Q1 2023 Antero Resources Corp Earnings Call
Greetings and welcome to the Antero resources first quarter 2023 earnings conference call. At this time, all participants are in a listen only mode.
A brief question and answer session will follow the formal presentation.
Anyone should require operator assistance during the conference. Please press star zero on your telephone keypad.
As a reminder, this conference is being recorded.
It is now my pleasure to introduce your host Mr. Brendan Kruger CFO of Antero Midstream N V. P of finances. Thank you Mr. Kruger you may begin.
Thank you good morning, and thank you for joining us for Antero <unk> first quarter 2023, Investor Conference call, we'll spend a few minutes going through the financial and operating highlights and then we'll open it up for Q&A.
I would also like to direct you to the homepage of our website at Www Dot Antero resources Dot Com, where we have provided a separate earnings call presentation that will be reviewed during today's call.
<unk> call may contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures.
Joining me on the call today are Paul Rady, Chairman and CEO and President Michael Kennedy, CFO , and Dave <unk> Senior Vice President of liquids marketing and transportation I will now turn the call over to Paul.
Thank you Brandon I'd like to focus my comments today on our company's operational performance during the quarter.
During the first quarter, we set a number of new company and industry drilling and completions records, which highlights our exceptional team and a high quality asset base.
Let's begin on slide number three titled drilling and completion performance. The chart on the left hand side of this slide highlights our lateral footage drilled per day.
During the first quarter, we achieved three of the top 10 lateral feet drilled in a 24 hour period.
This included a world record of 12340 lateral feet drilled in a 24 hour period.
The chart on the right hand side of the page illustrates our completion stages per day.
We set a new quarterly record at almost 11 stages per day, including a single day record of 16 stages per day.
These completion records are referring to a single completion crew across the two crews we have averaged 22 completion stages per day.
These are extraordinary achievements from both our drilling and completion teams, who continuously look for ways to improve our operations.
I will note that the increase in efficiency during the first quarter results and activity being pulled forward during the quarter, we completed 31% of our 2023 budgeted completion stages.
Now.
Let's turn to slide number four titled Antero, well performance versus peers.
In addition to the drilling and completion records, we continue to be very encouraged by the well productivity we are seeing.
The chart on the left hand side of this slide shows that Antero has liquids productivity continues to get better and better each year.
Average liquids productivity has increased 87% since 2018.
The chart on the right hand side of the page highlights well productivity trends versus our peers since 2020.
As illustrated on the page Antero is average cumulative equivalent production per well is 20% greater than the peer average over this time.
This is Dan.
This is an important distinction for antero with many companies having already drilled their best acreage our long core inventory life continues to deliver stronger results each year.
Next I'll discuss slide number five titled low decline rate leads to lower maintenance capital.
As we enter the fourth year of a maintenance capital program our base decline rate continues to move lower.
Analysis from a third party highlights that Antero is one year and three year decline rates are the lowest of our natural gas peer group.
Touching briefly on our cost outlook, we are beginning to see service costs rollover for rigs and completion crews. We're also seeing a decline in costs for raw materials, such as <unk> fuel and sand.
The combination of cost deflation drilling and completion efficiency gains and a lower decline rate is expected to result in lower overall maintenance capital requirements in 2024.
Lastly, I would like to comment on our organic leasing efforts during the quarter. The first quarter, we invested $72 million on land.
As previously communicated this represents just under half of our 2023 land budget of $150 million.
Our leasing efforts are primarily focused near our current development plan, where we are achieving these excellent drilling completion and well performance results. This land investment in the first quarter as the equivalent of over 50 incremental drilling locations, mostly in the liquids rich core of the Marcellus.
As we say equivalent locations as the organic leasing investment adds both absolute locations as well as lengthening our current locations for example.
Our 2023 wells drilled are expected to average 14500 feet in the lateral a 7% increase from the average in 2022.
Now to touch on the current liquids NGL fundamentals I will turn it over to our senior Vice President of liquids marketing and transportation, David Kendall Aldo for his comments Dave.
Paul <unk>.
Liquids prices have rebounded from recent lows in early Q1 and fundamental data is pointing to continued recovery throughout this year, especially for the propane barrel.
While the lack of cold weather and several PTH outages resulted in high propane inventories. This winter a resurgence in international demand has pushed more barrels into the global market in recent weeks.
Slide number six highlights that U S. Propane exports have already increased 20% year to date at $1 6 million barrels per day compared to 2020 two's average of 1.35 million barrels per day.
Additionally, propane exports hit an all time high at 1.85 million barrels per day in April According to EIA data.
The increase this year is the result of the post COVID-19 recoveries in demand in the Chinese economy reopening.
Looking at the macro infrastructure picture. This year is expected to be a pivotal one for the LPG market, which stands for liquefied petroleum gas, namely propane and butane.
As shown on slide number seven we expect record deliveries of very large gas carriers or vlccs, which are the largest sized marine vessels that can carry LPG roughly 550000 barrels per ship.
The market will also see significant increases in Chinese petrochemical demand for LPG, driven by PTH capacity additions this year and in 2024.
On the shipping side, the market expects deliveries to 46, new VLCC shifts during 2023, which equates to a 300000 barrel per day increase in shipping capacity based on average round trip voyages from the U S Gulf Coast of China.
On the left hand side of slide number seven the chart shows that 11, new Vlccs have already been placed into service year to date.
These capacity additions are already helped to reduce the Baltic rate from $94 at the beginning of 2023 to $75 today.
The additional vlccs are expected to reduce shipping rates further and narrow the spread between Mont Belvieu and international pricing, resulting in a tailwind for antero ctrip loss realizations.
Turning to slide number eight the U S is still expected to be the incremental global supplier of Ngls to meet increasing international demand.
Recently announced OPEC plus additional crude production cuts are expected to lower LPG from the middle East continuing to solidify the U S and the incremental NGL supplier to the world.
These recent OPEC plus oil cuts.
<unk> could limit OPEC, plus LPG supply by an additional 8% or <unk> six per month from May of 2023 to December of 2023.
The chart on the left hand side of the slide shows that while the rest of the world supply growth in NGL production is expected to be roughly flat from 2022 to 2020 for the U S is expected to grow 11% during that period.
I will note that we believe that this U S growth estimate could prove to be too high given the year to date reductions in liquids rich focused drilling rigs.
We have seen 27% and 19% declines in liquids rich focused rigs in the Appalachian basin and the Eagle Ford respectively. Since the beginning of the year.
Even with U S supply growth third party providers show that there is expected to be unconstrained LPG export capacity through the end of 2026 based on existing dock capacity and recently announced expansions as shown on the right hand.
The graph of slide number eight which is supportive for Mont Belvieu pricing.
While NGL Antero certainly benefits from the uplift in Mont Belvieu prices. The majority of insurers NGL exports are transported through the Mariner east system, and antero firm capacity on that system and unique pricing flexibility give us additional opportunities to take advantage of price spreads and arbitrage opportunities.
Turning to China on slide number nine we have seen a recent recovery in utilization rates on existing PD H units and continued plans to add more capacity in 2023, and 2024 to meet post pandemic demand growth.
A P. D. H is a propane dehydrogenation facility that takes a feedstock of propane and converts it into propylene a key building block in the plastics industry.
The chart on the left hand side of slide number nine shows the planned expansions over the next two years will nearly double <unk> capacity for 2022 levels, resulting in over 500000 barrels a day of potential new propane demand or about 5% of the overall global protein demand.
With limited supply growth coming from the Middle East and other areas as we just discussed China will increasingly depend on U S. LPG imports to serve these plants.
This trend is already evident with 50% of total Chinese LPG imports coming from the U S. In March of 2023, According to third party ship tracking data.
Antero is extremely well positioned to benefit from increasing global NGL demand over the long term with over 50% of our NGL NGL volumes being exported and all of our NGL volume currently unhedged with that I will turn it over to Mike.
Thanks, Dave.
Following our successful debt reduction program and Taro entered 2023 in the strongest financial position in company history.
Third strengthening our position as our low free cash flow breakeven level.
Turning to slide number 10, titled Free cash flow breakeven, we thought it was important to revisit this slide as it is critical to our natural gas macro views.
As a reminder, the slide provides a look at the natural gas peer group and the required Nymex Henry hub price for each of the peers to achieve an unhedged free cash flow breakeven position in 2023.
As illustrated on this page as a result of higher maintenance capital costs limited liquids revenue uplift and widening basis differentials on natural gas.
We estimate that most haynesville companies are not able to generate free cash flow in today's pricing environment.
We've already begun to see a moderation of activity from these producers through the gas directed rig declines in recent weeks.
We expect this downward trend in rig counts to continue through 2023.
As you can see on the left hand side of this slide and Taro is free cash flow breakeven price benefits from a significant liquids uplift and the premium natural gas pricing, we received by selling our gas out of basin.
Turning to capital returns slide number 11 illustrates the steady and consistent progress we have made in our share repurchase program over the last year.
During the first quarter, we purchased $87 million of our stock.
Since the inception of our share repurchase program at the beginning of 2022, we have now purchased over $1 billion of our stock or approximately 10% of our shares outstanding.
Now, let's turn to slide number 12, titled Antero has differentiated strategy.
As I just discussed our focus on liquids development provides significant benefits to our free cash flow breakeven in.
In 2023, we expect 45% of our total revenue to come from liquids.
This focus on liquids is further highlighted through the 17% liquids production growth we delivered during the first quarter compared to the year ago period.
This liquids growth compares to a 3% decline in natural gas volumes during that time.
Our differentiated strategy continues with the chart in the middle of the slide highlighting our ability to sell 100% of our natural gas out of basin, including 75% to the LNG corridor.
With no exposure to local markets that often trade 50 to over $1 back of Nymex.
We are able to capture premium prices to Nymex.
The chart at the bottom of the slide shows our commitment to reduce absolute debt. Since 2019. This kind of as a resulted in $2 $4 billion in debt reduction during that time.
The leverage profile of just <unk> five times.
Also acting as a cash flow tailwind our royalty agreement with Marika ended on March 31, 2023, increasing our net royalty interest in wells drilled by 375%.
This will result in lower cash flow distributions tomorrow vacate each quarter going forward, assuming the current strip.
We anticipate the majority of that cash flow to revert back to Antero in 2025 based on today's commodity prices.
We are committed to a return of capital policy, which targets returning 50% of free cash flow to shareholders.
Based on current strip prices and our current enterprise value of approximately $8 billion, we traded a PDP <unk> valuation so using our free cash flow to buyback our stock is an attractive option.
In closing the successful execution of Antero has differentiated business strategy positions us to excel across many commodity price cycles.
Increasing NGL demand through the reopening of China provides a bullish backdrop to NGL prices as we move through the year.
On the gas macro we continue to expect moderated activity from producers in basins that are outspending cash flow at today's prices.
We expect this moderated activity lead to significant volatility in pricing as natural gas demand growth materially in 2024 and beyond with a second wave of LNG export facilities coming online.
Looking ahead, we are well positioned with a peer leading balance sheet product diversity with nearly half our revenue generated from liquids and significant exposure to U S LNG demand growth.
With that I will now turn the call over to the operator for questions.
Thank you we will now.
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One moment, please while we poll for questions.
Thank you.
And our first question is from.
Chandra with benchmark company.
Please proceed with your question.
Yes. Thank you good morning, everyone.
Congratulations on the you know the drilling record set just trying to think through.
What this might mean as the year goes on with 31%.
The completions in the first quarter.
How do you think about the fourth quarter.
If youre running strong pain, Steve sort of stay within budget within the wells.
Guided or do you sort of take advantage of the efficiencies.
<unk> drilled through them.
As we close out the year.
Yes, no. Good question, Sue Bosch, where obviously, you're a bit ahead of schedule on the completions pace. So right now our thought is we would just have less completions in the fourth quarter and stick to that.
Stick to the budget.
Okay. Thank you.
And a follow up I guess is.
A couple of basic questions.
Update on the shell cracker.
It's a fully functioning at this point and then MVP, how you'd think of that.
Impacting the basin is there more gas coming or more rerouted gas as a consequence.
On the shell, they're still in the commissioning phase so they're not up.
Ramped up to the full volumes and we've completely risk that in our production guidance or gross wellhead volumes are obviously.
Ahead of expectations, but we have risked the ethane volumes as effect commissioning of the shell Cracker continues throughout all of 2023.
On MVP.
We don't sell any locally as you'll recall so we don't follow it that closely it just and.
And it seems that it's been delayed.
Past 2023, so we don't see really any impact from that.
Okay. Thanks, Mike.
Thank you. Our next question is from Bertrand Jones with curious Securities. Please proceed with your question.
Good morning, guys.
With your with your mineral acquisition and the 50 locations that you talked on it.
It seems like you're more comfortable just kind of replacing your inventory as you drill through it but do you have any thoughts on M&A in the basin.
Is there any driver to you know make companies come to the table or is it really a you know everybody is going to kind of wait and see and then as LNG demand comes on we might have a mic.
A mix of people that can get to the Gulf coast and those that can't and maybe that that forces M&A.
Yes, that's true.
Yes, we do.
Inside the base and you see our focus on adding the premium acreage to just continue to replenish our inventory yeah. There are a number of competitors in the basin that are somewhat traps that they are selling at the local index and can't go to the premium market. So.
Whether that results in a distress case on their part or not we'll see but we look at everything within the basin.
Okay. It sounds good and then shifting gears a little bit are.
You guys always put a lot of nice slides on propane and butane and what the markets look like but I was wondering if you could expand on maybe ethane.
I know prices are kind of depressed right now, but some of your peers have gotten kind of bullish.
Maybe towards the end of this year or next year.
Some of the Debottlenecking happens, maybe some exports pick up so I just want to know if you guys any thoughts on that.
Yes.
Ethane recovery volumes about 40% to 50% depending on the quarter right now is linked to Mont Belvieu and so I think some of those bullish outlooks are really around Mont belvieu pricing and frac spread pricing most of our.
Other other volume, it's not Mont Belvieu Linctus gasoline can we've as we've discussed previously calls we baked in a premium to gas to have a long term contract for those types of those types of customers, but on the value side.
Seeing the same predictions, obviously recoveries of ethane.
In Texas have been near Max for quite some time.
Production is growing down there, but so has demand for ethane.
The U S Gulf coast domestic side as well as on the export side, we do believe there'll be quite a bit of ethane.
Methane export growth.
Here.
In years, so certainly the potential if you look historically ethane is trading more like an oil product in those gas products prior to the shale Revolution.
It's really been in recent years has traded more similarly in gas, but yes.
Yes that potentials there as the demand for ethane is those types of facilities is very sticky they're building crackers that can only consume ethane. So that's kind of a man and you want a house, both domestically and internationally.
Got it and then I don't want to take a real third question, there's kind of a follow up.
The comment about.
Maybe just letting the number of completions be bad and not going over your capex. Even if you have kind of efficiencies would that comment also applicable to next year I think.
Some of your other peers would likely choose to let their volumes go up and then others are letting their production volumes fall year over year. So I just didn't know if that applied to 'twenty four as well as the maintenance program the <unk>.
<unk> next year as well or is maybe there's some wiggle room.
So, yes, there's always a wiggle room, but no.
Pretty determined to stick to our maintenance cap for 2024 as well so it may turn out the way. It does in 2023 that we move to our completions more quickly but will still.
Stay under the under the budget constraints now.
I'd also add on the.
2020 for maintenance capital level.
It's at a lower level than the 23 capital because of these efficiencies that really drive lower cost plus we are seeing a rollover in the service cost.
Raw materials and as each year that we are at maintenance capital our decline rate lowered by about 1%.
So youll need less wells as well to keep at that maintenance level.
That's perfect. Thanks, guys.
Thank you.
Thank you.
Our next question is from Omar <unk> with Goldman Sachs.
Please proceed with your question.
Hi, good morning, and thank you for taking my questions.
My first question was.
Around the optimal capital structure and your free cash flow breakeven.
Likely going to be and what are the gas price environment does we havent really took gas storage win as demand has increased so I have a two part question for you first would love your thoughts around any actions you can take to further lower your free cash flow breakeven, especially given that your plans to be unhedged going forward and second any thoughts on building cash on the balance sheet.
And on optimal leverage ratios, which can allow you to be more opportunistic in a low commodity price environment.
Yeah. Good question, we're attacking the breakeven by really focusing on the highest liquids opportunities we have and Thats why you see our break evens are so low.
Because we're drilling $12 75 to 1300 Btu wells that are heavily liquid.
Focus so that's how we're.
Really thinking about lowering our breakeven on the natural gas side.
So and then on building cash we wouldn't build cash you.
You saw last year, we would have had an opportunity to that but instead of doing that we are active in the open market repurchasing our debt or bonds.
Some of our bonds become callable two in the first quarter of 'twenty four.
So we would call those bonds instead of building cash and if.
All of that was not available to us we'd be buying back our shares. So I have no plans on building cash on the balance sheet, we'll use it to either pay down our debt or buy back shares.
Quick follow up there then would you be willing to use our credit facility to do share repurchase.
Would you prefer.
To date it remains low.
Liquidity in the case of CVR.
So your outlook.
Yes, no we wouldn't lever up to buy back shares we're a very steadfast in our debt reduction goals and wanted to get it as low as possible. So we would not use our credit facility to buy back shares we'd rather keep it low.
Okay.
Thank you. Our next question is from Arun.
I'm with Jpmorgan. Please proceed with your question.
Yeah, Good morning, maybe.
Maybe ask Dave.
In terms of C. Three plus pricing in the futures market is kind of embedding.
Call It a low 50% range in terms of the WTO in terms of our ratio relative to <unk>.
Do you think that's a fair outlook for the near term.
And how does this potential reduction in shipping costs, how do you think about that influencing.
Demand globally for for a CPI plus just because its cheaper.
And perhaps the.
The ratio relative to <unk>, if we get into a better demand environment.
Yeah, I think it's actually for the near term, we'll just call up into the summer of 2023.
I think levels are probably pretty in line with where we would expect them to be just given the high propane inventory.
Absolute levels.
Same here through March and April .
You know what I'd say as we move through the year, that's where we see the upside as we expect exports to continue to be quite robust and thats, where youll see propane inventories start to move.
Down in the five year range closer to the five year average we've got potential would be below the five year average by the end of the year and that's where you can really see that propane price start to appreciate in the percentage of <unk>.
I offer or Ctrip plus barrel improve.
We continue that.
<unk> strong values for ISO butane in the summer or similar to what we saw last time around value for octane appears to be there again in the market. So I think we'll continue to see some tailwind from that as well, but really you'll see three making up over 50% of our <unk> plus barrel focus is really going to be on the demand side of the equation.
See in those exports start to pull down inventories.
Great.
And just my follow up would be just on the capital efficiency front.
You guys did in <unk>.
Average of 11 stages this quarter.
Well its you know for us.
Tend to think of a good quarters doing eight stages. So that's a pretty impressive.
Number so.
How does that is that influencing yet your thoughts on on the Capex budget, which I think the midpoint in terms of the D&C capex guidance of $900 million.
And do you think this is a level of completion efficiency that can be sustained or did everything just go right. This quarter.
No.
And for the 900 like you are you referenced around in that and our thoughts we've moved up our assumptions I think we were assuming eight to nine stages, a day and we achieved 11, so an hour assuming around 10 stages a day. So we're not assuming the 11 continues but we are assuming.
Better performance and increase performance.
I think that will occur throughout the year.
Can I sneak in one more Mike.
Sure.
I just wanted to get a sense you guys do a lot of great work on the kind of the macro picture.
One question will you be getting from investors and just perhaps thoughts on the timing of Golden pass in 2024, I know you don't operate that that's an exxonmobil.
Project, but do you have any.
Intel or thoughts on the timing of that project, because it's pretty important for the supply demand balance thinking about gas next year.
Let me pass that question, Justin Fowler, who is our vice president of <unk>.
Natural gas marketing trading so Justin yeah, good morning Arun.
We just continue to hear on our side that you know.
Exxon and the Qatari is continue to fast track Golden pass so the first train.
Right that is expected to come online is around seven.
700 $5800 per day.
We're thinking that's going to be sometime in.
2024, so that will just.
Sorry to take more gas.
Now into the liquefaction corridor and then they will continue to ramp up another two trains and again everything that we're hearing there.
Work in the fast track that project.
Thanks, Justin I appreciate it.
Yeah.
Thank you.
Our next question is from David Beckel Baum with PD Cowen. Please proceed with your question.
Hey, guys. Thanks for taking the questions. This morning.
No problem.
I was just I was hoping maybe you could quantify a bit or talk directionally.
About the maintenance capital progression to 24, and 25 and I suppose.
There was also I guess, the theoretical impact of lower free cash breakeven on the corporate level from some of the moniker adjustments over time.
You know I I guess as we sit today given some of the efficiencies that are happening and then it seemed like there was some pressure on costs coming down in the field.
How do you think about like percentage wise as decline in maintenance spend into 'twenty for them beyond that or.
Or was it really the visibility beyond 'twenty four is dictated by base decline.
And at this point.
They all go into it and they're all a tailwind for US David I would you know.
When you think about it in the kind of 10% to 15% range.
Year over year decline 24 versus 23 so.
That's pretty significant and that continues.
You know to be about the level that you need in the out years. It continues to trend a bit down as.
Maintenance capital needed.
For a lower decline declining base as you continue to you know put year after year of flat production in the wedges.
That continues to decline from there.
Thanks, Mike.
If I could just follow up on the land budget I know there was the expectation obviously this would be the largest quarter in terms of land spend but.
I guess as have you seen more opportunities on just some of the land side coming to you as the market has been softer or is there really no correlation between that type of market and what we're seeing on the spot screen.
Yes, no we knew that first quarter was going to be a large one because a lot of these deals that you land. It takes 60 days to close so we knew in November and December we had some large packages that we are able to execute on we're going to close in January and February .
Right now the pipeline is as the budget suggest that you do.
I don't have those large packages. So it should come back into that $25 million level, a quarter type of pace, which is more normal for us.
Thanks, Mike Best of luck guys.
Thank you.
Thank you. Our next question is from Kevin Mccarthy with Pickering. Please proceed with your question.
Hey, good morning, as it relates to service costs can you remind us what your philosophy is on contracting term and how that might play into lower well costs in the back half of this year and into next year.
And I was going to ask you to.
To provide a range of potential impacts, but it sounds like you're just you're just did did you say that maintenance capex would be down 15% next year.
At 10%, a 10 to 15, but I would start with 10 and 24 and then maybe it trends to 15 in the out years after that and 25% compared to 23.
Yeah, so our contracts on the completion side. They expire there generally annual contracts that expire at the end of 'twenty three there are openers and them based on commodity prices and we are obviously with the low natural gas price below those commodity price kind of openers.
So we'll just have to see how that goes in 'twenty three.
The rigs they are.
Generally 12 to 18 months, we try to stagger them. So we don't have all the rigs coming off at once.
So it's a it's.
It's a mix of late 'twenty three in first and second quarter of 24 for the rig.
Great I appreciate that detail and then apologies if I missed this in your presentation or your release, but can you let us know how many wells you turned in line and how many wells you completed in the first quarter.
Well, it's about 80 for the year I think its probably about even on the the world turn lines, maybe low twenties.
Yeah.
Great. Thank you.
Yeah.
Thank you. Our next question is from Sebastian Chandra with the Benchmark Company. Please proceed with your question.
Yeah, Mike just to follow up on the inflation or the deflation question.
How much do you think you'd attribute to being in a gas basin.
<unk> seen some perhaps.
Excess deflationary.
Cal wins, there or how much do you think this is.
Just across all services and materials.
I'd say, it's the latter right now what we're.
Really.
Thinking will occur in 'twenty three it's more on the raw materials side and that'll be across basins, but its more on the tubular it's more on sand costs more on fuel and that's you know regardless, whether it's gas or oil basin, you know you're going to capture.
Some of those cost decreases on the service cost we are now seeing some.
Decline in rig counts and completion crews being used.
Used in our basin.
So theres some spot fleets, becoming available and that should eventually lead to.
The lower service costs, but right now we're not we're not seeing it for.
For this quarter.
Right got it so that 10% to 15% number if you had to wait how much of that raw material dependent versus service dependent is there a number you can throw out there.
Yeah, well at that 10% for next year does not assume any service cost decrease that's really more just looking at the raw material costs, and then looking at it lower well counts because our our decline.
Decline rates go down.
Excellent. Thank you.
Yep.
Okay.
Thank you.
No further questions at this time I would like to turn the floor back over to Mr. Brendan Bell for closing comments.
Thank you for joining us on today's call. Please reach out with any further questions. We are available. Thank you.
This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation.
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