Q2 2022 EOG Resources Inc Earnings Call

Where we are in the development lifecycle of that play our multi basin portfolio of high return assets all competitive against our premium hurdle rate provides invaluable flexibility to invest at the pace that allows each play to get better.

It also allows us to plan around basin level market dynamics impacting services and infrastructure to minimize inflation and bottlenecks.

We are able to optimize reinvestment across our total portfolio to add reserves at lower finding costs lower the overall cost base of the company and continue to improve Eog's companywide capital efficiency.

This quarter, we are highlighting <unk>, our continuous methane monitoring system that we piloted in the Delaware Basin and are now deploying in our most active development areas.

<unk> is yet another example of how Eog's decentralized model not only fosters innovation across eight teams, but also our compounds the impact of innovation by taking ideas born in one operating area and expanding them across multiple basins.

From the latest information any information technology, driven solutions to reduce emissions to innovation focused on drilling and completions operations to procurement of casing and sand EOG is unique in its ability to leverage its culture and operating structure to get incrementally better every year.

The tremendous inventory and cost improvements we've made over the last several years provides high confidence in the low breakeven and operational flexibility of our business.

This confidence in our business along with the strength of our industry leading balance sheet.

Susan this quarter to terminate a significant portion of our oil and natural gas hedges.

Going forward, we expect to hedge significantly less than the $20 to 30% of volumes, we typically hedged in prior years.

The current operating environment is challenging given the volatility of commodity prices and inflation headwinds through it all our employees have remained focused on execution and have improved the business.

Our second quarter performance as proof of that we delivered more oil for less capital and in the face of a unique inflationary environment our forecast for capital expenditure this year remains unchanged.

EOG is consistent execution low cost structure reduced hedge position and transparent cash return strategy based on our regular dividend that we have never suspended or cut that has grown 21 of the last 24 years and is now competitive with the broader market puts EOG in its strongest position ever to deliver significant value to <unk>.

Our holders through the cycle.

Here's Billy with an operational update and early look at 2023.

Sandra.

We posted outstanding results in the second quarter.

Our performance included exceeding the midpoint of our production guidance, while capital expenditures in total per unit operating cost beat forecasted targets.

So once again more oil for less capital.

Like to thank our employees for their dedication and persistence to execute and deliver such outstanding results.

As we have guided to all year, our oil growth year over year will be about 4% to return our production to pre COVID-19 levels.

Halfway through the year, we're on track to deliver that objective.

And have done so against a challenging supply chain backdrop.

The upward price pressure on steel fuel and labor continues due to ongoing supply constraints initiated by Covid and extended by the war in Ukraine.

The impact of this has resulted in an inflationary headwinds that have meaningfully exceeded our initial expectations earlier this year, making.

<unk> in an increasingly challenging to maintain flat well cost.

However, our employees continue to innovate and deliver efficiencies that offset a significant portion of this inflationary pressure.

For example, in our Delaware Basin drilling operation.

Our downhole drilling motor program is providing solid performance improvements.

Generating a 13% year over year increase in the footage drilled per motor run.

The motor program and other improvements are reducing drilling times versus last year.

In the Eagle Ford our drilling teams have improved the footage drilled per day by 11% versus last year.

I'll also managing drilling parameters to reduce the cost of drilling fluids are 10%.

In our completion operations we.

We had previously discussed the company's plans to increase the use of Super Zipper completions.

Our 40% faster than normal zipper operations.

We have now utilize this technique on about 65% of Eog's completed wells year to date.

Which is yielding an 11% improvement in the lateral footage completed per day.

Super Zipper completions combined with our focus on more efficient operational practices.

Is increase the amount of pumping hours per day about 24%.

In addition, we continue to progress our self source sand program and expect to further reduce sand cost in the second half of the year and extend those savings into 2023.

All in all we now expect our well cost to see a modest single digit increase over last year and most of this increase will be seen in the second half of the year.

However, we were able to leverage our operational flexibility within our multi basin portfolio, such that our capital and volume plan remains unchanged.

Now turning to the macro backdrop oilfield service capacity remains extremely tight and as further constrained by the limited availability of materials and experienced labor driving uncertainty and the cost of services not only for this year.

But also for 2023.

These constraints are more concentrated in areas with the highest activities such as the Permian basin.

EOG is multi basin portfolio provides us the flexibility to manage these constraints by optimizing activity.

Between our multiple plays to maximize our return on investment.

Just as in the past EOG, we play to its strengths to mitigate where possible.

Inflationary pressure and operational constraints facing us.

We are currently taken steps to secure services for next year, and we'll know more about the 2023 outlook next quarter.

Regarding production growth.

It's too early to discuss next year's plans with any degree of precision.

However, it is important to recognize we will maintain our discipline.

And as we see things today would expect low single digit oil growth similar to this year.

On the natural gas side, we're excited about the results of our South Texas Dorado play.

And its ability to play an increasing role in supplying the growing demand of petrochemical and LNG markets along the Gulf Coast.

As we allocate future capital based on returns.

This play will command additional investment.

Not only to meet the growing demand.

But also for infrastructure needed to capture the value chain from the wellhead to the market Center.

These investments not only generate healthy returns, but ultimately lead to lower well cost and lower long term unit operating cost.

We also expect to fund our emerging and promising exploration plays as we improve the company for the future.

Now here's Ken to give you an update on our emissions reductions effort.

Thanks, Billy this quarter, we are providing details on our continuous methane monitoring project, which is an example of the progress we're making in our emission reduction efforts over.

Over the last several years, our leak detection and repair program or Eldar has advanced from sound sight smell surveys to survey is using more accurate optical gas imaging to today's deployment of scalable solutions of the latest technology continuous methane monitoring this.

This technology detects potential leaks and provides real time alerts to help accelerate repairs and we will provide data and trend analysis to potentially prevent future methane releases.

We've been evaluating continuous methane monitoring technology for a few years. There are several third party systems and technologies available to monitor and detect potential methane leaks, which use intermittent or continuous monitoring technology.

About 18 months ago, we began a pilot project using our solution. We built in house named <unk>, which is a fence line monitoring solution that uses methane sensing technology to continuously monitor facilities and provide real time alerts of potential leaks to a central control room, we tested ICM.

<unk> monitoring solutions and use and available in the market today and confirmed that our sensor detected methane release events consistent with these third party systems.

The results from these tests confirm that <unk> is the most effective solution for EOG to use to detect and accelerate leak repairs will also being scalable and economic.

Like so many of our innovations this technology is being spearheaded by our employees across the company.

Since the pilot our employees are rapidly deploying <unk> in the field prioritizing areas of highest potential impact. The initial installations are focused in the Delaware basin and currently cover about 60% of our production.

We expect that most of the remaining Delaware basin production will be monitored by <unk> by year end, we will continue to rollout <unk> in other operating areas next year.

Using our proprietary system allows us to own the data creation flow in storage, which is a priority with all our information systems owning the <unk> data and retaining direct control of its collection provides invaluable flexibility to improve both data quality as well as the tools to analyze and inner.

Great ice data with existing operational data from our production facilities.

This data along with our ability to monitor our operations for many of our for control rooms will enhance the $24 seven capability to continuously identify prioritize and repair leaks.

In the future when data from my sense is paired with other real time production data, we expect to be able to make improvements in the design of facilities to minimize releases.

We're also optimistic that we will be able to more readily predict the likely size and source of of methane release.

Leveraging technology to enhance our methane leak detection and repair program is another great example of Eog's culture of continuous improvement throughout all our operations.

Our employees have embraced the company's emission reduction efforts.

I am excited to see how eog's culture of innovation and technology will continue to drive creative solutions.

Now here's Jeff to discuss the progress we've made in our premium combo play in the southern Powder River Basin.

Thanks, Ken our emerging Mallory and Niobrara plays in the Southern Powder River Basin have made significant progress recently the powder return to steady development last year. After a pullback in 2020 driven by the pandemic results in 2021 were stellar with respect to both well performance and well cost reduction strong results to date.

Combined with the benefit of infrastructure investments have positioned to Mallory and Niobrara plays to command more capital in 2023 and beyond.

The powder River Basin is an established operating area for both EOG and the industry that has experienced several chapters of development over its history. The latest chapter for EOG kicked off in 2018, when we move the Mallory and Niobrara plays into commercial development, we identified nearly 500 net premium locations between both tar.

<unk> over 130000 net acre position in the southern part of the basin.

Since 2018, we have made great strides in fine tuning our technical model to improve the predictability and performance of the wells, we've delineated the different parts of the basin high grading the specific landing zones.

Basin has stacked potential similar to the Permian with two widespread well known very robust source rocks in the Mallory and Niobrara amongst those two source rocks are hybrid opportunities such as silk zones and sand zones, a whole section of reservoir that really lends itself to horizontal drilling and completions. We have also made targeted infrastructure.

Investments in recent years, which have helped lower the cost structure in each play we have added nearly 40 miles of water pipeline and $2 5 million barrels of water storage capacity, our water infrastructure investment in the PRP has allowed us to source about 90% of our water used in our operations from reuse reducing <unk>.

Cost for both water sourcing and disposal. We have also invested in infrastructure to enable local sand sourcing.

The installation of a high pressure gas gathering system has been instrumental in achieving a 99, 8% gas capture rate.

The infrastructure is also benefiting our operating costs per unit lease operating expense and the powder is among the lowest in the company.

The <unk> is farther from market and some of our other premium plays however, the Mallory and Niobrara has several advantages that more than make up for it.

First and foremost the wells have some of the largest per well reserves in the company on a barrel of oil equivalent basis and the southern PRP. The Niobrara Mallory formations are more combo that as they produce a mix of oil and natural gas. While the laterals are also longer at 9500 feet, which contributes to the higher recoveries.

Performance is mostly due to the quality of the reservoir and composition of the products with a large component of natural gas to support higher recoveries.

Date, EOG has completed about 40, net Mallory and Niobrara wells in the southern PRP. This year, we anticipate completing 15 net Mallory and Niobrara wells and expect to significantly increase that activity next year.

As a result of our exploration work on the entire powder River basin hydrocarbon system over the last few years. We have also built an additional 110% net acre block in the north.

Extending our acreage in the productive fairway to 90 miles.

Northern area is a historically under explored part of the basin and after recognizing the potential in the area, we cored up acreage adjacent to our legacy Yates acreage through a series of trades and small bolt on transactions Utah.

Utilizing reservoir data for multiple plays we identified landing zones in the Mowry, and Niobrara formation with favorable Petro physical and Geo mechanical properties and began testing we drilled four successful delineation wells, which we believe are industry first in the area. While it is still early in the delineation we've confirmed the development.

Potential of our northern powder River basin acreage to add to our future premium inventory.

Mallory and the Niobrara combo plays in the southern Powder River Basin stand today, well positioned to compete for capital within the portfolio and combined with our position to the north the basin has significant investment potential for years to come next up is lance to provide some color on our marketing position in the powder. Thanks, Jeff as we look further down.

Onstream the investment in infrastructure that has lowered the cost structure in the southern powder River Basin also allows us to apply our time tested marketing strategy of establishing multiple connections to provide market pricing diversification.

Today, we hold sufficient processing transportation and fractionation capacity for natural gas liquids out of the PRP, we have access to both the mid continent at Conway, Kansas and the Gulf Coast at Mount Belvieu, Texas, an underappreciated aspect of the Mowry and Niobrara wells as they are prolific NGL production and the <unk>.

Heavier post processing mix of Ngls they produce.

After processing to minimize ethane extraction, our powder River basin NGL barrel contains approximately 10% ethane, 45% propane and the remainder being butane and more of a heavier ngls, resulting in an NGL to WTO price ratio of over 50%.

In the first half of this year, our NGL price realization was 50 301, which is a $7 17 premium to the Mount Belvieu typical barrel. In addition, the quality of the powder River Basin oil is and it has an average API gravity of 44 to 47 and remains in high demand during the first half of this.

Year realized prices for our oil production out of the <unk> or <unk>, plus a $1 63 with access to both Guernsey, Wyoming and Cushing, Oklahoma markets.

Stepping back I'd like to review, our marketing strategy for the company as a whole and all our active development areas, we want to retain control of our products and establish multiple sales points, which adds significant value. For example in the first half of this year, we transported an average of 188000 barrels of oil per day for export.

Which represents about 30% of gross production with Optionality to sell based on a <unk> or a Brent index with a widening of the Brent <unk> spread we have the opportunity to take advantage of our capacity to deliver up to 250000 barrels of oil per day for export.

For propane, we have delivered 19000 barrels per day for export at premium prices to Mt. Belvieu. We also continued to see strong uplift in our natural gas price realizations due to our early mover advantage securing 140000 <unk> per day linked to <unk> am to <unk> LNG facility in Corpus Christi Cheniere recently.

We announced Friday.

Our final investment decision on stage III in Corpus Christi, one stage III goes in service EOG will triple its exposure to JM to 420000 <unk> per day.

We continue to see constructive long term demand for all our products both domestically along the Gulf coast and internationally to unlock that value you need control of your products transportation capacity and an early mover advantage to capture spreads quickly.

As we look down the road EOG is well positioned to capture the strength of prices in these export markets to generate additional cash flow and value to shareholders next step is for concluding remarks.

Thanks Lance.

We believe EOG is differentiated for the following reasons.

We have a diverse portfolio of assets across multiple basins, providing geographic and product diversity.

We are a reliable and consistent high performing operator.

We are among the lowest cost structures.

We are committed to sustainability.

We maintain an exceptional balance sheet.

Our cash return strategy is transparent.

Our regular dividend is competitive with the broader market.

And finally.

The EOG culture is one of a kind and it's at the core of our differentiated performance.

We believe there are only a handful of north American E&P companies that have the asset quality.

<unk> the scale to compete globally on oil and gas cost of supply and on top of that produce the barrels with a lower environmental footprint.

In the future those are the companies that the world is going to want to deliver additional barrels and we firmly believe that EOG is a leader in that group of North American E&ps. Thanks.

Thanks for listening, we will now go to Q&A.

Thank you.

The question and answer session will be conducted electronically.

I'd like to ask a question please DC with parsing the stocky.

The ticket on your Touchtone telephone.

If you are using a speakerphone. Please make sure your mute function is turned off to allow us to go to reach our equipment.

Question is limited to one question and one follow up question.

We will take as many questions as time permits.

Once again, please press star one on your Touchtone telephone to ask a question.

Following your question, hoping Fitch you may remove yourself.

Thanks Staci.

But just to give everyone an opportunity for questions.

First question comes from Leo Mariani.

<unk> partners VIP is go ahead.

Hey, guys.

Totally realize that it's obviously way too early for 'twenty three guidance at this point you guys did have some prepared comments, which kind of is that as things stand today, you would look to grow oil kind of low single digits next year and it feels like a bit of a pivot from what you. All had said in the past, which was kind of this 8% to 10% oil growth we kind of.

The optimal sort of operating speed.

For EOG has something changed in terms of how you look at kind of optimizing the operations versus the growth of the company.

Okay.

Yes, Leo this is Ezra I appreciate your question.

Really what we've always talked about is it.

Our growth is really the output of our ability to generate high returns from a disciplined reinvestment strategy and that's really what we've tried to describe today is as.

As you pointed out first of all it is early to talk about 2023.

Ultimately, we're we're committed to remaining disciplined we want to focus investment in each of our assets at a level, where they can continue to improve every year directionally as we see it today, how the supply and demand balances look the constraints on services the associated inflationary pressures oil growth will likely be similar to this year.

And as Billy highlighted we would expect to direct additional investment towards our Dorado natural gas play based on the positive results results that we're seeing there.

Okay. That's helpful.

And I just wanted to ask on capital obviously, you're one of the few companies did not raise the capex budget. Thus far here in 2002, you described a lot of the ways that youre able to kind of keep costs are lower than some of the innovation that you've sort of had I did notice that you did pull some of the wells out of the schedule this year not big numbers.

Just talking a few on the margin I just wanted to get a sense is there any thought that maybe doing a little bit last to kind of stay within the budget and just kind of looking at where you were in the first half and third quarter guidance is it fair to say, you're probably kind of in the upper half of the capex for the year.

Yes, Leo this is Billy Helms, yeah, the small change in well count.

It is really just a result of two things one is timing some of the wells that were scheduled to complete at year end are going to slip into the next year.

The timing thing.

The other factor that plays into that as a change in working interest in some of our plays.

We've had slightly lower working interest in some of our Delaware Basin wells in the second half of the year.

Just to illustrate how minimal that is thats only about a 2% average change in working interest across the across the year. So it's a very miniscule amount, but that explains the change in the well count as far as the Capex. We're very pleased as you can tell from the comments, we made about the ability of our teams to continue to innovate in.

Drive efficiencies in our business to offset inflation.

Inflation turns out to be just a little bit higher than we anticipated. This year. So we are going to see a slight improve or increase in our well cost as we go through the especially the second half of the year, but we're still confident we're going to stay within our guidance and don't expect to.

Faced additional costs that will increase our our budget.

Okay. Thanks, guys.

Thank you.

Next question comes from Jay <unk> from JP Morgan Chase O'brien. Please go ahead.

Yes, good morning.

I appreciate the color on the powder River basin, but I guess my first question is just thinking about capital allocation between the basins as we think about next year.

Today as I think 22 of 24 of your rig lines are either in the Delaware or Eagle Ford you.

You have one rig in the powder River basin.

You mentioned in your comments you plan to lean a little bit on the Dorado next year and significantly increase perhaps the mix of activity in the powder River Basin. I was wondering if you can give us a sense of how your activity could.

Shift as we think about next year and how many rig lines you may have in the powder.

Yeah Arun this is Billy.

As far as capital allocation.

As we see it today.

There's a lot of factors playing into that of course, and it's early to say, where we're going to be still will have quite a bit of activity in the Delaware basin going forward. It is a.

Premier play in the company and certainly that will continue to command quite a bit of capital Eagle Ford has been a.

As you know our.

Performance engine for the company for the last decade or longer and that will and Theyre generating outstanding results. So that'll still command capital as we compare we allocate capital based on returns and certainly the encouragement, we're seeing from Dorado and the activity there.

Is showing us the ability to be able to continue to fund that program going forward.

And then the confidence we have in the new emerging powder River basin gives us a sense that that will also come and quite a bit of activity. So the ratios I would say are going to say stay similar.

As far as the powder River basin, and our overall capital plan that will depend on the outlook for commodities at that time.

But the.

What we're going to see in the powder just to be clear is a shift of activity from some other older traditional plays the Turner and the.

And.

Yes.

Parkman.

To some of the deeper more emerging plays and then marry more specifically and denial.

So youll see that shift the amount of capital allocated to that play will also depend on just the commodity price outlook that we see for the year once we get closer to that.

But overall we are.

Take away from that I would think would be that the flexibility we have with the multiple plays we have to chase to continue to add value long term to the shareholders.

Great.

Follow up is just.

Maybe one for Tim.

Just maybe a housekeeping question.

Tim in the 10-Q.

You have $1 8 billion of collateral postings associated with hedge activity I was wondering if you could help us think about the potential runoff.

Those collateral postings.

As well as maybe the timing of when you plan to pay off the $1 25 billion of bonds is that later this year or in 2003.

Yes. This is Tim as far as the bond that is 23 its in the first quarter of 2023.

When that will mature.

No plans to pay it off early as far as the collateral.

Run off kind of like the hedges, we've given you the.

The timing of when those hedges are in our 10-Q, so it kind of runs off or is that timing comes off.

It all depends of course on where.

The strip goes how that comes off but right now it's based on the strip and that would be how it would come off as those run off.

Alright, great. Thanks.

Thank you next.

Next question comes from Scott Hanold from RBC capital markets. Please go ahead.

Yes. Thanks.

I can ask a question one more question maybe on.

The pier B.

You all highlight.

Good commodity price realizations that you're all seeing there is that something.

That you think can persist going forward and is it a function of.

What's happening in the basin overall or is it specifically something <unk> got in place that allow you to kind of benefit there.

A bit more.

Hey, Scott this is lance or Dana Thanks for your question.

Yeah, when you think about the price realizations.

I think the broader message is just you can really just see how competitive the powder as with all our other plays I mean operationally.

Heard Jeff kind of outline a lot of things in the opening comments, but even for our products. We continue to just really see it being in high demand for.

For example, like even on the crude.

You have to remember one of the important attributes of a powder, especially related to EOG is just think about the crude quality.

Today, we're kind of seeing right around $44 45, we expect that to kind of be a $44 47 kind of overtime and so we really want to protect that quality.

We've secured.

500000 barrels of storage kind of in the field, we've got firm capacity to both Guernsey and the Cushing market, so having that multiple flexibility, where we can show that kind of high demand barrel and the API quality that we have keep it kind of segregated without API quality.

It's really a value when we sell direct to our refiners and so just being able to have that value and have that quality and consistency is key and so we draw a lot of that experience from what we've done in the Eagle Ford and also in the powder.

Sorry on the Delaware Basin.

Yes, that's the quality is what youre seeing on the price realizations and then as you think about the Ngls.

Youre seeing mostly ethane extract ethane rejection that's happening there. So most of that youre seeing that ethane is going to go more towards like an <unk> or selling that as a gas and so that is a heavier barrel that you are seeing that we kind of show, but again, we have the market flexibility. We can show that barrel in Conway and we can also show that barrel and Mount Belvieu. So we can kind of all of that flexibility.

<unk>, two and look at those spreads.

So okay.

Getting kind of back to your question.

Really the quality and then the flexibility that we have with the multiple markets and it's an area. That's absolutely in demand is weak.

Got it thanks for that.

Follow up.

I want to ask a question on Trinidad and it looks like Youre guiding down a fair amount for gas production in Trinidad and I know you've had some exploration success, there and I think youre drilling a development there.

You have are you going to be drilling a development well. This year. So could you give us a sense of like what to expect from from Trinidad and is it more of.

The relative pricing dynamic there versus the Dorado in terms of like which plays you're going to get sort of more capital investment.

Yes, Scott this is Billy Helms.

So for Trinidad we've had as you know a long successful history of really maintaining pretty much flat production.

With minimal investment and it generates quite a bit of cash.

The company cash flow for the company. So it's been a very successful project for multiple decades now we still see exploration opportunities and are still counting on exploration success going forward just based on the things we see today the small.

Guide down in gas production, especially in the next let's say the rest of this year is based on some turnaround projects. We have on some of the compressor stations and platforms in the field.

So it's just an operational issue really manifest.

Manifest in the third quarter, mainly.

So.

But as we start to drill some of these exploration wells, we still have confidence that production base will continue.

Okay. Okay. So it will it should turnaround back to sort of normal levels and by early 'twenty three is that right yes.

Yes, that's right.

Got it thank you.

Thank you.

Next question comes from Scott Greenberg from Citigroup.

Please go ahead.

Yes, good morning, just coming back.

<unk> question I know you guys had previously commented that you don't see an outsized inflationary impact on EOG next year from contract at all or any other factors.

Engaging earlier than normal discussions for services and consumables et cetera.

Still confident that the plan.

When you experience.

Next year will not be any worse than the industry trend.

Yes, Scott this is Billy Helms again on the inflation question I think I would distinguish a little bit there I think we're recognizing the inflation that everybody else in the industry is seeing.

We're able to combat that really through a lot of the efficiencies we drive through our business and Thats really a result of the culture, we have of continuous improvement and the quality of the staff we have in each of our operating divisions.

So now the contracting strategy has always been a long term thing for EOG, we work with.

Our vendors are partners on the service side.

And our contracts are always a little bit staggered so that all of the contracts don't roll off at the same time.

It gives us a lot of flexibility to also manage the.

The commodity cycles to make sure we have a consistent operating performance level going into the year.

We always start about this time of year.

I wouldn't say, we're we're starting any earlier than we typically do I think we always started sometime here in the middle part of the year to start securing services for the next year as we see things play out we take opportunities as we see those emerge too.

Make arrangements with vendors and our service partners to secure those services in the upcoming year and that determines the level of.

Services that we can.

Secure for next year as well cost, we typically like to think about securing about 50% to 60% of the well cost ahead of any given year and that range depends on the opportunities we see with service partners to lock in those services.

This year, we expect to be somewhat the same as we go into next year, but we'll see as we get closer to the year end, but thats, how we see the inflation, obviously, we expect with the tightness in the market.

We're going to see some additional inflationary pressure.

Going into next year.

So just anticipating that we could see another uptick in our well cost going into next year, but we expect to again moderate a lot of that with our efficiency gains.

Got it and then a follow up here on the 60.

60% distribution threshold.

Really in light of the early hedge settlement payments made this quarter.

Include those payments that you guys are doing a recording.

And you guys are running ahead of the threshold.

I assume those are more of a onetime hit the free cash you are running a little bit.

Behind that threshold and I know you will.

Look at the threshold.

Annual basis.

So I guess the question is whats your appetite.

To approach the 60% payout for the year.

Moving the impact of the $1 3 billion and an early hedge settlement payments.

Yes, Scott this is Ezra.

Just a little bit of color on that obviously.

<unk> decides the dividend each quarter, they review our business needs the macro environment.

Our cash position, so on and so forth and as you said the $1 50 per share special this quarter, which brings the total dividend commitment to right at $7 30 per share.

Is on pace to achieve the minimum of a 60% free cash flow return and I think thats. The emphasis on there is that the 60% is a minimum ultimately it's up to the board like I said to return additional cash in 2022.

The way to think about those early terminations of the hedges is really a reflection.

Think of our confidence in improving the financial profile of the company our ability to navigate inflationary inflationary pressures this year.

Flexibility to allocate capital across multiple resource plays which are each delivering exceptional returns and really our ability to continue to lower the cost base of the company. These are all things that deliver expanded free cash flow opportunities for EOG.

Great appreciate the color. Thank you.

Thank you.

<unk> comes from Neal Dingmann Tour Securities. Please go ahead.

Good morning, Chris.

Is it maybe for you or Tim on a little bit different on capital allocation, specifically planning instead.

Of what you all would need to see either quantitatively or qualitatively would need to see to start to turn.

So you're looking at more or I guess his guys call. It out they are leaning into buybacks.

Given I understand you'll have bought back shares for years.

We did see.

Decent decline a month or so ago. So.

I'm just wondering when you guys think about buyback.

When you say opportunistic what really goes into that.

Yes, Neal this is Ezra thank you for the question.

Basically we evaluate a buyback just like any other investment decision and really what we do is we look to see.

How it is going to create long term shareholder value.

And as you highlighted and as we've discussed previously the $5 billion share repurchase authorization that we have in place we've talked about using opportunistically and what that means for us is using it during times of what we would say a significant dislocations in the market.

And that's as opposed to do a more programmatic system and quite frankly this year. During Q2, we didn't really see what we would say it was a significant dislocation we definitely witness a lot of volatility I think rather than.

Dislocation.

The volatility was due it was driven by changes to the oil inventories that we saw.

That was really due to the SPR releases, we saw some concern over demand destruction associated with the.

Inflationary pressures across the broad market.

We saw some potential for weaker demand associated with the uptick of of Covid cases, but ultimately in our view. These are all kind of short term events that really doesn't change the fundamental supply and demand picture.

I like how you're thinking about that and then my second or follow up slightly.

Likely for Bill just on vertical integration specifically.

You'll have other areas other oilfield service areas.

Besides you mentioned self source sand.

Just wondering do you have other areas that.

I guess, you would all have more vertically integrated or.

You would think about doing that and I'm just wondering on that also in that self source sand how much capacity would you add on that side.

Yes, Neal this is Billy.

Certainly on the self source sand you named one of the primary ones, that's a big part of our program.

We've been doing that as you might remember for more than a decade and.

And what we've been able to do is find ways to get the source of the sand closer and closer to the wellhead.

Minimizing the cost of the product, but also the transportation involved and getting it to the to the wellhead.

We are expanding that through the rest of this year such that we'll be able to continue to supply a greater and greater amounts from our own self sourced minds.

So we're excited about the growth in that.

Other areas that we self source theres a number of them I mentioned briefly in the prepared comments.

Note to our.

Efforts to take control of the drilling motors that we use in our drilling operation.

That's a small thing maybe but it is a big driver of performance when it comes to that part of the business.

We recognize that a couple of years ago built up some expertise and our staff to address that we work specifically to not only design, but also build and oversee the maintenance of those motors that ultimately drives the improved performance.

And we're seeing great results from that program.

That's another differentiator in our drilling performance that allows us to continue to offset inflation.

Some of the other things as you know we've been managing our tubular inventory.

For many many years as well we deal directly with the steel mills, which gives us a lot of advantages in the sense of having some clarity or some certainty on the market kind of what that's indicating to get ahead of issues, where we see it take advantage of opportunities to secure those.

Lower cost.

And make sure that we have pipe for our programs on a go forward basis. So those are maybe a couple of other things.

That will give you some color on what we're doing.

Yeah, that's great details. Thank you.

Got it.

Thank you.

Next question comes from Doug Leggate from Bank of America, Doug. Please go ahead.

Doug Your line is more later.

You can proceed with your question.

Hello, and good morning, everyone. Thanks for letting me on.

Slide five.

Our latest assessment of the cash flow it doesn't give any numbers around that in terms of breakeven I wonder if I could just ask you to look into two.

2023.

Give us an update of where you see your sustaining capital in the breakeven oil and gas prices that go along with that the assumptions behind that if you don't mind.

Yes, Doug we haven't released that and we did we did remove the <unk>.

Breakeven slide from earlier this year because of the significant change.

And gas prices that have gone on in the first six months of the year. The best thing I can point to is the fact that we continue to bring on lower cost reserves.

Basically focused on the premium and double premium wells into the cost base of the company.

Look at a reduction in our unit cost and a reduction in our DD&A rate year over year to two kind of infer the reduction in our breakeven.

Okay I'll push David on this and see if we can get them to put it back in because it's a pretty critical.

Obviously, the market's perception of free cash flow, but I appreciate the answer.

My follow up as I apologize in advance like this but.

Just a follow up on the share buyback question.

Location and your stock is subject to obviously, but if I look at your share performance.

Absolute terms.

In relative terms in particular for the last quarter five years.

It's really struggled to against the rest of the sector.

And one could interpret from your comments.

Dislocations on perhaps.

Perhaps the buyback Scott you're doing value in your stock.

So if you could address that.

As the transitory nature of a special dividend why you wouldn't want to step in just about every one of your peers is doing something on buybacks on their share performance is quite different from yours on a relative basis, so any thoughts around that would be appreciated.

Yes, Doug.

The first thing I would say is that.

I think it's stating the obvious that I feel that our stock is undervalued right now, but again, we look at that buyback and investment in that buyback, we compare it against other opportunities in the business to create shareholder value.

Long term shareholder value and when we do that when we compare it versus reinvesting in the business drilling. These double premium these premium wells at 30% and a 60% direct after tax rate of return based on $40 oil and $2 50 natural gas. It's a very very high hurdle. So when you think about what can create longer term value for the shares.

Holder, we see the benefit of reinvesting in the business driving down our long term well costs lowering the breakeven so as we talked about as a very very competitive portion of allocation now with regards on the transitory nature comparison with the transitory nature of a of a special dividend I think again it goes back to the way that we look at the buyback with regard.

Who are our shareholders.

Buying repurchasing shares during a volatile movement in the stock price I think.

Thank our shareholders prefer to have the authority of special dividends coming back to them as opposed to us trying to time the volatility in the markets.

From again I would go back to what we call a significant market dislocation.

Thank you to have an opportunity there that would compete very favorably to create long term shareholder value.

It's a tricky one I guess, a special dividend doesn't reinvesting and if you think your stock is undervalued then.

One could argue that the volatility is.

It's something you've got to live with that you think is I guess what number.

We're probably not going to agree on this but it seems to me the special dividend is.

Yes.

The lesser permanent.

Impacts on the share price I guess is what I was getting at but anyway I. Appreciate your answer as always appreciate your perspective. Thank you.

Thank you.

Thank you.

Comes from Paul Cheng from Scotia Bank. Please go ahead.

Thank you good morning too.

Two questions. Please.

Could you comment on the A&D market.

For example, again Eagle Ford I think you gentlemen, headset.

Getting a little bit higher.

So do you see opportunities to make maybe a more sizable bolt on acquisition that.

Debt to beef up the operations there.

And secondly that.

Wondering.

They had a chance to review the news and the proposal.

On the tax law changes and how that what would be any major impact.

To EOG. Thank you.

Thank you Paul This is Ezra let me let me attack that first question on the Eagle Ford and then I'll hand, it over to Tim Driggers to.

Give some feedback on the tax law proposals so on the A&D market there in the Eagle Ford Yeah, Let me let.

Let me clarify how we're viewing the Eagle Ford right now we're on pace to deliver.

For the second year in a row basically record rates of return and record finding costs.

In our drilling program, there and the big thing that comes to US it kind of fits back into some of my opening comments talking about the right investment rate for plays a different life cycles.

So clearly our Eagle Ford position has reached a point, where it's not a main focus area for growth.

But what we see is a very very long runway.

Exceptional returns on those on those wells as you reinvest in them.

We're moving at the right pace, where our team has the ability to.

To execute on lowering costs, increasing incrementally the well productivity.

As far as expanding our footprint there.

We'll have a very robust eagle Ford inventory position.

Think about the Eagle Ford position, Yes, we've talked about 7000 locations in may and approximately halfway drilled through those locations. So still well over 10 years' worth of inventory to drill on the other thing about looking to do A&D.

Established based on like that it's just going to be the cost of acquisition.

We primarily focus our exploration efforts and we always have for the two decades that we've been involved in unconventional resources on organic or Greenfield lease acquisitions because of that low cost of entry is critically important to providing through cycle value to the shareholders.

Those are the PDP value.

You would have to pay for.

And in an established area or just established acreage prices those things stay with you on your books forever. It raises the cost base of the company and has really antithesis to what we've been trying to do over the last few years by shifting to premium and now double premium drilling.

Tim would you like to please comment on the tax proposals sure.

Paul as far as the proposal.

We're in the process of reviewing that as is everyone else currently, but specifically looking at the minimum tax.

Proposal <unk>.

We did not see that as having any detriment to eog's we are full.

Taxpayer already so as we model. It currently it will have no impact on EOG.

Okay.

Thank you our next.

Question comes from Jeanine Wai from Barclays Jeanine. Please go ahead.

Hi, Thanks for taking our questions.

Maybe just following up on Paul's question, there low cost bolt ons have always been part of your capital allocation strategy and we noticed in the cash flow statement had about $350 million of that in there.

Any color on whether that was primarily blocking and tackling and youre active areas or is that more on the exploration front.

Yeah.

Yes, Jeanine this is Billy Helms.

What particular acquisition is really just an opportunity we found to bolt on some largely primarily acreage in some of our exploration plays.

Very little if no production on those plays and it just is another way that we can continue to add and grow at a low cost.

Our exploration opportunity set that we see in the future of the company.

Sure.

Okay, Great and then maybe just a quick one on marketing.

Talked about you've got Optionality for up to 250000 barrels a day of Brent exposure.

Youre not letting that much right now but.

Looking at your production levels out of the Permian and Eagle Ford and so what's the capacity to increase beyond that $2 50, or maybe to get to that two safety and if you were to take on some more exposure on that is this really looking at things more on the contract side or you also securing too.

So open to securing more docs based on your own. Thank you.

Oh, Jeanine and thanks for the question.

Question two is timely.

The exports, especially for crude oil has been an important component of our marketing strategy, but when you really look just from an industry standpoint too.

Refiners in the U S are not expanding I mean, if anything is integrating right. I mean, we're seeing our market share and you are seeing refinery shutting down youre seeing refineries that are being repurposed and so we had a view going all the way back to 2018 that we wanted to have.

A significant export position that we could access from multiple multiple plays and I know one of your questions. There, which is how do we think about the Delaware basin or how do we think about the Eagle Ford and you're exactly right that was all in our contracting that we wanted to be able to have a large position that we could access from both of those plays. So if you think about it today we.

That $2 50, and yes that facility is expandable, but we have 5 million barrels of storage I mean, we can segregate WTO <unk>, we can segregate our Eagle Ford I mean, we are in.

Premier position as we think about from a low cost and being an early.

With our tankage position and then also with the capacity that we have out of the Delaware Basin from a transport physician and also from the Eagle Ford So.

What I would say as we can we can transact very quickly we have tankage that's in place and so if we feel the need that we needed to push more cross and that's absolutely something that we could do.

Great. Thank you.

Okay.

Thank you. Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead.

Hey, Good morning team just one question for me is just can you give us the lay of the land.

The Dorado program is shaking up shaping up.

Do you think about the net asset as we go into next year from a planning perspective, but as we continue to see the gas curve has firmed up here how.

How do you think dorado can fit into the overall U S gas picture.

Yes.

Yes, Neal this is Ken at this time, we really have two drilling rigs active in the in the Dorado play and just to give you a little bit of background on it since 2018, we've drilled and completed over 30 of our 250 premium locations. Both in the in the Austin Chalk and the Eagle Ford and we've really made excellent progress on.

Reducing well cost and enhancing our geologic understanding and increasing our well performance. We're we're we've increased our lateral length and written were really operationally being able to execute it.

As far as how 2023 goes it's a little early to talk about the 2023 program. Yet obviously, we'll remain disciplined with our investment there first to make sure that the market needs the gas and second to make sure we're operationally getting better.

We one thing to keep in mind is really don't need a lot of wells there to grow production significantly given the performance of the wells in there and theyre shallow decline rates.

Thanks, Steve.

In the interest of time. This is the end of the Q&A session. Today. So now I'll hand, you over to Mr. Jacobs for closing remarks.

Yeah.

Yes.

Want to thank everyone for participating on the call. This morning, and thanks to all our shareholders for their continued support.

Especially want to recognize our employees for their performance this quarter our discussion today highlights their focus on making EOG, a low cost operator generating high returns and lowering our environmental footprint each and every year. Thank you.

This concludes today's call. Thank you for joining you may now disconnect your lines.

Yeah.