets.
In addition to our premium well strategy, and which wells must generate a minimum of 30% direct after tax rate of return at a flat $40 oil and $2 50 natural gas price for the life of the well we invest at a pace that allows each asset to improve year over year, lowering the costs and expanding the margins generated by each asset.
It <unk>.
Disciplined investment means more than just expanding margins at the top of the cycle. It means delivering value for the life of the resource and through the commodity price cycle.
Not only developing lower cost reserves, but also investing strategically to lower the operating cost of these resources, which positions EOG to generate full cycle returns competitive with the broad market.
<unk>.
Looking ahead to 2023 EOG is in a better position than ever to deliver value for our shareholders and play a significant role in the long term future of energy.
Our ability to reinvest in the business delivered disciplined growth lower our emissions intensity earn high returns raised the regular dividend and returned significant cash to shareholders all while maintaining what we believe is the best balance sheet in the industry is due to our differentiated strategy executed consistently year. After year now here is <unk>.
Tim to review our financial position.
Zero.
When we established our premium strategy back in 2016, our goal was to reset the cost base of the business to earn economic returns at the bottom of the price cycle.
The impact premium has had on the cost basis of the company and our financial performance has been dramatic.
Since 2014 prior to establishing our premium strategy, our DD&A rate has declined 42% and cash operating cost by 23%.
Also in 2014 and under similar oil prices. This last year, we earned 15% our oce.
With our lower cost structure, our Oc increased to a record 34% in 2022.
We have also reduced net debt last year by $800 million to further strengthen the balance sheet.
We view a strong balance sheet as a competitive advantage in a cyclical industry.
Our current balance sheet is among the strongest in the energy industry and ranks near the top 20 percentile of the S&P 500 in terms of leverage and liquidity measured as net debt to EBITDA and cash as a percentage of market cap.
We have a $1 billion to $5 billion bond maturing in March and intend to pay that off with cash on hand.
Our 2023 planned is positioned to generate another year of strong returns.
We expect to grow oil volumes by 3% and total production on a Boe basis by 9%.
At $80 <unk>.
And $3 25, Henry hub, we expect to generate about $5 $5 billion of free cash flow for.
For nearly 8% yield at the current stock price and producing our oce approaching 30%.
This attractive financial outlook, along with our strong balance sheet is what gave us the confidence to declare a $1 per share special dividend to start the year on top of our regular dividend of $82.05 per share.
As a reminder, our commitment to return a minimum of 60% of free cash flow considers the full year not a single quarter in isolation.
The special dividend reflects the confidence in our plan and our constructive outlook on oil and gas prices.
We will continue to evaluate the amount of cash return as we go through the year with an eye on once again meeting or exceeding our full year minimum cash return commitment of 60% of free cash flow.
Here's Billy to discuss operations.
Thanks, Tim.
I would like to first thank each of our employees for their accomplishments and execution last year.
2022 was a challenging year and the commitment and dedication of our employees remains steadfast as they delivered outstanding results.
Last year, it can be characterized as a year of heightened inflation.
We witnessed increasing commodity prices accompanied by higher levels of activity across the industry.
The result was a much tighter market for services labor and supplies.
We were able to offset most of this inflation through efficiency gains.
And capital management across our portfolio to limit well cost increases you're just 7%.
For the full year oil production was above the midpoint of guidance, while capital expenditures were $4 6 billion.
We're only two 2% above the original guidance midpoint said at the beginning of the year.
Our operating teams work working throughout the company leveraged efficiencies to help offset inflation.
This is most evident in our core development plays which sustained sufficient activities to support continued experimentation and innovation.
In the Delaware Basin, we expanded use of our Super Zipper completion technique.
The increase traded lateral feet per day by 24%.
And our Eagle Ford play the completions team increased completed lateral feet per day by 14%.
And the amount of sand pumped per day per fleet by 27%.
Our decentralized operations team are.
<unk> continually striving to improve performance and share learnings across our portfolio to limit well cost increases.
These learnings are then deployed in our emergency emerging opportunity plays for.
For instance, in the southern Powder River Basin Mallory play the drilling team decreased drilling time by 10% with improved bid in drilling motor performance.
In our South, Texas Dorado gas play the operations team reduced drilling time by 12% through technical and operational advancements they promise to continue to drive improvements in 2023.
Beyond cost reductions a new completion design implemented last year in the Delaware Basin.
Realizing positive improvements in well performance in certain target reservoirs.
This new design was tested in 26 wells last year and is yielding as much as an 18% uplift and estimated ultimate recovery.
We're also making great progress towards our long term ESG goals.
Our wellhead gas capture rate exceeded 99, 9% of the gross gas produced and preliminary.
<unk> results indicate that we lowered GHT intensity and methane emissions percentages in 2022.
We now have approximately 95% of our Delaware basin production covered by <unk> or.
Our continuous methane monitoring technology.
Now turning to the 2023 plan.
<unk> forecast of $6 billion capital program to.
To deliver 3% all volume growth and 9% total production growth.
We expect total volumes on a Boe basis to grow each quarter through the year.
First quarter will show more growth in gas versus oil due to the well mix and timing of several dorado gas wells that were completed late in the fourth quarter of last year.
The plant can be summarized in the following four points.
First.
Drilling rig and Frac fleet activity in our core development programs, specifically, the Delaware Basin and the Eagle Ford.
It will be relatively consistent with the fourth quarter of last year.
The longer term outlook for the Eagle Ford is to maintain the current production base, where we have over a decade of continued opportunities to generate high returns and cash flow.
After a decade of stellar operational improvements in the Eagle Ford.
It has become a highly efficient high margin play with existing infrastructure and access to favorable markets.
In the powder River basin, the planned builds off last year's positive well results and infrastructure installation with an additional 20 Mallory completions.
We expect to complete a few additional wells in our emerging Utica play in Ohio, as we continued to delineate our acreage position and drill a few wells in the Bakken and DJ basins.
And Dorado, our plan is to achieve an activity level that creates economies of scale and develop a continuous program to allow for innovation that drives improved well performance and cost reductions.
This results in a moderate increase in activity completing about 10 additional wells versus last year.
In Trinidad drilling rig is now scheduled to arrive in the third quarter, which is about a six month delay. So international volumes decreased 60 million cubic feet per day, or 10000, Boe's per day versus our earlier estimates.
Overall, we increased activity in our emerging plays.
The average rig count for the year is expected to increase by about two rigs and one additional frac fleet.
Second we have line of sight to efficiencies that we expect will limit additional inflation pressure on well cost to just 10% versus last year.
Year over year increases in tubular cost as well as day rates for drilling rigs and Frac fleets are the main drivers of the increase.
As part of our contracting strategy, we stagger our agreements to secure a baseline of services and secure.
Consistent execution.
For this year, we have locked in about 55% of our well cost which is a similar level to previous years.
Approximately 45% of our drilling rigs and 65% of our Frac fleets needed for the year are covered under term agreements with multiple providers.
By maintaining this consistent basis services, we expect to find additional opportunities to drive performance improvements and eliminate downtime, thus potentially providing opportunity to offset some additional inflation.
Third.
Our 2023 capital program includes additional infrastructure investment.
Typically funding for facilities and other infrastructure projects comprises 15% to 20% of the Capex budget and this year, we expect that number to be closer to 20%.
And Dorado, we commence construction late last year on a new 36 inch gas pipeline from the field to the Agua Dulce sales point near Corpus Christi, Texas.
This pipeline will help ensure long term takeaway.
Fully capture the value chain from wellhead to the market Center.
Support expanded LNG export price exposures due to come online around 2026.
And broadened our direct interstate pipeline capacity to reach markets. So along the entire Gulf Coast corridor.
We're also undertaking smaller infrastructure projects in other areas like the Utica.
To lower the long term unit operating cost.
Fourth we plan. The plan includes capital there represents the next steps towards our vision of being among the lowest emissions producers of oil and natural gas.
Our first Ccs project has begun injection.
And we will continue to explore opportunities to enhance our leadership position in an environmentally prudent operations.
These projects offer healthy returns.
While also providing reductions in long life unit operating cost and lower emissions.
EOG remains focused on running the business for the long term.
<unk> generated high returns through disciplined growth.
Improving our resource base through organic exploration.
Improving our environmental footprint and investing in projects that will lower the future cost basis of the company.
I am excited about 2023 and the opportunity it brings for our employees to further improve the company.
Now here's Ken to review year end reserves and provide an inventory update.
Thanks, Billy our 2022 proved reserve replacement was 244% for a finding and development cost of just $5 13 per barrel of oil equivalent excluding revisions due to commodity price changes our proved reserve base increased by 490 million barrels of oil <unk>.
Equivalent and now totals over $4 2 billion barrels of oil equivalent. This represents a 13% increase in reserves year over year and was achieved organically.
2022, we also reduced our finding and development costs by 8% compared to the previous year and.
In fact over the past five years, we have reduced finding and development costs by nearly 40%.
Our permanent shift to premium drilling combined with our culture of continuous improvement focused on efficiencies driven by innovation, our why our corporate finding costs and DD&A rate continued to decline.
We continue to focus on maximizing the long term value of our acreage for example last year. We continued co development of up to four wolfcamp targets. The pursuit of secondary targets with wells developed in packages alongside traditional development benches generally have minimal production.
<unk> on the primary zone, however, carry a favorable investment profile because they require no additional leasehold investments are drilled and completed on existing pads and produce into existing facilities and gathering systems.
The goal is to deliver low risk high returns that maximize the cash return potential of our assets.
Looking out beyond our current proved reserves, we've identified over 10 billion barrel equivalents of future resource potential in our existing premium plays with an expected finding cost refining and development cost less than our current DD&A rate.
When we invest at a finding and development costs less than our DD&A rate, we drive the cost basis of the company down when we invest in high returns combined with our low finding and development costs. It shows up in the financials as increased return on capital employed.
Thanks to the benefits of our decentralized structure and multi basin organic exploration strategy, our resource base is growing faster than we drill it.
More importantly, it is getting better we have over 10 years of double premium drilling at the current pace and we are focused on improving the quality of our resource every year through operational innovation technical improvements and exploration.
Now, let me turn the call back to <unk>.
Thanks, Ken.
In conclusion I'd like to note the following important takeaways.
Yohji resources offers a unique value proposition first it begins with our multi basin portfolio of high return investment opportunities anchored by the industry's most stringent investment hurdle rate our premium price deck.
Second our disciplined growth strategy optimizes investment to support continuous improvement across our portfolio.
Our employees utilize technology and innovation to increase efficiencies and allow EOG to remain a low cost operator.
Third we are focused on generating both near and long term free cash flow to fund a sustainably growing regular dividend support our commitment to return additional free cash flow to shareholders and maintain a pristine balance sheet to provide optionality through the cycles.
Fourth we are focused on safe operations, and improving our environmental footprint across each of our assets utilizing both existing and internally developed technologies and.
And finally, it's the EOG employees that make it happen our culture is at the core of our value proposition and as our ultimate competitive advantage.
Thanks for listening now we'll go to Q&A.
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If you are using a speaker phone. Please make sure your mute function is to hand off to allow your signal to reach our equipment.
<unk> are limited to one question and one follow up we.
We will take as many questions as time permits.
Once again, please press star one on your Touchtone telephone to ask a question.
Your question has been answered you may remove yourself by pressing the pound key.
Just a moment to give everyone an opportunity to signal for questions.
Our first question today comes from Paul Cheng from Scotiabank. Your line is now open.
Alright. Thank you good morning, everyone. Two question piece first.
Alright.
How is your investment program change.
<unk> landscape D&B natural gas point I would imagine that this point gets more economic to pay.
And against that.
That changed your outlook for the next several years on that.
Second question is on the <unk>.
<unk>.
Maybe that it seems like you're investing for the future. So yes.
Thank you Lee.
Capex requirement to maintain production at this point.
For your program and also.
Looking at.
Thank you for that.
Yes.
Andy Agg, yet that you think will stop.
<unk> seen some softening in the calls and which can be lumpy we effected.
Youll Kevin bucket.
Thank you.
Thank you Paul This is Andre good morning, those are both great questions. So let me start with the first one here.
Natural gas and what's it looking like right now.
Correct, we've been watching the recent volatility in natural gas.
Late 2022, and currently associated with the LNG outages in the warm winter that we're experiencing.
Our gas growth. This next year on the plan you will see is about at the midpoint is about 240 million cubic feet per day about 50% of that is coming out of the.
As you mentioned the associated gas from the Delaware Basin and the other half of it's basically coming out of our our Dorado play.
Our strategy to Gerardo I would say it hasn't significantly changed yet.
And at this point, we don't really see.
That it would barring any anything dramatic in the reason for that is it.
Draw it always has been kind of a longer term strategy for us.
We've always focused on having moderate investment there to grow into the growing demand centers along the Gulf coast. It's never really been about chasing seasonal demand are aggressively ramping up activities in that play.
The U S. Just this year, we will have about two Bcf a day of LNG export back online after the disruption is clear.
We've got an additional five Bcf a day coming online and kind of the $24 25 timeframe and then potentially another eight Bcf a day.
Still working through financing and we see this line of sight demand growth is also reflected with the strip price.
Where do you see currently it's moved into contango. So our long term strategy and Gerardo really remains the same its investment at a pace, where the asset improves each year.
Given us an ability to drive down both upfront well costs and long term operating costs, where we can consistently deliver the low cost of supply. This year as Bill stated, we will be moving towards the one completion crew program.
To really capture those efficiencies at Dorado.
The first part of your second question I believe is on sustaining capex.
And what I'd say is the sustaining capex is a number that we don't necessarily focus on here is an organic.
Growth company and the reason for that is even during 2020, we didnt maintain a maintenance capital type of program.
We are very dynamic.
We'll grow when we see the ability to invest in our business and the market supports it and when we don't need to we can pullback at that time as well so maintenance capex is not necessarily a number that we look at now as far as break evens on our capital program. This year.
It definitely is up a little bit year over year as Billy mentioned there is some inflation in there, but also we're obviously seeing the opportunity to invest in our multi basin portfolio and increase the capex. So our Capex program. This year is at $44 <unk>.
<unk> price with a $3 25 gas price and I'll, maybe hand, it over to Billy to give a little bit of color on inflation and where we see it going this year certainly.
On the inflation front I think it's safe to say that everybody is saying.
Commodity prices falling we saw.
Seen in inflation rates have peaked and come down and so we're seeing a lot of the service cost at least have plateaued.
Going into this year and so.
As I mentioned on the call, we've got about 55% of our well cost secure through existing contracts with the.
With our vendors and that leaves us the opportunity to capture any upside that we might see in lower rates going into the year.
So.
We're sitting in a fairly good position I think.
We're going to be poised and waiting to see what happens in and take advantage of opportunities as they present themselves, but I think inflation at least is showing that we've plateaued, we baked in about a 10% inflation into our plan and as we see opportunities. We will continue to look for ways to improve that.
Okay. Thank you.
And we have the opportunity.
Okay.
I think what we've seen.
<unk> seen as one of the biggest drivers of this last year on inflation was certainly <unk> casing cost and I think we've seen.
Different things in different parts of that makeup I think the EUR W. Products is it mostly the surface and intermediate casings those have rolled over and are softening a little bit more than the production casing, which is your stainless products, which.
They are still largely exposed to imports.
So youre seeing some opportunities on casing, but I think there is still yet to come most of that on the on the service side I think we haven't really seen anything manifest it yet, but I think we've all seen.
<unk> counts have largely been flat since September and Theyre down off their peak of it.
In November of probably 20% 25 rigs.
With the drop in gas prices I think everybody is expecting maybe we will see some more softening on the rig activity level. So that may lead to some opportunities to capture some markets. The one advantage that we have and I will go ahead and throw this out when may expand on it later, but.
The benefit we have is operating in multiple basins.
And so we see certainly more service tightness in labor constraints in areas with the most activity, which would be the Permian, but we have the opportunity to shift activity to our other basins to enable those to take advantage of.
More available equipment or available capacity to add services.
Favorable rates. So that's the advantage that we have as a company.
Our next question today comes from every Jai <unk> from J P. Morgan Your line is now open.
Yes, good morning.
As you have a net cash balance.
And if we run through call it the $80 case.
55.
$5 5 billion and free cash if you return.
50% of that Youre looking at our balance sheet that would be call. It $3 billion in net cash at year end. So I wanted to get your views on uses of that cash.
Cash.
On the balance sheet, and where your head's at in terms of thoughts of increasing cash return to shareholders.
<unk> looking at inorganic opportunities, including bolt ons or M&A and how would you prioritize some of those opportunities as we think about 2023.
Yes, good morning, Arun It sounds great. That's a great question.
I love talking about our balance sheet and the strength of its something that we would take a lot of a lot of pride in and the reason for that is because it gives us a lot of optionality.
Current times, whether it is to look at.
In 2020, we purchased strategically purchased a lot of casing in 2021 were able to purchase a decent amount of line pipe and just last year, we were able to make.
Small acquisition in the Utica play, including purchasing some minerals there.
So were still not looking for any large expensive corporate M&A, we do.
Continue to seek out opportunities, where it makes sense to do bolt ons things that would be accretive things that could move right into our existing infrastructure and extend some of our lateral lengths.
In general for our net cash position I would say, we don't have a specific target.
We do like to have the Optionality of the one thing you didn't mention is that we will be retiring a bond here.
In this first quarter at $1 2 billion.
And then in addition to that I would point out that last year, we did move beyond our minimum commitment of that 60% return of free cash flow to our shareholders.
Last year, we returned approximately 67% and so I think you can see you can take that as a data point that.
When appropriate and at the right time and obviously it's.
Value added at the board level.
Depending on where we're at within the cycle, where we're at within the year and what our cash position looks like.
We have proved that we're willing to move above and beyond the 60% minimum threshold.
Great My follow up.
Just given the size of the company Youre approaching 1 million Boe per day in terms of overall output.
And.
Most of your activity is short cycle oriented.
And I wanted to get your thoughts on.
On exploring longer cycle opportunities youre seeing some of your peers invest in areas such as Alaska LNG.
I wanted to get your thoughts on <unk>.
Looking at the long cycle, and perhaps an update on where we stand for to drill beehive in Australia.
Yes, Arun we can start maybe with some of our longer cycle stuff. We can start with Trinidad as Billy mentioned, there has been a bit of a rig delay on our Trinidad drilling program. So that'll start about mid year. This year, we did set a platform.
Their base this past year based on the one of the discoveries that we made in 2020, we should start construction on another platform. There named Demento. Later this year also based on some of the work that we did in that drilling campaign that ended in 2020.
So that's on the Trinidad side in Beehive in Australia, our prospect on the northwest shelf that prospect is actually slid a little bit it's now time to be spud in two.
2024, and then with some of the other projects that you had mentioned.
As you can see and it goes in line with what we were just talking about with the ability of our balance sheet.
To be strategic and opportunistic and typically we do these things counter cyclically like our agreement on the LNG side or the ability to put in some infrastructure like we are currently in Toronto to go ahead, and lower our operating costs and expand our margins. Those are the type of opportunities that we really look forward things that are.
In concert with our core business, which is drilling and developing premium oil.
Oil and natural gas wells.
Our next question today comes from Doug Leggate from Bank of America. Your line is now open.
Thanks, Hi, good morning, everybody.
So Tim I don't know if this one's for you or for Azure, but your comments about being able to offset some of the inflation.
Been a fairly consistent part of your messaging over the last year. So I think folks were maybe a little surprised by the Capex number.
So I wonder if you could walk us through the moving parts of whether it be activity lag or more.
Pacifically infrastructure related to some of the Europe places a disproportionate amount of.
Take are we spending.
This may be a lifting the capex issue I'm just curious on the on the breakdown.
Yes, Doug this is Billy Helms, So let me take a stab at that.
So.
First theres, probably three buckets, you can probably put the increase in first of all as inflation and our well cost. That's that's probably a good piece of that is a third of it is about where it is.
We're anticipating about a 10% well cost inflation.
And our program versus last year and yes that's.
Maybe.
10% over and above last year, but still last year, we achieved only a 7% well cost.
Greece in spite of probably arguably 15% or 20% inflation. So I think our teams have done a great job on offsetting inflation with efficiency gains we're expecting more of that this year, but we've baked in about a 10% cost increase the second part of that is going to be infrastructure, we've talked about.
Already our Dorado gas pipeline.
<unk> been initiated and we're also building out some.
Some infrastructure and some of our emerging plays like the Utica to start the testing of those plays.
And then we've also included some capital for our ESG projects that were advancing so.
Those are kind of the buckets that we look at and then obviously we have some additional wells on top of that and these various plays so as we pick up the two additional rigs and one extra frac late of course, thats going to accompany some additional well count. So those are the three main buckets that I would.
Characterize the increase in the capital versus last year.
Okay I appreciate the color Billy Thanks for picking that went up.
My follow up is probably for us as well forgive me for this one but I wanted to take you back to pre Covid when.
<unk> is growing quickly and frankly, our market didn't meet the oil.
You could make the case that today, we've got a market that doesn't need the gas.
I understand your point about maybe trying to take.
Marcus from others are cutting back but the fact is we still have a lot of responded market in the U S. Why is this the right time.
To accelerate your gas production given what is.
Potentially very constructive outlook longer term.
Yes, Doug that's a good question, yes, I think the difference is.
Between 2000, 2019 or pre COVID-19 with the oil versus what we're doing in <unk> right. Now so I guess the drop of volumes are anticipated to support its basically the output of a single completion spread program. This year.
And the benefits that we see a running a consistent program there to learn about this asset continue to drive down costs support putting in some infrastructure things like.
Water takeaway in basin gathering that outweighs the near term.
Volatility in the gas price because what we see is in a very not too distant future, we see a pretty dramatic increase in the offtake and the demand come in on along the Gulf Coast now we are Backstopped and supported obviously with investing on the return side and these premium wells. So we measure the investment on here at a $2.
50, natural gas price and today's prices Thats below we run that $2 50, all the way through the life of the asset.
Yeah.
The rest of the gas so we're growing this year as honestly as we as I said at the top of the Q&A is really associated gas coming out of the Delaware Basin.
Where the returns there are dominantly driven obviously on the oil and liquid side.
And we're really running a maintenance program or.
Flat activity level program to Q4.
The Delaware Basin.
Our next question today comes from Leo Mariani from MK Partners. Your line is now open.
Yeah.
Yes.
Hi, I was hoping you could update us a little bit on maybe some new well results. If there are any from some of the emerging plays most interested in hearing about.
Any recent Utica, well performance or any Utica wells that may have come on and then similar just in the <unk> just trying to get a sense. If you have seen improving wells there as well you've talked a lot about cutting costs in CRB, but just curious as to whether or not some of those wells.
Improvements as you guys have gotten more experience.
Yeah.
Yes. This is Ken I'll take the Utica portion of that the four wells were drilled and completed in 'twenty to really continue to deliver.
Expected performance in <unk>.
And just to give you a flavor on that we anticipate starting our drilling program for 'twenty three at the end of the first quarter here. One other thing I would note in the Utica not on the well side, but on the acreage side as we have added about 10000 acres of low cost acreage to our position and we will continue to look for additional opportunities to add to that position. So we're.
We're really excited about the Utica plan for 2023, I'm going to go ahead and give it over to Jeff now for the powder, yes.
Yes, Leo this is Jeff just a quick update in 2022, we continue to delineate our acreage there in the southern Powder River Basin, we completed about 31 net wells across the four primary targets and all of those we had excellent results.
And we've been shifted our primary focus there as we've talked about previously to the Mallory. So in 2023, we're going to ramp up the activity a little bit there, we're going to run kind of a consistent two to three rig program with one Frac fleet.
So that'll be about 55 net wells and the majority of those as we talked about will be in the Mallory, it's about a 75% increase year over year Theyre in the Mallory and then we will continue to focus on optimizing that Mallory program. There in our southern Powder River Basin core area, we will collect a lot of valuable data and then we will look to utilize it in the future on our overlying Niobrara formation.
And then the North powder River basin position that we announced earlier on.
Okay. That's helpful. And then just wanted to jump over to the Eagle Ford If I look at the Eagle Ford production has kind of been steadily dropping.
Last year, you guys had picked up activity pretty significantly in 'twenty three it looks like roughly 50% more net completions this year versus last and your prepared comments you take hold are basically trying to kind of keep eagle Ford flattish for a number of years.
Sort of going forward just wanted to get.
Any additional color around that Eagle Ford had counted that in decline in favor of.
Other players, primarily Delaware and now the plan is to kind of flatten it out or you're kind of seeing new things there in terms of well productivity or lower costs that have got more encouraged about the play I just wanted to get a sense because it seems like maybe it's a resident slightly in the pecking order here.
Okay.
Yes, Leo this is Ezra.
That's a great pickup it's a good question because thats exactly whats happened is that it is.
<unk> up with with.
With respect to the returns and the way they compete for capital over the last couple of years kind of coming out of the pandemic, we've reduced our investment there and the result of that we've been trying to right size. The investment and the result has been really back to back years of the highest drilling rate of return drilling programs that we've seen in the history of developing that asset.
As everybody knows it's very high margin oil play.
We've got a lot of infrastructure and a tremendous amount of industry knowledge there.
Simply the.
The asset now is commanding a lot more capital investment. This year, we are looking to invest to maintain flat production as you said.
Production has decreased a bit over the last couple of years and one advantage that we are seeing in the Eagle Ford and Billy touched on this maybe I'll, let him add a little more color on it is really how the inflation and service availability has manifested itself.
Across these different basins and why the Eagle Ford is a bit more attractive.
Sure.
As I mentioned earlier in some of the questions.
Obviously, you see more levels of inflation and more.
Constraints on services in certain fields versus the other the Permian being the most active place certainly there is a.
More.
Constraints their own services and labor in those kind of things. So it allows us the opportunity to pick up activity in basins that are seeing less stress you might say in the Eagle Ford certainly being one of those on top of that our team. There Nagel Ford has done just a tremendous job continuing to push innovation and striving for efficiencies.
Such that we continue to to make better and better returns in that play with time and we've kind of reached a point is as I mentioned, there that we want to maintain a constant level of production going forward in that place because we do see more.
More than a decade of running room is continuing to maintain that production level with the opportunities. We have in front of us. So we think it's just a good level of production to maintain going forward.
Our next question today comes from Neal Dingmann of Suntrust. Your line is now open.
Good morning. Thank you Regina. Thanks for the time. My first question is on your play detail specifically was looking at small than slides I see a couple of years ago. You. All suggest that you had approximately about 11500 premium drill locations with about I think it was nearly 55% of these in the Delaware that Dell about <unk>.
8% of these Dell being Wolfcamp plays I'm, just wondering if it really number one the total premium locations is still I forget what the last number you threw around the Canadian locations and Wonder if you would still consider the majority of the us and the Wolfcamp portion of the Dell.
Yes, Neal this is Ken I'll take a shot at that.
What we talked about earlier and the way we really look at it is we have 10 years of double premium inventory at our current activity level. So the locations really arent a concern for us what we're really trying to to talk about and show us the value proposition of our 10 plus billion Boe.
Resource base that as our finding costs less than our current DD&A rate invest.
Investing in this inventory will reduce <unk> and improve earnings and return on capital employed.
Our well counts are really constantly changing as our development plans evolve acreages swapped and laterals are extended and all of those changes improve our finding costs and returns and modify our location count. So what we're really focused on now is lowering our cost basis as you reinvest at high returns.
No that makes sense and then maybe you can just follow up on that I guess my follow up is on <unk> details, maybe specifically the Bakken you all suggested.
Even a couple of years ago, there wasn't a ton of locations. As you said, maybe I don't know if you would consider it a ton of value. There. So I'm just wondering how many.
How are you kind of look at that play today and would you all consider you certainly don't need it financially, but would you consider monetizing that give it appears to be one of your more mature areas.
Sure Neal.
<unk> can create significant returns and it is one of our highest oil percentage plays that we have in the company, so where its appropriate and wanted to appropriate for development, which is we're going to be putting some money into it. This year, we will try to run about a one rig program there for the foreseeable future.
Thank you.
Our next question comes from Scott Gruber from Citigroup. Your line is now open.
Yes, good morning.
So I saw in your supplemental deck that you've mentioned continuous pumping operations are helping to drive completion efficiency in the Delaware I believe that's one of the benefits you're seeing from running.
Your Frac fleet.
Kevin just a bit more detail on how continuous Brad David.
David completion efficiency above and beyond.
Zippers.
Yes, Scott this is Billy.
Yes, we're thrilled with the advances that are efficiencies driven through our completion teams.
Pumping operation you are right. It is tied to mostly our electric frac fleets.
Just a reminder, we've we're probably running 60 or 70% of our Frac fleets today are our electric and we've been in that business really since about 2015. So we've been operating more electric frac fleets, probably than most of our peers or most of the industry.
For a long period of time and through that way.
Again, a tremendous amount of knowledge of how to continue to drive efficiencies in that operation. It really started more in our San Antonio group in the Eagle Ford play and that's why we're so excited about continuing our investment there.
And certainly we are transferring that information in that.
Those techniques across the company, including the Delaware basin, but basically the continuous pumping operation allows us to minimize any amount of downtime. So we can increase the amount of footage we complete every day.
This drives the well costs down over time.
And allows us to.
Sure.
Approach, some really highly efficient completion strategies and so.
Part of that is also leading to.
Improved completion designs, which is allowing us to make better well performance.
So overall, it's just one thing.
Built on another and we're excited about the future and where that takes us.
Got it and then you also mentioned taking advantage of any softening in the rig and frac rate. They do manifest this year.
How is your contract coverage for both.
We will be able to tighten or would you be able to capture any deflation before.
Would that really.
Benefit more.
More than 24, just given the contract coverage.
Our contracts are really staggered.
And they don't all roll off at any one given time, certainly our well cost is up this year.
I mentioned earlier, because some of those contracts rolled off last year, and we renewed them as higher day rates and pumping charges. This year.
But in general we have about 45% of our drilling rigs secured under term agreements and about 65% of our frac fleets.
So it leaves us ample opportunity to capture.
Opportunities if they do present themselves as time moves on.
Our next question comes from Jeanine Wai from Barclays. Please go ahead.
Hi, good morning, everyone. Thanks for taking our questions.
My first question.
Following up on Leo's question on the Eagle Ford in terms of the step up in activity in the Eagle Ford. This year can you talk about how capital efficiency compares between the overall, Delaware in South, Texas, South, Texas Eagle Ford.
Yes.
When you pull it all data the difference in the web performance looks like the Eagle Ford is about 30% lower on a cumulative oil per foot basis over the past couple of years, but that's only one side of the equation and we realize that.
I think there are three key disclosure indicated that the Eagle Ford well cost is almost 30% lower on a per foot basis than in the Delaware. So I guess just putting it all together for US can you just.
I'll provide some color on how capital efficiency and returns compare between the Eagle Ford and the Delaware.
Yes, Jeanine. This is bill happy to give you some color on that.
The Delaware Basin is certainly one of our most capital efficient plays quickly followed by the Eagle Ford.
We have in the Eagle Ford is as I mentioned earlier, the tremendous efficiencies that have been driven in that play.
You are right Q.
<unk> per foot.
<unk> is probably a little bit lower in the Eagle Ford.
But the well cost is also significantly less and so we can put a lot more wells to sales in a lot shorter timeframe than we can in the Delaware Basin and then it's going back to that also we didn't really feel that we wanted to ramp up activity anymore in the Delaware basin, but instead leverage on our multi based.
<unk> portfolio too to increased activity in areas where.
Equipment and crews are more available to leverage into our operation.
So that's why we've chosen to do but I think the Eagle Ford is still one of our most capital efficient plays we have in the company.
And we were excited about that opportunity to keep sustaining volume going forward.
Okay, great. Thank you for that detail, maybe moving to base declines can you provide an update on your current base declines given the 3% oil and a 9% growth. This year do you anticipate that your oil and corporate declines will remain flat or at least or maybe even decrease this year. Thank you.
Yes, Jeanine. This is Billy again, the base declines have been fairly consistent I would say year to year, and we don't see a measurable.
Change really in our base declines going forward I think.
Last year was a pretty good year is to compare to this year and I expect that declines would be similar.
Yes.
Great. Thank you.
Our next question comes from Derrick Whitfield from Stifel. Your line is now open.
Good morning, all and thanks for taking my question with my first question I'd like to lean into the new completion design that you've implemented in Delaware that achieved an 18% EUR uplift could you perhaps elaborate on the nature of the enhanced and its applicability across the basin.
Yes Derrick.
This is Billy Helms again.
On the new completion design, certainly, we're always experimenting with new ideas and trying to innovate as two ways, we can improve well performance over time and we're excited about some of the new advancements and techniques.
Experimenting with in the Delaware basin and to be honest that's just.
More color on why we like to get to a consistent program.
And where we can innovate and experiment.
And make these improvements.
So I'm not going to go into detail about what this new completion design looks like but certainly as we continue to advance it.
Will translate it to.
And for that technology to other basins and we're already doing so.
We were excited about the 18% uplift we've seen but it's only been done on 26 wells so far in the Delaware Basin. So you can see it's still early on.
The amount of the improvement is tremendous though and we fully expect to be able to transfer that knowledge to other plays.
Perfect.
My follow up perhaps shifting over to the Eagle Ford, we noticed the legacy wet gas position with seemingly re engaged in your supplement update I recall that initial position was in the order of 26000 acres.
Could you perhaps comment on what it's brought it back to like the amount of activity you're expecting over the next couple of years.
Yes, Derek this is Ken yes, really what's brought it back to life as our people and our San Antonio Division have have reviewed it and realized that they could invest in high returns in that area. So we've actually looked at three different zones within that area and drill.
Three wells last year that had significant returns and we will see additional activity. This year I don't know that we've given an exact well count, but it will definitely be stepped up and really it's just a matter of having legacy acreage.
And our people understanding where we think we can make those kind of returns.
That's great. Thank you.
Our next question comes from Charles Meade from Johnson Rice. Your line is now open.
Good morning.
And Billy and the rest of the EOG team there.
I want to follow up on Gary's question, which was.
That was a.
Great question, I'd, just like to push a little bit further on that.
Our base completion design of I understand you don't want to talk about but what it is but.
As I imagine some of the possibilities.
I'm curious is this something that is this something that you applied to one of your your maybe.
Brings year couldn't hear intervals that that's something that bringing that bringing in kind of a lesser interval up to the.
Sure couple of premium threshold or Alternatively is this something that youre doing already on or is this a new design on it.
Let me kind of a meat and potatoes interval.
Maybe.
Harold.
Broader shift higher in your whole Delaware basin capital efficiency.
Yes, Charles this is Billy Helms.
Yes, the new design is.
Really starts with a.
And understanding of the rock, we're applying it to I think we've talked in the past about how all of our designs are tailor made to every wellbore and whatever the geology is telling us the right application for that.
So is it something they look at plasma all zones, I would say probably not.
But it is certainly more attractive than other zones, but it is also being done in the core of the play it's not just applying to the fringe intervals are the fringe of the plays but some of our core plays core target intervals, and we're seeing dramatic improvements now.
Going to be continued to be tailored based on what the geology tells us is the right application.
We'll tweak it and be able to transfer that knowledge as we see it develop.
That's helpful color. Thank you Billy.
For my follow up and I recognize this is a.
Simplification.
For.
Congrats to you guys and your number of rigs and the number of plays but overall you indicated that if youre going to increase youre going to add three new rig lines and 23 can.
Can you give us a sense, where you are in that process or when we should expect those in aggregate.
Rig count could tick up over the course of 'twenty three.
Sure Charles.
The rigs are.
A pretty much in operation today, we started.
Kind of picking up rigs at the end of the fourth quarter going into this year and as we've mentioned.
The fourth quarter run rates in the Delaware Basin, and the Eagle Ford will be pretty consistent throughout the year.
No.
We've also started drilling in some of the other play some of the new emerging plays such as the powder River Basin and Dorado. So those are kind of ongoing will be picking up rigs at different times and some of the other plays like the Bakken or the DJ or the Utica and those will kind of come and go those arent going to be really.
Yet full rig lines, they'll kind of ebb and flow based on the timing of each individual play, but the base program is pretty much going to be said and I'd say the rig count is not going to fluctuate much beyond where it is today.
There are no further questions at this time I will now hand back over to Mr. Jacobs for closing remarks.
I would just like to thank everyone for participating in the call. This morning, and especially thank our employees for the outstanding results delivered in 2022. Thank you.
That concludes today's EOG resources fourth quarter and full year 2020 results you may now disconnect your lines.
Yeah.