Q3 2023 Range Resources Corp Earnings Call
Yeah.
Yeah.
Welcome to the range resources third quarter 2023 earnings conference call. All lines have been placed on mute to prevent any background noise statements made during this conference call that are not historical facts are forward looking statements such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in forward looking statements.
After the Speakers' remarks, there will be a question and answer period at this time I would like to turn the call over to Mr. Late Sando, Vice President Investor Relations at range Resources. Please go ahead Sir.
Okay.
Thank you operator, good morning, everyone and thank you for joining ranges third quarter earnings call. The.
Speakers on today's call are Dennis Degner, Chief Executive Officer, and Mark <unk>, Chief Financial Officer.
Hopefully you've had a chance to review the press release and updated Investor presentation that we've posted on our website.
We may reference certain of those slides on the call. This morning.
You'll also find our 10-Q on ranges website under the investors tab.
You can access it using the Sec's Edgar system.
Please note, we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures.
So posted supplemental tables on our website.
Realized pricing details by product along with calculations of EBITDAX cash margins and other non-GAAP measures with that let me turn the call over to Dennis.
Thanks, Laith and thanks to all of you for joining the call today.
As we finish out our 2023 program ranges business plan is on track and we're making steady progress on the following key objectives. We have shared with you throughout this year.
Operating safely while driving continued operational improvements.
Generating free cash flow through the cycles, where the peer leading full cycle cost structure.
And prudent allocation of that free cash flow balancing a strong balance sheet with returns of capital to shareholders and the long term development of our world class asset base.
I believe our most recent quarters are a great example of consistent advancement against these objectives and the results reflect the resilience and durability of <unk> business.
During the third quarter, we successfully delivered on our operational plans safely with peer leading efficiencies and.
And ranges competitive cost structure.
Low capital intensity liquids, optionality and thoughtful hedging allowed us to generated healthy full cycle margins, despite a lower commodity price environment.
These results are underpinned by ranges multi decade inventory and brought to fruition by a talented technical team that continues to innovate.
Walking through some of our quarterly results.
All in capital for the third quarter came in at $151 million with your year to date capital spending totaling $478 million or approximately 80% of our annual plan.
This frontloaded capital spending is right on track and follows the activity cadence we outlined earlier this year.
As previously discussed we ran two frac crews for most of the third quarter, which aligns with our back half way to turn in line count and production trajectory.
The second spot crew was released in early Q4 and as of today, we're back down to one dedicated horizontal rig and one dedicated frac crew as planned.
Production for the quarter came in at 212 Bcf equivalent per day.
Adding an average of approximately 40 million cubic feet equivalent per day versus the prior quarter.
And placing us on track for a fourth quarter production increase that aligns favorably with the current shape of the forward commodity curve.
Supporting our production profile, we turned to sales 19 wells during the third quarter.
Operator: Welcome to the Range Resources 3rd quarter 2023 earnings conference call. All lines have been placed on you to prevent any background noise.
13 of these wells are located in our dry acreage position, but the other six located in our wet and Super rich acreage.
Operator: Statements made during this conference call that are not historical facts are forward looking statements. Such statements are subject to risk and uncertainties which could cause actual results to differ materially from those in forward looking statements.
All in southwest, Pennsylvania.
As has become a hallmark of our operations over three quarters of the wells are located on pads with existing production.
Operator: After the speakers remarks, there will be a question and answer period.
Laith Sando: At this time, I would like to turn the call over to Mr. Late Sando, Vice President, and Vester Relations at Range Resources. Please, go ahead, sir. Thank you, operator.
Minimizing our operating surface footprint.
Supporting nimble operations and driving ranges cost efficient development approach and peer leading capital efficiency.
Dennis Degner: Good morning, everyone, and thank you for joining Range's 3rd quarter earnings call.
Looking at operations, just under 1100 Frac stages were completed on 18 wells during the quarter and southwest and northeast, Pennsylvania.
Dennis Degner: The speakers on today's call are Dennis Degner, Chief Executive Officer, and Mark Scucchi, Chief Financial Officer. Hopefully you've had a chance to review the press release and updated investor presentation that we've posted on our website. We may reference certain of those slides on the call this morning. You'll also find our 10 queue on range as well. You can access it using the SEC's Edgar system. Please note, we'll be referencing certain non-gap measures on today's call.
Demonstrating a continuation of our operational efficiencies, we averaged over nine frac stages per day for the quarter.
Representing a 17% increase versus the same time period in 2022.
Our second spot Frac fleet was utilized during the quarter and completed a return trip to an existing producing pad in our northeastern Pennsylvania acreage.
Dennis Degner: Our press release provides reconciliations of these to the most comparable gap figures. We've also posted supplemental tables on our website. It includes realized pricing details by product along with calculations of evidence, cash margins, and other non-gap measures.
Adding three new wells to the pad site.
Consistent with what we've seen this year in southwest PA are completion metrics for this pad improved dramatically versus our initial development.
This was accomplished through our continual learnings and improvements, which drive range as best practices and logistics planning.
Dennis Degner: With that, let me turn the call over to Dennis. Thanks, late, and thanks to all of you for joining the call today. As we finish out our 2023 program, Range's business plan is on track, and we're making steady progress from the following key objectives we've shared with you throughout this year, operating safely while driving continued operational improvements, generating free cash flow through the cycles with the peer leading full cycle cost structure.
Water operations optimization and service partner Kpis.
Altogether. This resulted in an increased number of frac stages per day.
Our reduced cycle time to complete this pad site.
And drove an 80% improvement in overall completions efficiency.
Also during the quarter range successfully completed two of the longest laterals and ranges Marcellus program history.
Dennis Degner: And prudent allocation of that free cash flow, balancing a strong balance sheet with returns of capital to shareholders, and the long-term development of our world class asset base. I believe our most recent quarters are a great example of consistent advancement against these objectives, and the results reflect the resilience and durability of range's business. During the third quarter, we successfully delivered on our operational plans safely with peer leading efficiencies, and Range's competitive cost structure, low capital intensity, liquids optionality, and thoughtful hedging allowed us to generate healthy, full cycle margins despite a lower commodity price environment.
But both lateral lengths exceeding 21000 feet.
And when factoring in the total drill footage from surface to the end of the lateral that total distance exceeded five five miles per well.
As a result of the team's success in increasing lateral lengths in the 2023 program.
Well to complete this year's program with fewer turn in lines than originally planned.
We still plan to turn to sales approximately 650000 lateral feet. However, we will be doing this with 51 wells turned to sales or 16% fewer than what we had planned at the start of the year.
This will drive a <unk> production increase of approximately 40 to 60 million cubic feet equivalent per day over the third quarter.
Dennis Degner: These results are underpinned by Range's multi-decade inventory and brought to fruition by a talented technical team that continues to innovate. Walking through some of our quarterly results, all in capital for the third quarter came in at $151 million, with your year-to-date capital spending totaling $478 million, or approximately 80% of our annual plan. This front-loaded capital spending is right on track and follows the activity cadence we outlined earlier this year. As previously discussed, we ran two-fract crews for most of the third quarter, which aligns with our back half-way-to-turn-in-line count and production trajectories.
And given the flatter production profile of these long laterals it sets us up well heading into early 2024 and to what we expect will be improved pricing.
I congratulate our team on this tremendous accomplishment as we continued to advance efficient long lateral development for rages assets.
Of course record completion efficiencies aren't possible without an integrated water operations and logistics group.
In the third quarter. The team continued to build upon rages ongoing water recycling effort through strategic partnerships with other producers and third party treating facilities.
<unk> and water savings of over $2 $4 million in Q3.
Dennis Degner: Gregory. The second spot crew was released in early Q4 and as of today we're back down to one dedicated horizontal rig and one dedicated frack crew as planned. Production for the quarter came in at 2.12 BCF equivalent per day, adding an average of approximately 40 million cubic feet equivalent per day versus the prior quarter and placing us on track for a fourth quarter production increase that aligns favorably with the current shape of the forward commodity curve.
As mentioned earlier the team operated in both our southwestern and northeastern PAA acreage during the quarter.
Even while concurrent operations were being performed over 200 miles apart.
The team maximize efficiencies across these jobs to achieve our highest recorded water volume delivered in over five years by moving over 200000 barrels of water on multiple days, while establishing a new range record of handling over 800000 barrels and four days.
Dennis Degner: Supporting our production profile, we turn to sales 19 wells during the third quarter. 13 of these wells are located in our dry acreage position, with the other six located in our wet and super rich acreage, all in southwest Pennsylvania. As has become a hallmark of our operations, over three quarters of the wells are located on paths with existing production, minimizing our operating surface footprint, supporting nimble operations, and driving ranges cost efficient development approach and peer leading capital efficiency.
This is an outstanding achievement and demonstrates the team's focus on peer leading capital efficiency and supports our overall financial results that Mark will touch on in just a moment.
Before moving back to marketing I want to touch briefly on service cost.
We recently launched our annual RFP process for services needed in 2024.
The process is in the initial phases, but early indications suggest prices are softening for certain services and consumables versus the start of 2023.
Most notably we have seen a reduction in tubular goods pricing this year.
Dennis Degner: Looking at operations, just under 1100 frack stages were completed on 18 wells during the quarter in southwest and northeast Pennsylvania. Demonstrating a continuation of our operational efficiencies, we averaged over nine frack stages per day for the quarter, representing a 17% increase versus the same time period in 2022. A second spot frack fleet was utilized during the quarter and completed a return trip to an existing producing pad in our northeastern Pennsylvania acreage, adding three new wells to the pad site.
And as a result, we've locked in steel pricing for our 2020 for a program at approximately a 30% discount to what we saw in 2023.
For sand, we've seen similar signs of cost reduction and anticipate those savings could remain in place throughout 2024.
Other consumables like diesel fuel have moved higher and could remain elevated for next year.
While we have a natural hedge against diesel prices with our condensate production, we've secured pricing for a portion of our 2024 development plan further mitigating pricing risk.
Dennis Degner: Consistent with what we've seen this year in southwest P.A., our completion metrics for this pad improved dramatically versus our initial development. This was accomplished through our continual learnings and improvements which drive ranges best practices in logistics planning, water operations optimization, and service partner KPIs. All together, this resulted in an increased number of frack stages per day. A reduced cycle time to complete this pad site, and drove an 80% improvement in overall completion efficiency.
Similar to our 2023 development program range will continue to utilize a super spec drilling rig and an electric Frac fleet in 2024.
Day rates for rigs and 24, showing signs of decline versus peak levels seen over the past 12 months.
Certainly influenced by the current U S rig count.
But super spec rigs remain in high demand.
Similarly for completions electric Frac fleets are operating at a high level of utilization, resulting.
Dennis Degner: Also, during the quarter, range successfully completed two of the longest laterals in Rage's Marcellus program history, with both lateral links succeeding 21,000 feet. And when factoring in the total drill footage from surface to the end of the lateral, the total distance exceeded five and a half miles per well. As a result of the team's success in increasing lateral links in the 2023 program, we were able to complete this year's program with fewer turn in lines than originally planned.
Resulting in comparable year over year pricing. Despite this year's overall rig count reduction across the U S.
To secure this portion of our program range is contracted and electric fleet for two years that is scheduled to commence operations on January one 2024.
In aggregate, we anticipate RFP process will generate a modest year over year cost savings across various services.
We will have the numbers formalized by year end and at the end of the day, we fully expect to remain at the leading edge of capital efficiency, when compared to our peers and other basins.
Dennis Degner: We still plan to turn to sales approximately 650,000 lateral feet. However, we will be doing this with 51 wells turned to sales, or 16% fewer than what we had planned at the start of the year. This will drive a 4Q production increase of approximately 40 to 60 million cubic feet equivalent per day over the third quarter. And given the flatter production profile of these long laterals, it sets us up well heading into early 2024.
We look forward to sharing our 2024 plans with you on the next call.
Turning to the NGL macro and pricing.
Third quarter salt prices increase across the board for both Ngls and condensate.
Overall liquids pricing was supported by upward trending crude values and lifted further by strengthening supply demand fundamentals for Ngls.
Dennis Degner: And to what we expect will be improved price.
Anthony fundamentals strengthen on increased domestic demand and third quarter exports that were up 19% year on year.
Dennis Degner: Housing. I congratulate our team on this tremendous accomplishment as we continue to advance sufficient, long-lateral development for range assets. Of course, record completion efficiencies aren't possible without an integrated water operations and logistics group. In the third quarter, the team continue to build upon range of ongoing water recycling effort through strategic partnerships with those of producers and third-party tree facilities, resulting in water savings of over $2.4 million in Q3. As mentioned earlier, the team operated in both our southwestern and northeastern PA acreage during the quarter.
While LPG balances improved on stronger domestic propane demand and exports that increased 16% versus the prior year's quarter.
At the same time third quarter global LPG balances tightened 14% year on year.
As a result of improving NGL fundamentals range was able to realize $24 44 per barrel in the third quarter.
A 14% increase over the prior quarter.
This realized price represents a 63 per barrel uplift versus the Mont Belvieu index.
Dennis Degner: Even while concurrent operations were being performed over 200 miles apart, the team maximized efficiencies across these jobs to achieve our highest recorded water volume delivered in over five years by moving over 200,000 barrels of water on multiple days while establishing a new range record of handling over 800,000 barrels in four days. This is an outstanding achievement and demonstrates the team's focus on peer leading capital efficiency and supports our overall financial results that Mark will touch on in just a moment.
Reflecting ranges advantaged portfolio of NGL contracts.
And access to international markets.
And as a reminder, each $1 per barrel increase in rages NGL per barrel price represents $30 million in incremental cash flow generated.
As we enter the winter months, we expect fundamentals to remain strong and our NGL price realizations to remain in the $1 minus to $1 per barrel premium for the fourth quarter <unk>.
<unk>, a strong premium to Mont belvieu for the year.
Dennis Degner: Before moving back to marketing, I want to touch briefly on service costs. We recently launched our annual RFP process for services needed in 2024. The process is in the initial phases, but early indications suggest prices are softening for certain services and consumables versus the start of 2023. Most notably, we've seen a reduction in tubular goods pricing this year, and as a result, we've locked in steel pricing for our 2024 program at approximately a 30% discount to what we saw in 2023.
On the natural gas front incremental gas demand for power generation, we touched on during the last quarter proved resilient in the months that followed as the summer expired.
This incremental power demand, coupled with industrial demand growth exports to Mexico and continued LNG commissioning.
It's the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rig out activity reductions we've seen in the haynesville.
To follow we then see further strengthening with increased LNG exports next year and beyond.
Dennis Degner: For sand, we've seen similar signs of cost reduction and anticipate those savings could remain in place throughout 2024. Other consumables like diesel fuel have moved higher and could remain elevated for next year. While we have a natural hedge against diesel prices with our condensate production, we've secured pricing for a portion of our 2024 development plan for their mitigating pricing risk. Similar to our 2023 development program, range will continue to utilize a super-spec drilling rig and an electric frat fleet in 2024.
We are excited about the future of natural gas and Ngls, but regardless of the macro backdrop. The team remains focused on advancing our overall efficiencies.
Levering repeatable well performance across our large contiguous inventory.
While bolstering our strong balance sheet with returns of capital to shareholders.
These are the building blocks that underpins the resilience of ranges business through the cycles and I believe the positive results, we've seen year to date.
A reflection of that.
I'll now turn it over to Mark to discuss the financials.
Thanks Dennis.
Dennis Degner: Day rates for rigs in 24 are showing signs of decline versus peak level seen over the past 12 months, certainly influenced by the current U.S, rig count. But super-spec rigs remain in high demand. Similarly for completions, electric frat fleets are operating at a high level of utilization, resulting in comparable year-over-year pricing despite this year's overall rig count reduction across the U.S. To secure this portion of our program, range is contracted an electric fleet for two years that is scheduled to commence operations on January 1, 2024.
As we turn to the financial results I think some context is helpful to frame upstream companies results in relation to the macro economic backdrop.
During the first nine months of 2023, Nymex natural gas prices averaged $2 71 per Mcf.
Compared to $6 77.
For the same period of 2022.
Wty oil prices were roughly $77 per barrel in the first nine months of 2023 compared to $98 in 2022.
These price declines have led to our natural gas focused rig count drop of 27% since April with U S natural gas production now stabilizing.
Dennis Degner: In aggregate, we anticipate our RFP process will generate a modest year-over-year cost savings across various We'll have the numbers formalized by year end, and at the end of the day, we fully expect to remain at the leading edge of capital efficiency when compared to our peers and other basins.
The read through is it prices experienced year to date are below maintenance levels at least for marginal producers.
With a market that is at low tide, when proves or revealed hopefully the investor task of comparing upstream companies is a bit easier.
Dennis Degner: We look forward to sharing our 2024 plans with you on the next call.
Lower prices highlight the quality of assets the durability of business model and identify those that not only survive, but thrive through cycles.
Dennis Degner: Turning to the NGL macro and pricing, the third quarter saw prices increase across the board for both NGLs and compensate. Overall, liquid pricing was supported by upward trending crude values and lifted further by strengthening supply demand fundamentals for NGLs. Ethane Fundamental Strengthen on the increased domestic demand and third quarter exports that were up 19% year on year. While LPG balances improved on stronger domestic propane demand and exports that increase 16% versus the prior year's quarter.
Despite commodity prices experienced in 2023 range is having a successful year focused on creating value today, while also positioning the company for long term value creation.
Does that mean.
It means range has reduced debt and paid cash dividends, while fully funding our capital reinvestment program that efficiently sustains production, while also positioning the company for the long term as a responsible reliable supplier to growing global demand for U S natural gas.
Dennis Degner: At the same time, third quarter global LPG balances tightened 14% year on year. As a result of improving NGL fundamentals, range was able to realize $24.44 per barrel in the third quarter, a 14% increase over the prior quarter. This realized price represents a $0.63 per barrel uplift versus the Montville View Index, reflecting range's advantage portfolio of NGL contracts and access to international markets. And as a reminder, each $1 per barrel increase in range's NGL per barrel price represents $30 million in incremental cash flow generated.
Putting ranges success in numbers.
<unk> third quarter analyst cash flow totaled $240 million funding $151 million in capital investments.
And the $19 million quarterly dividend.
While maintaining balance sheet strength.
Cash flow was driven by strong production.
Achieving pre Nymex <unk>.
<unk> realization of $2 79 per Mcf during the third quarter.
This realized unit price is 24 cents above Nymex Henry hub, demonstrating the value of ranges diverse sales outlets for natural gas and the pricing uplift from natural gas liquids and condensate.
Dennis Degner: As we enter the winter months, we expect fundamentals to remain strong and our NGL price realizations to remain in the $1 minus to $1 per barrel premium for the fourth quarter, generating a strong premium to Montville View for the year. On the natural gas front, incremental gas demand for power generation we touched on during the last quarter proved resilient in the months that followed as the summer expired. This incremental power demand coupled with industrial demand growth, exports to Mexico, and continued LNG commissioning sets the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rig activity reductions we've seen in the Haynesville.
During the third quarter ranges realized NGL price was $24 44 per barrel or $4 seven on an mcf equivalent basis.
Ranges portfolio of transportation capacity and customer contracts supported differentials delivering roughly 80% of natural gas out of basin.
Virtually all natural gas liquids out of basin.
Generating roughly 90% of revenues from diverse growing premium markets.
In addition, <unk>.
<unk> approach to hedging provide additional support to per unit realizations for hedged realized price of $3 nine per Mcf.
Hedged cash margin per unit of production was a resilient $1 23.
Dennis Degner: To follow, we then see further strengthening with increased LNG exports next year and beyond. We are excited about the future of natural gas and NGLs, but regardless of the macro backdrop, the team remains focused on advancing our overall efficiencies, delivering repeatable well performance across our large, continuous inventory, while bolstering a strong balance sheet with returns of capital to shareholders. These are the building blocks that underpin the resilience of ranges business through the cycles, and I believe the positive results we've seen year to date or reflection of that.
Benefiting from our persistent focus on efficiency and the right way risk of certain price linked to call.
Total cash unit costs improved by 29.
Versus third quarter last year.
The change from prior year, primarily relates to savings and processing fuel and power costs.
Which are related to NGL and natural gas prices.
And demonstrate the resilience full cycle cost structure of ranges business.
Cash interest expense declined by $8 million for the quarter compared to Q3 last year on reduced debt balances.
Ranges financial hedging program supported realized prices for the third quarter with approximately $59 million in Nymex related gains.
Mark Scucchi: I'll now turn it over to Martin to discuss the financials. Thanks, Dennis. Yes, as we turn to the financial results, I think some context is helpful to frame upstream companies results in relation to the macro economic backs.
Looking forward range is natural gas is approximately 50% hedged for the balance of 2023 with an average $3 40 <unk> floor pre.
Mark Scucchi: Actress. During the first nine months of 2023, 9x Natural Gas Prices averaged $2.71 per NCF compared to $6.77 for the same period of 2022. WTI oil prices were roughly $77 per barrel in the first nine months of 2023 compared to $98 in 2022. These price declines have led to a natural gas-focused rig count drop of 27% since April with new U.S, natural gas production now stabilizing. The re-true is that prices experience year-to-date or below maintenance levels, at least for marginal producers.
Providing continued confidence and range of free cash flow profile.
For 2024, we have hedged approximately 50% of natural gas at an average floor price of $3 68.
Using a combination of $4 swaps and.
And colors, retaining upside to roughly $5 30.
Our modest 2025 hedge position on natural gas with an average price of $4 12 did.
It did not materially change quarter over quarter.
The objective of this program is essentially to cover fixed costs at attractive levels, enabling consistent free cash flow, while maintaining exposure to a market poised we expect to positively respond to new LNG facilities coming online alongside rising domestic demand with U S natural.
Mark Scucchi: With a market that is at low tide when truths are revealed, hopefully the investor task of comparing upstream companies is a bit easier. Lower prices highlight the quality of assets, the durability of business models, and identify those that not only survive but thrive through cycles. Despite commodity prices experience in 2023, range is having a successful year focused on creating value today while also positioning the company for long-term value creation.
Gas supply flattening as a result of significantly reduced industry activity.
Turning to the balance sheet.
At the end of Q3, we held cash balances of $163 million, which is essentially unchanged from last quarter.
We will continue to manage our cash balance.
To retain flexibility for efficient working capital management bond redemption and share repurchases.
Mark Scucchi: What does that mean? It means range has reduced debt and paid cash dividends while fully funding a capital reinvestment program that efficiently sustains production will also positioning the company for the long-term as a responsible, reliable supplier to growing global demand for U.S, natural gas.
This cash balance combined with future free cash flow and $1 2 billion available on our undrawn revolving credit facility, providing ample liquidity to efficiently operate our business and take advantage of opportunities the market may present.
Mark Scucchi: Putting ranges success in numbers. Third quarter analyst cash flow total $240 million funding $151 million in capital investments and the $19 million quarterly dividend while maintaining balance sheet strength. Cash flow was driven by strong product sales achieving pre-NIMEX hedge realization of $2.79 per MCFE during the third quarter. This realized unit price is 24 cents above NIMEX Henry Hub demonstrating the value of ranges diverse sales outlets for natural gas and the pricing uplift from natural gas liquids and condensate.
We've been focused on a target capital structure for several years and as of quarter end, we have reduced debt net of cash by roughly $2 5 billion.
Peaked in 2018.
This places us very close to our target range of one to $1 5 billion and net debt.
With current leverage of roughly one times debt to EBITDAX.
In close proximity to our balance sheet targets.
We believe the company is in great shape to continue value creation on a stable financial base throughout the business cycle.
Successful results this year combined with a positive industry backdrop for range going forward support our confidence in the return of capital program discussed on previous calls.
Mark Scucchi: During the third quarter ranges realized NGL price was $24.44 per barrel or $4.07 on an NCS equivalent basis. Ranges portfolio of transportation capacity and customer contract supported differentials delivering roughly 80% of natural gas out of basin, virtually all natural gas liquids out of basin generating roughly 90% of revenues from diverse growing premium markets. In addition, ranges approached a hedging provide additional support to per unit realizations for a hedged realized price of $3.9 per MCFE.
We believe our reliable fixed cash dividend is appropriate at this time and in this market while remaining opportunistic in our share repurchases with capacity available totaling $1 1 billion.
As we look to 2024 with an expected even stronger balance sheet, we will be in a position to evaluate the size and speed at which we deploy free cash flow.
We believe that will provide greater flexibility around our capital allocation priorities of balance sheet strength returns of capital and growth at an appropriate time.
Fundamentally we will prioritize financial strength.
And remain responsive to market conditions project returns.
Mark Scucchi: Hedged cash margin per unit of production was resilient $1.23 benefiting from a persistent focus on efficiency and the right way risk of certain price linked costs. Total cash unit costs improved by 29 cents versus third quarter year. The change from prior year primarily relates to savings and processing, fuel, and power costs, which are related to NGL and natural gas prices, and demonstrate the resilient full cycle cost structure of range of business.
And prudent reinvestment.
In a commodity business prices will fluctuate design.
The designing of business to be successful in both high prices and lower prices is challenging it.
It requires quality assets and a creative dedicated disciplined team.
The range team across every facet of the business.
And act like owners of the business.
Striving to make the best decisions.
For the safest cleanest and most economic results.
A few commonly used words apply to our story.
Mark Scucchi: Cash interest expense declined by $8 million for the quarter compared to Q3 last year on reduced debt balances. Range's financial hedging program supported realized prices for the third quarter with approximately $59 million in 9x related gains. Looking forward, range's natural gas is approximately 50% hedged for the balance of 2023 with an average $3.40 floor providing continued confidence in range's free cash flow profile. For 2024, we have hedged approximately 50% of natural gas at an average $4 price of $3.68 using a combination of $4 swaps and collars retaining upside to roughly $5.30.
Unique differentiated peer leading.
Other superlative.
Instead, I'll point to the data.
Low based client.
Lower full cycle cost structure.
Largest quality acreage position.
And more than a decade of positive performance revisions of proved reserves.
Combination that we believe creates an E&P company built for the long haul.
With a strong financial foundation, and our largest portfolio of quality inventory in Appalachia.
Third with transportation to delivery points across key U S and international markets. We seek to continue this trend of disciplined value creation for our shareholders.
Dennis back to you.
Thanks Mark.
Before moving to Q&A I'll reiterate a message we've shared previously that is as important today as ever given the current world events.
Mark Scucchi: A modest 2025 hedge position on natural gas with an average price of $4.12 did not materially change quarter of a quarter. The objectives of this program is essentially to cover fixed costs at attractive levels enabling consistent free cash flow while maintaining exposure to a market poised we expect to positively respond to new LNG facilities coming online alongside rising domestic demand with US natural gas supply flattening as a result of significantly reduced industry activity.
As the world continues to move towards cleaner more efficient fuels natural gas and Ngls will be the affordable reliable and abundant supply that helps power our everyday lives. While also helping billions of others improve their standard of living.
We believe Appalachian natural gas and natural gas liquids are positioned to meet that future demand.
And within the Appalachian Basin range has de risked a large inventory of high quality wells across our $5 million net acre position and translated that into a business capable of generating free cash flow through commodity cycles.
Mark Scucchi: Turning to the biology, the end of Q3 we held cash balances of $163 million which is essentially unchanged from last quarter. We will continue to manage our cash balance to retain flexibility for efficient working capital management, bond redemption and share purchases. This cash balance combined with future free cash flow and $1.2 billion available on our undrawn revolving credit facility provide ample liquidity to efficiently operate our business and take advantage of opportunities the market may present.
All while leading the way on capital efficiency emissions intensity and transparency.
With that we'll open the line for questions.
Thank you Mr. Degner the question and answer session will now begin if you would like to ask a question. Please indicate by pressing the star key Dan One line.
If youre using a speakerphone please pick up your handset before asking your question. If you would like to withdraw. Your question you may do so by pressing star one again.
Mark Scucchi: We have been focused on a target capital structure for several years and as a quarter end we have reduced debt net cash by roughly $2.5 billion since its peak in 2018. This places us very close to our target range of one to one and a half billion dollars in net debt with current leverage of roughly one times debt to EBITX and close proximity to our balance sheet targets we believe the company is in great shape to continue value creation on a stable financial base throughout the business cycle.
Once again, please press star one to ask a question in one moment for our first question.
Our first question will be coming from Scott Hanold of RBC capital markets. Your line is open.
Yes, thanks, good morning.
I thought it was pretty interesting.
The ability for you guys to reduce the well count so dramatically this year with the longer laterals.
Could you give us some color and context around the overall capital efficiency, where do you think like.
Mark Scucchi: Successful results this year combined with a positive industry backdrop for range going forward, support our confidence and the return of capital program discussed on previous calls. We believe a reliable six cash dividend is appropriate at this time and in this market while remaining opportunistic and our share repurchases with capacity available totaling $1.1 billion.
Like on an annual basis, you could save with drilling less top holes and how does that manifest into or how.
And when does that manifest into stronger free cash flow.
Yes, good morning, Scott I'll start and this may be something that Mark and I both tag team.
Across this this discussion here, but.
When you look over the past several years I will take about a half step back first year over year, we continue to see the team demonstrates the ability to advance our efficiencies and what that's transitioned into is the ability to drill longer laterals I think you've heard us talk about it not only in today, but in some of the prior quarters were not alone.
Mark Scucchi: As we look to 2024 with an expected even stronger Technology. We will be in a position to evaluate the size and speed at which we deploy free cash flow. We believe that will provide greater flexibility around our capital allocation priorities of balance sheet strength, returns of capital and growth at an appropriate time. Fundamentally we will prioritize financial strength and remain responsive to market conditions, project returns and prudent reinvestment.
We will be drilling our longest laterals, but our fastest stays where we saw an improvement at the mid year point of a 40% improvement in our drilling efficiencies just as the first half of the year versus 2020 two's full year average.
Mark Scucchi: In a commodity business, prices will fluctuate, designing a business to be successful in both high prices and lower prices is challenging. It requires quality assets and a creative, dedicated discipline team. The range team across every facet of the business think and act like owners of the business, striving to make the best decisions for the safest, cleanest and most economic results.
Completions are seeing the same thing.
Seen approximately a 20% 25% improvement in completion efficiencies this year versus last year. Some of this with procedures rooting out nonproductive time, and then having the ability to reduce overall cycle time.
As you basically execute these pad sites. So it's a multi variable type of assessment. When you start to then translate that into our capital efficiency.
If you just do a spreadsheet exercise and you compare the 10000 foot program with 61 laterals like we originally communicated to something more like we're seeing today for the year. It really changes our capital efficiency by as much as 15% to $20 per foot so pretty exciting about when you think about it from that perspective, but what that also.
Mark Scucchi: A few commonly used words applied to our story, unique, differentiated, peer leading among other superlatives. Instead, I'll point to the data, low-based client, low full-fleckle cost structure, largest quality acreage position, and more than a decade of positive performance, revisions of approved reserves. The combination that we believe creates an ENP company built for the long haul. With a strong financial foundation and the largest portfolio of quality inventory in Appalachia paired with transportation to delivery points across key U.S, and international markets, we seek to continue this trend of discipline value creation for our shareholders.
It does at the same time as it pulls activity that would have been executed in let's just say the first half of Q1 has the ability to pull that into the back half of Q4, and so when you think about.
Our guidance that we provided early on this year from a capital window perspective, and we're looking at both land and other aspects to this part of that was us looking forward and anticipating some of these capital are these operational efficiency improvements and what that could set us up for in 2020 for having these long.
Dennis Degner: Dennis Beckier, thanks Mark.
Dennis Degner: Before moving to Q&A, I'll reiterate a message we've shared previously that is as important today as ever given the current world of this. As the world continues to move towards cleaner, more efficient fuels, natural gas and NGLs will be the affordable, reliable, and a abundant supply that helps power our everyday lives while also helping billions of others improve their standard of living. We believe Appalachia, natural gas, and natural gas liquids are positioned to meet that future demand.
Your laterals is going to present, a flatter production profile that carries into the early part of 2024. So we really like the setup is seeing how this then translates into year over year further improvements and then the last thing I'll certainly throw out is again congratulations to the team for all their hard work on this it is.
As a supervisor am I used to say success begets success, and so the momentum I think behind everyone in what we've been able to accomplish by returning to pad sites is now what we're seeing in our peer leading capital efficiency the ability to maintain that 76 cents per mcf fee for the replacement molecule. This year last year's 64.
Dennis Degner: And within the Appalachian Basin, range has derives the large inventory of high-quality wells across our half million net acre position, and translate that into a business capable of generating free cash flow through commodity cycles. All while leading the way on capital efficiency, emissions intensity, and transparency.
So however, it shapes up with what pulls in this year, we fully expect that to be another component that allows us to be on that peer leading edge.
Okay, and just specifically on the on the cost savings are those.
Operator: But that will open the line for questions.
If we're looking at 10 less wells on it this year for example, like what does that save you.
Operator: Thank you, Mr. Degner.
Operator: The question and answer session will now begin. If you would like to ask a question, please indicate by pressing the star key then 1-1. If you're using a speaker phone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing star 1-1 again. Once again, please press star 1-1 to ask a question in one moment for our first question.
If were to look at that in isolation, just as a reference point.
Well again from a from a simplistic standpoint, I would say ultimately you could if you start to remove top holes out of the program and you start to look at savings for facilities construction that could represent approximately $10 million.
But when you start to think about that activity that pulls in then at the end of the year essentially that gets redeployed two drilling rigs frac activity that ultimately when you have that operational fork in the road of it doesn't make a whole lot of sense to release rigs conferred December wanted to only didn't pick it back up in January one as we sample so.
Scott Hanold: Our first question will be coming from a stat handle of RBC capital markets. The line is open. Yeah, thanks.
Dennis Degner: Good morning. I thought it was pretty interesting the ability for you guys to reduce the well-conced dramatically this year with the longer laterals. Can you give us some color and context around the overall capital efficiency? What do you think, like on an annual basis, you could save with, you know, drilling less top holes? And how does that manifest into or how and when does that manifest into stronger free cash flow?
It maintains that ability to continue on with your operational efficiencies, but at a high level spreadsheet exercise it would be around $10 million, but it really provides us the flexibility year in and year out to make that judgment call.
We reached the year end.
Yeah, No I appreciate that as you know, we do a lot of spreadsheet exercise on the side of the table, but.
Dennis Degner: Yeah, good morning, Scott. I'll start and this may be something that Mark and I both tag team across this discussion here. But when you look over the past several years, I'll take about about a half step back first year over year, we continue to see the team demonstrate the ability to advance our efficiencies and what that's transitioned into is the ability to drill longer laterals. I think you heard us talk about it not only in today, but in some of the prior quarters where not only were we drilling our longest laterals, but our fastest days where we saw an improvement at the mid-year point of a 40% improvement in our drilling efficiencies just so the first half of the year versus 2022's full year average.
And my second question and it's going to be along the same lines look it sounds like then you're going to have more ducks at the end of the year and can you talk about having that larger DUC build the set up for 2024 and maybe into 2025, how you look at potentially utilizing that.
More aggressively or just has a lower kind of free cash or free cash flow buffer.
Into 2024.
Well I'll start off with this and when we think about the again at a high level what it does allow us from a flexibility standpoint is to deploy a completion crew January one instead of maybe waiting to see that DUC inventory build thats more quote just in time within that completions activity.
Dennis Degner: Completion is seeing the same thing. They've seen approximately a 20 to 25% improvement in a completion efficiencies this year versus last year. Some of us with procedures, rooting out non productive time and then having the ability to reduce overall cycle time as you basically execute these pathsides. So it's, it's a multi variable type of assessment when you start to then translate that into our capital efficiency. If you just do a spreadsheet exercise and you compare a 10,000 foot program with 61 laterals, like we originally communicated something more like we're seeing today for the year, it really changes our capital efficiency by as much as $15 to $20 per foot.
Starts with just a little bit later into the first quarter. So it really does provide a nice setup for us and how we then see that production come online hopefully it.
More favorable pricing opportunities I think the activity that not only gets pulled forward in 2024, but at the end of this year. Also then makes that equivalent impact from a cash flow perspective.
Just frame it at a high level as to say, we see that helping US then take either capital pressure off for next year, where depending upon the set up that we're going to consider for 2025 that will communicate at the next earnings call along with our 2020 for budget. We think it provides a really healthy optionality for us to either think about.
Dennis Degner: So pretty exciting about it when you think about it from that perspective. But what that also does at the same time is it pulls activity that would have been executed in, let's just say the first half of Q1 has the ability to pull that into the back half of Q4. And so when you think about our guidance that we provided early on this year from a capital window perspective, and we're looking at both land and other aspects to this part of that was us looking forward and anticipating some of these capital are these operational efficiency improvements.
Growth win.
That opportunity persist or how it further supports our maintenance level program whichever path is most prominent.
I appreciate the color. Thank you.
Thank you Scott.
One moment for our next question.
And our next question comes from Doug Leggate of Bank of America. Your line is open.
Dennis Degner: And what that could set us up for in 2024 having these longer laterals is going to present a flatter production profile that carries into the early part of 2024. So we really like the setup and seeing how this then translates into year over year further improvements. And then the last thing I'll I'll certainly throw out is, you know, again, a congratulations to the team for all our hard work on this. It is as a whole supervisor might use to say success gets success.
Thank you good morning, everyone. Dennis I appreciate all the details this morning, there's obviously Scott.
Scott hit a couple of the key.
Issues are obviously going to impact your outlook for 'twenty four so I have a simple question to try and summarize.
All the moving parts what do you think has happened.
Or will happen to your corporate level breakeven gas price and the reason I'm asking is it.
Dennis Degner: And so the momentum. I think behind everyone and what we've been able to accomplish by returning to peg sites is now what we're seeing in our peer leading capital efficiency. The ability to maintain that 76 cents per MCFE for the replacement molecule this year, last year, 64 cents. So however it shapes up with what pulls in this year, we fully expect that to be another component that allows us to be on that peer leading edge.
It looks to us that you were pretty close to breakeven ex hedges in 'twenty.
Third quarter 2003.
But at $2 50.
Henry hub gas price, we've got a forward curve north of four it seems to us the market continues to grossly underestimate the free cash flow capacity of the portfolio. So I'm trying to understand what you would.
Where you would draw the line in terms of what you think Youre 24, corporate breakeven can look like and I've got a quick follow up please.
Dennis Degner: Okay, and just specifically on the cost savings of those, you know, if we're looking at, you know, 10 months wells, you know, on it on, you know, this year, for example, like, what would that save you if we were to look at that nice relation just as a reference point. Well, again, from a, from a simplistic standpoint, I would say, you know, ultimately you could, if you start to remove top holes out of the program and you start to look at savings for facilities construction, I could represent approximately $10 million.
Sure Good morning, Doug Thanks for the questions.
Yes, I think as we think about the breakout of our inventory on slide five it's something we've walked through a number of times with folks, but we've made the transition from really talking about wells from an EUR per thousand foot perspective, and really starting to talk about the breakeven, which youre addressing.
We basically look at it from a standpoint, we've got the 2500 locations that basically have a breakeven of $2 50 or less.
Dennis Degner: Awards. But when you start to think about that activity that pulls in then at the end of the year, essentially, that gets redeployed to drilling rigs, frack activity. That ultimately, when you have that operational fork in the road of, it doesn't make a whole lot of sense to release the rigs come for December 1 to only then pick it back up in January 1 as an example. So it maintains that ability to continue on with your operational businesses.
With further improvements in our capital efficiency and Youre always going to have fluctuations in service costs that are going to take place just given what's going on in the market. We would expect that to be incredibly stable and be opportunity to further improve that as we look at expanding areas like water recycling as an example, and further trends translate.
Some of the record efficiencies that we've been talking about this year into more repeatable performance.
Dennis Degner: But at a high level, spreadsheet exercise, it would be around $10 million. But it really provides us the flexibility year in and year out to make that judgment call when we reach the year in. Yeah, I appreciate that as you know, we do a lot of spreadsheet exercises on the side of the table. But, you know, as my second question, it could be along the same lines. You know, look, it sounds like then you're going to have more ducks at the end of the year.
Certainly it's fun to talk about the records, but really in order to be successful. We know it's important that we be repeatable. So how do you translate that into repeatable formats, and we think that has the opportunity to further improve our overall breakeven costs from that inventory bidding perspective.
Hey, Good morning, Jeff This is mark I'll, yes.
Dennis Degner: And can you talk about, you know, having that larger duck build, the setup for 2024 and maybe into 2025, how you look at, you know, potentially utilizing that. You know, more aggressively or just as a lower, you know, kind of free cash or a free cashable buffer into 2024.
Alright.
Dollar per foot level, the corporate level not the not the well level sorry, Mark go ahead.
Sure I think stepping back and look at the corporate level cash flow third quarter. This year is really.
An exemplary example of what this asset can do.
We generated greater than $90 million in free cash flow.
We intentionally reinvested and deploy that maintain the balance sheet strength pay the dividend continued to maintain and improve the balance sheet. Because this asset in <unk> can be viewed like an annuity I know, that's one lens through which you used to value.
Scott Hanold: Well, I'll start off with this. And when we think about the, you know, again, at a high level, what it does allow us from a flexibility standpoint is to deploy a completion crew January 1. Instead of maybe waiting to see that duck inventory build that's more, quote, just in time for then that completion activity starts with just a little bit later into the first quarter. So it really does provide a nice setup for us and how we then see that production come online, hopefully at more favorable pricing opportunities.
As we fast forward and look at what this company can do Theres a few scenarios in our deck to talk about free cash flow hypothetical scenarios.
Approach $4 Youre generating what we think is a reasonable perhaps conservative estimate of $1 billion per year corporate level of free cash flow and greater and I think it's notable also that that incorporates an assumption, but fairly conservative NGL realizations. So there is basically an option an upside option embedded in that as well. So if we're thinking about <unk>.
Scott Hanold: I think the activity that won't not only gets pulled forward in 2024, but at the end of this year also then makes that that equivalent impact. From a cash flow perspective, you know, I'll just frame it at a high level as to say we see that helping us and take either capital pressure off for next year or depending upon the setup that we're going to consider for 2025 that will communicate at the next earnings call along with our 2024 budget.
<unk> scenario that represents an enormous annuity of cash flow ranges that we've talked about before and as Dennis has already said, we are very mindful of positioning the business to be resilient. If prices are soft, but also to position ourselves to participate in growing demand, whether that's 25 pick your timeframe.
Scott Hanold: We think it provides a really healthy optionality for us to either think about growth when that opportunity persists or how it further supports our maintenance level program, whichever path is most prominent. Appreciate the color. Thank you. Thank you Scott.
Range has the capacity of the willingness and the ability to to grow to grow efficiently and generate what we think will be some of the most competitive margins out there. So.
I think the repeatability of that also to them at this point is key this inventory depth multiply that out across a couple of decades times, a $1 billion of free cash flow annually at the corporate level and improving as we pay off debt.
Operator: One moment for our next question.
Douglas Leggate: And our next question comes from Doug Legate of Bank of America. Your line is open. Thank you.
Other corporate cost reduced on an mcf basis, expanding your per unit margins.
Douglas Leggate: Good morning, everyone. Dennis, I appreciate all the details this morning. There's obviously Scott hit a couple of the key issues that are obviously going to impact your outlook for 24. So I have a simple question to try and summarize all the moving parts. What do you think has happened or will happen to your corporate level break even gas price? And the reason I'm asking is it looks to us that you are pretty close to break even X hedges and 20 as third quarter 23.
That.
I think really does represent a unique opportunity in this space.
Marcos Thanks for the clarification guys.
Douglas Leggate: But at 250 Henry hub gas price, we've got a forward curve north of four teams towards the market, continues to grossly underestimate the free cash flow capacity of the portfolio. So I'm trying to understand what you would, where you would draw the line in terms of what you think you're 24 corporate break even can look like. And I've got a quick bubble up, please.
You are right I mean that the other thing too many companies can claim the inventory depth. So I don't know that I would say when you look at everything of annuity, but but.
Certainly inventory depth is a big constraint on valuation for sure. So thank you for that clarification quick follow up guys.
If your inventory depth as defined on 10000 foot laterals, which I believe it is but youre drilling significantly longer laterals and improving capital efficiency.
Much longer do you think I mean, how long do you think the program can continue to step up into those longer laterals and I'll I guess, we'll see inventory that put the longer lateral just a question. So I'll leave it there. Thank you.
Thank you, Doug I think Theres a lot of running room. When you think about the ability to further extend our laterals and what that means to our overall program. If you look back over the past, let's just say three years I'll pick something reasonably near term year over year, we've seen continued theme of incrementally.
Dennis Degner: Sure, good morning, Doug. Thanks for the questions. You know, I think as we think about the breakout of our inventory on slide five, it's something we've walked through a number of times with folks, but you know, we've made the transition from really talking about Wells from an EUR for thousands. And foot perspective and really starting to talk about the break evens, which you're, you're addressing. We basically look at it from a standpoint, we've got the 2500 locations that basically have a break even of 250 or less with further improvements in our capital efficiency.
Increasing our overall lateral lengths and I know we've talked about this on previous calls, but also while returned to pads with existing production. So this isn't necessarily what we would call clean sheet development, where you are moving out into the fringes of your asset base is in and around prior producing wells and taking the learnings from those historical exit.
Dennis Degner: Now you're always going to have fluctuations and service costs that are going to take place just given what's going on in the market. We'd expect a, that could be incredibly stable and be opportunity to further improve that as we look at expanding areas like water recycling as an example and further translating some of the record efficiencies that we've been talking about this year into more repeatable performance. Certainly, it's fun to talk about the records, but really in order to be successful, we know it's important that we be repeatable. So how do you translate that into repeatable formats. We think that has the opportunity to further improve our overall break even costs from that inventory bidding perspective. Thank you, Marty.
Houston's and translating that into more efficient execution and planning. So we see the 21000 foot laterals that we drilled this year is a good reflection of that we've got in excess of 60 wells that are at 15000 foot and horizontal length. So again, we'll move methodically through equipment upgrades procedure.
Yours, TPI tracking and make sure that we're <unk>.
Leading our laterals in the most efficient and prudent way.
<unk> looked at the end of the day, we've got an inventory runway even with exceeding of these laterals is 30% greater than 30 years with breakeven is that are the $2 range or better and so we think this is going to bode well as we think about the runway of this inventory development process.
Mark Scucchi: This is Mark. Oh, sorry, the corporate level, the corporate level, not the not the well level. Sorry, Mark. Go ahead. Sure. I think sitting back and looking at the corporate level cash flow. Third quarter this year is really an exemplary example of what this asset can do. We were, we generated greater than $90 million in free cash flow. We intentionally reinvested and employed that, maintain the balance sheet strengths, pay to dividend, continued to maintain improve the balance sheet because this asset in one sense can be viewed like an annuity.
Gentlemen, thanks for your time I appreciate the answers.
Thank you, Doug and one moment for our next question.
And our next question will come from Jean Ann Salisbury of Bernstein. Your line is open gene.
Hi, Good morning, one more follow up on the dry barriers.
Longer laterals and fewer turned in line love how material is the shape of the forward curve and that decision. For example, if the forward curve goes into backwardation would that would that kind of push you to stop extending lateral length or even potentially get a shorter laterals.
Mark Scucchi: I know that's, you know, one lens, which you use to value a factor is we fast forward and and look at what this company can do. There's a few scenarios in our deck to talk about free cash flow hypothetical scenarios. We have, you know, as we approach $4, you're generating what we think is a reasonable perhaps conservative estimate of a billion dollars per year, corporate level of free cash flow. And greater.
I think maybe from an economic.
Standpoint, I'll start this one off.
The shape of the forward curve.
<unk>.
Drive.
Mark Scucchi: And I think it's notable also that that incorporates an assumption fairly conservative in GL realization. So there's basically an option, an upside option embedded in that as well. So if we're thinking about a maintenance scenario, that represents an enormous annuity of cash flow ranges. We've talked about before and as Dennis has already said, we are very mindful of positioning the business to be resilient of prices or soft, but also to position ourselves to participate in growing demand whether that's 25 pick your time frame range has the capacity, the willingness and the ability to to grow to grow efficiently.
Will be the primary driver in that decision, making process as we look at efficiency in driving Lewis maintenance capital number possible. It is optimizing those capital Reinvestments.
Creating a company with.
Call, it, 40% or better reinvestment rate to hold production flat in that.
70, some cents.
<unk> capital expenditure to hold production flat so the shape of the curve as we think about the overall economics. It's also impacted by the flat decline rate that range, 19% decline rate. So as you flatten that out over time, we're looking at a price three year through the seasonality what the sustainable price levels.
Mark Scucchi: And generally what we think will be some of the most competitive margins out there. So I think the repeatability of that also to Dennis this point is key, this inventory depth, multiply that out across a couple decades times a billion dollars free cash flow annually at the corporate level. And improving as we pay off debt and other corporate costs reduce on an empty Fee basis expanding your per unit margin that that I think really does represent a unique.
And of course, that's also bolstered by the hedging program. So prices will move they will move radically our balanced program that generates significant contribution from the liquids cut as well combined with the natural gas cut along with sales points across the U S. The.
Shape of the curve doesn't necessarily impact us deciding to drill 12 to 15000 foot lateral really it comes back to what's the economics with the space in the existing system, where are we placing that to optimize the use of the existing surface facilities existing compression gathering and long haul transport so.
Not to talk around the question, but its just a multifaceted.
Mark Scucchi: [inaudible] Mark Sons, Mark Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, Mark Sons, of Dollar. Yes, no, that makes sense. Thank you. And then your differential guidance for the year moved, it was slightly, but moved slightly to the 40 to 45 cents. Can you give any more color around whether that was specific in market, getting a little bit worse or in basin pricing?
Asian and evaluation, we do to make sure we can get the most out of the three investor dollar, yes, no that makes sense. Thank you.
And then your differential guidance for the year.
That means slightly to 40 to 45 and can you give any more color on whether that was specific end market getting a little bit worse.
And based on pricing.
Life can add some details to that but I think the short version is we all know in shoulder seasons.
And where storage levels were in the third quarter. There were some soft spots in the in basin markets in particular in Appalachia, but Fortunately 80, plus percent of our gas out of basin and basically all of our liquids over 90% of our revenues out of basin. So that inflection of that minority of the production that sold in basin.
It is bolstered by our by our basis hedging program and effectively a basis hedging program embedded in the physical sales and diversity of customers we have but.
That's the long and short of it Theres been no substantial change to our portfolio of customers, we still sell across greater than 30 different natural gas pricing points, and we'll look to keep optimizing that program over time that portfolio over time.
Great. Thanks, that's all for me.
And one moment for our next question.
Our next question will be coming from <unk> Chaudhry of Goldman Sachs <unk> Company. Your line is open.
Hi, good morning, and thank you for taking my questions.
My first question. My first question was on the NGL macro I appreciate all the details on the slide deck.
So they have been weak this year.
Especially for LPG and you've seen that pick up in exports recently, but the fruit bases have been high dose. So would love your thoughts around the LPG outlook heading into next year.
You bet good morning <unk>.
I think as we start to think about it.
I'll start with propane first when you think about.
What we've seen clearly stock levels have been elevated were running around 100 million barrels in inventory levels.
That's clearly on the back of the weaker winter from this past year and also maybe a little bit of a slower progression to the chemical markets than what had originally been anticipated.
Thank you would you start to think about 24, which was the crux of your question.
A couple of things.
See our we see is underpinning.
Positive movement going forward and one is the PVH infrastructure and <unk>.
In cracker infrastructure, that's been in the process of being commissioned seeing improving run rates month over month, but also additional infrastructure that will get commissioned so it's around 400000 barrels a day and infrastructure this year.
And next year, it's in excess of 400000. So you have got back to back years of what we will call incremental.
Needs in an infrastructure thats going to get commission, that's going to help with this stock level perspective in view.
The other side of this equation is you have got really strong exports. If you look at year to date values. We've seen a range of one five to one 7 million barrels a day.
Average is a little over one five for the year the.
A few years ago that would've been a peak moment and a record $2 two but now it's good strong repeatable performance month in month out so thats certainly helping with the equation. When you think about days of supply, though when you translate that back to where we're at today really 3% below the five year average. So when you think about all of the demand component in getting through the winter setup.
We have ahead of us we see stock levels, starting to re normalize as you get into the through the first half of 2024.
Anthony is tighter diesel supply on that side is around 18 days in storage levels are just below 50 million barrels that we continue to see strong interest from our traditional counterparties on additional ethane opportunities and so we would expect to see.
Some some spikes at times and pricing like we've seen over the past three months to six months, it's been reflective in how the market has been tight and we would expect to see some ongoing volatility as we move forward and of course once we start to see net gas storage levels get re normalized as well you would expect to see further improvements in ethane treating then on the <unk>.
With what's happening on the gas spreads as well.
I will join in here as well as we think about the valuation impact of that commentary in the backdrop that creates today, we're seeing NGL realizations in the 35% tightened ZIP code mid thirties relative to WTS as we think about a more normalized level that we would fully expect to be well in excess of 40% what youre seeing is an embedded option value.
Mark Scucchi: Um, life can add some details to that, but I think the short version is we all know in shoulder seasons and, and where storage levels were in the third quarter, there were some soft spots in the in basin, markets in particular in Appalachia, but fortunately 80 plus percent of our gas is out of basin. And basically all of our liquids over 90% of our revenue is out of basin. So that is a selection of that minority introduction that's sold in basin.
Within range for that re rating for the normalization of propane inventories and while nominally they are high on a days to cover basis like many many of the other commodities, they're not that far off of five year averages. So with these high export levels growth and demand the speed at which they can recover to normalized level nominally and actually become tight in reality.
Mark Scucchi: Um, you know, it is bolstered by our, by a basis hedging program and effectively a basic hedging program embedded within the physical sales and diversity of customers we have. But, um, that's that's the long and short of it. There's been no substantial change to our portfolio of customers. We still sell across greater than 30 different natural gas pricing points and we'll look to keep optimizing that program over time, that portfolio over time.
Douglas Leggate: Great. Thanks. That's all for me.
Operator: In one moment for our next question.
It really highlights the value of that embedded option of Ngls within the range story.
Okay.
Another option that you have.
On growth given your differentiated inventory.
Anything you would like to see on local demand or anything you are seeing on gas marketing, which can unlock that potential.
Heading into next year.
And the next few years.
Umang Choudhary: Our next question will be coming from among Chargery of Goldman Sachs and Company. Your line's open. Hi. Good morning. And thank you for taking my questions. My first question was on on the NGL macro. I appreciate all the details on your slide deck. Prices have been weak this year, especially for LPG. And you've seen a pickup in exports recently, but the free prices have been high, too. So we'd love your thoughts around the LPG outlook heading into next year. You bet. Good morning.
Yes, I think when you start to think about the opportunity for growth and we will just say in basin demand clearly a shell cracker is a good example of it.
It's ongoing commissioning getting to higher run rates over the course of time and it's working through but we would kind of view as normal Greenfield startup type.
Challenges, but also successes in the same breath. So I think that's a good example, I think the other part is is you've got coal retirements that are going to be taking place over the balance of the next few years opportunity for Nat gas and range to backfill those opportunities for power generation I think if we learned anything this past summer net.
Dennis Degner: Um, I think as we start to think about, you know, we're, I'll start with propane first when you think about, um, you know, what we've seen clearly stock levels have been elevated. We're running around 100 million barrels in inventory levels. Um, that's clearly on the back of a weaker winner from this past year and also maybe a little bit of a slower progression to the chemical markets than what had originally been anticipated.
Yes, really stood strong for that backfill of powder generation, adding two five bcf roughly.
Incremental power to power generation and occupying that space when times wind and others were below forecast. So we see those as kind of more in the near term I think when did you start to get past 2024, you really start to have the question of what additional power generation is going to get put into place from a combined cycle.
Dennis Degner: And I think if you start to think about 24, which was the crux of your question, you know, a couple of things I see are we seeing is underpending, you know, a positive movement going forward. And one is the PDH infrastructure and, uh, and cracker infrastructure that's been in the process of being commissioned, seeing improving run rates month over month, but also additional infrastructure that will get commissioned. So it's around 400,000 barrels a day in infrastructure this year.
Dennis Degner: And next year, it's an excess of 400,000. So you've got back-to-back years of what we'll call incremental, needs and in infrastructure that's going to get commissioned, that's going to help with this stock level perspective and view. The other side of this equation is you've got really strong exports. If you look at year-to-day values, we've seen a range of 1.5 to 1.7 million barrels a day. Average is a little over 1.5 for the year.
Standpoint, I think youre seeing a lot of dialogue now around the grid reliability, how you expand that if we're going to have further electrification and bolstering of the grid.
That's going to come with a reliable fuel source, which we think range of net gas is going to play a huge role in that and I think the second thing I would throw out on the future is EV battery industrial type development manufacturing if you start to look at where some of this.
Incremental in future.
Manufacturing and industrial demand is pointing to to be constructed it's not too far away from some of the transport that range has in our portfolio that gets us to the Gulf to the Midwest. So again, we really see this as being a bright future for not only net gas and Ngls, but how is the role that range could play in that.
Dennis Degner: The few years ago, that would have been a peak moment in a record 2.2, but now it's good, strong, repeatable performance month in and month out. So that's certainly helping with the equation. When you think about days of supply, though, and you translate that back to where we're at today, we're really 3% below the five-year average. So when you think about all the demand component and getting through the winter setup that we have ahead of us, we see stock levels starting to re-normalize as you get into through the first half of 2024.
As you start to see inventory exhaustion by others and also then underpinned by the quality and runway of inventory that range and so we think it's a bright future.
It's a multi variable perspective as you look forward.
Very helpful. Thank you so much.
Thank you.
One moment for our next question.
Dennis Degner: Ethane is tighter. The basis of supply on that side is around 18 days and storage levels are just below 50 million barrels. And we continue to see strong interest from our traditional counter parties on additional ethane opportunities. And so we would expect to see some spikes hit times in pricing, like we've seen over the past three to six months. It's been reflective in how the market has been tightened. We would expect to see some ongoing volatility as we move forward.
Yes.
Our next question will be coming from Michael <unk> of Stephens. Your line is open.
Hi, Good morning, guys does give some detail on the savings you anticipate per steel and sand maybe on rig costs as well.
It looks like you kept your well costs in your investor deck unchanged from last quarter.
Can you say.
Dennis Degner: And of course, once we start to see net gas storage levels get re-normalized as well, you would expect to see further improvements in ethane trading then on the back of what's happening on the gas spread as well. I'll join in here as well as we think about the valuation impact of that commentary and the backdrop that creates, you know, today we're seeing ingial realizations in the 35% type of mid 30 relative to WTI.
Are you seeing 24 costs will be.
Relative to 'twenty three.
Some of those savings get offset elsewhere I know you mentioned.
The new Frac fleet.
Fleet.
Is that going to offset those savings or do you anticipate lower cost structure.
Yes, good morning, Michael I think I would I would start off by somewhat saying, we're super early in the process of our RFP rollout that we just deployed here over the last several weeks. So what I'm sharing with you is kind of some of those early indications in the prepared remarks. This morning, I think we're going to have.
Dennis Degner: As we think about a more normalized level that we would fully expect to be well in, because that's a 40%. What you're seeing is an embedded option value within range for that re-rating for the normalization of protein inventories. And while nominally they are high on a days to cover basis, like many, many of the other commodities, they're not that far off of five year averages. So with these high export levels growth and demand, the speed at which they can recover to normalize levels nominally and actually become tight in reality really highlights the value of that embedded option of NGO.
A lot better view once we get toward the end of the year, we get that process wrapped up and we start to communicate how that translates into our execution for our plan for 2024. So I think we'll have a lot better view at that point.
Dennis Degner: What else within the range story? Another option which you have is also on growth given you a differentiated inventory. Anything you would like to see on local demand or anything you are seeing on gas marketing, which can unlock that potential heading into next year or in the next few years.
The numbers in the back of the slide deck haven't changed because ultimately we're still in the middle of that evaluation of that process and once we know what our full cost structure will look like then we'll have again better updates you are seeing in our opinion I'll share. One final thought you are starting to see I think a.
Maybe cost are going to look differently than the traditional rig count service cost of rig count down service costs down across the board.
Dennis Degner: Yeah, I think when you start to think about the opportunity for growth and we'll just say in base and demand, you know, clearly a shell cracker is a good example of its ongoing commissioning, getting to higher run rates, you know, over the course of time. And it's working through what we would kind of view as normal greenfield startup type, you know, challenges, but also success in the same breath. So I think that's a good example.
We tried to share some of that this morning in the prepared remarks, because youre still seeing a high level of utilization for our services as an example, like Super spec drilling rigs and also the electric fracturing fleets, we think that could prevent could present some stabilization in that cost structure, maybe even some slight relief, but it'll be other areas that we may see.
Dennis Degner: I think the other part is, is you've got whole retirements that are going to be taking place over the balance of the next few years opportunity for, you know, net gas and range to backfill those opportunities for power generation. I think if we learned anything this past summer, you know, net gas really stood strong for that backfill of power generation adding to and have BCF, you know, roughly an incremental power generation in occupying that space when, you know, at times, wind and others, you know, we're below forecast.
Again more relief, whether it's some of the consumables like tubular goods, where we're seeing that 30% relief for for next year and have done a job of securing that but also in areas like diesel fuel more stabilization on the frac sand side as well. So we will have better numbers for everyone. At the next call, but we would expect to see some modest.
Level of savings it could be.
Single digit type savings mid level, but we will have a better answer once we get to February.
Dennis Degner: So we see those as kind of more in the near term. I think when you start to get past 2024, you know, you really start to have the question of what additional power generation is going to get put into place from a compound cycle standpoint, if you're seeing a lot of dialogue now around the grid reliability, how you expand that we're going to have further electrification and bolstering of the grid. That's going to come with a reliable fuel source, which we think range and that gas is going to play a huge role in that.
Understood. Thanks.
I guess given the longer laterals, the improved capital efficiency. It sounds like your base decline rate continuing to shallow can you say where maintenance capex or maybe GE.
Easier maintenance activity level would need to be next year relative to 2023.
I think a way of thinking about our program for 'twenty four.
It's type scenario is around $600 million.
Dennis Degner: And I think the second thing I would throw out on the future is ED battery industrial type development manufacturing, if you start to look at where some of this. Chris, incremental and future manufacturing and industrial demand is is pointing to to be constructed. It's not too far away from some of the transport that range hands in our portfolio that gets us to the Gulf to the Midwest. So again, we really see this as being a bright future for not only that gas and AGLs, but how the role that range could play in that as you start to see inventory exhaustion by others.
You could see that be slightly less depending upon the setup. We are thinking about for 2025. Once we start to get to February you see what kind of winter we've got.
LNG infrastructure build out how thats further progressing along so I think there are several variables that we would want to take into account, but I think the way to think about our program and a maintenance scenario was about $600 million.
And it would be around 50 to 60 wells I think historically, we would've said 60 wells kind of year in and year out, but with the advancement in our lateral links it could be somewhere closer to 50.
Depending upon what kind of inventory, we would like to carry into the setup for 2025.
Dennis Degner: And also then underpinned by the quality and runway of inventory that range has. So we think it's a bright future. It's a it's a multivariable perspective as you look forward. Betty has. Thank you so much. Thanks, your mom.
Very good thank you.
Thanks, Michael and one moment for our next question.
Michael Scialla: And one moment for our next question. Our next question will be coming from Michael Salah of Steven's. Your line is open.
Our next question will be coming from Jacob Roberts.
Of Tpa <unk> company your line is open.
Good morning.
I think you touched on this in response to Doug earlier, but I'm just curious if you could remind us the percentage of activity that has been on prior pads in recent years, and where you expect that percentage to ship to over the next let's say 12 to 24 months.
Michael Scialla: Hi, good morning, guys. Then give some detail on the savings the anticipate for steel and sand, maybe on rig costs as well. It looks like you kept your well costs in your investor deck unchanged from from last quarter. Can you say where do you think 24 costs will be relative to 23 do some of those savings get offset elsewhere. The new fraction fleet. Is that going to offset those savings or the anticipate lower costs next year?
Yes, good morning, Jacob historically.
Have been moving back to pads with existing production for somewhere as low as 30%, but it's more closer to about 50% of our activity. Each year. This past quarter kind of represents some of that fluctuation of what we see quarter in and quarter out we're actually three quarters of our wells.
We executed were on pads with existing production, but I think a good way of thinking about our program year than a year out is about half of our activity would be on pads with existing production and again part of that is to complement something mark touched on a few minutes ago and that is utilization of the gathering system compression pipes.
Michael Scialla: Yeah, good morning, Michael. I think I would I would start off by, you know, some of us saying we're so super early in the process of our RFP rollout that we just deployed here over the last several weeks. So what I'm sharing with you is kind of some of those early indications in the prepared remarks this morning. I think we're going to have a lot better view once we get toward the end of the year.
And also where our processing, where we see those opportunities so moving back to those pads not only provides capital efficiency improvements, but it also translates into our ability to keep our gathering system fully utilized in our cost structure as low as possible.
Michael Scialla: We get that process wrap up and we start to communicate how that translates into our execution for our plan for 2024. So I think we'll have a lot better view at that point. The numbers in the back of the slide deck have it changed because ultimately we're still in the middle of that evaluation of that process. And once we know what our full cost structure will look like, then we'll have, you know, again, better updates.
Okay I appreciate that.
And then second question could you refresh us on where the understandings are on the Utica Devonian and maybe where you hope to be in.
Michael Scialla: You are seeing in our opinion, I'll share one final thought. You are starting to see I think a it's maybe cost of going to look differently than the traditional recount up service cost of recount down service cost down across the board. And we try to share some of that this morning in the prepared remarks because you're still seeing a high level of utilization for services as an example lights to perfect drilling rigs and also the electric fracturing fleets.
That understanding and enter 2020 for whether it's via your own pursuits or by peers in the area.
Yes.
Well when we think about the Utica I'll start off by saying, we're awfully excited about the future potential of that asset, but when we think about our inventory runway on the Marcellus. The repeatability, we've got 500 wells that we've drilled and completed we understand that the formation incredibly well.
Michael Scialla: We think that could prevent, could present some stabilization in that cost structure, maybe even some slight relief, but it'll be other areas that we may see again more relief, whether it's some of the consumables like tubular goods, or we're seeing that 30% relief for for next year and have done a job of securing that, but also in areas like diesel fuel more stabilization on the practice side as well. So we'll have better numbers for everyone at the next call, but we would expect to see some modest level of savings. It could be single digit type savings mid level. Gregory.
Again as I mentioned earlier, it's very repeatable for us and so the improvements that we've made it really kind of underpins the resilience of our business. When you think about the future of the organization and the inventory building that we have with the low breakeven that we touched on earlier our focus is clearly on the Marcellus as we go forward.
In many cases youre going to see others focus on the Utica because of potentially limitations they have either in their marcellus inventory or the quality of that inventory. They have we think we can be patient. We can sit back we can do industry surveillance wants what others are doing and then translate that into how we would advance the technical model.
Michael Scialla: Better stood, thanks. And I guess given the longer laterals, the improved cap efficiency sounds like your baseline rate is continuing to shallow, can you say where maintenance cap X or maybe if it's easier maintenance activity level would need to be next year relative to 2023? I think a way of thinking about our program for 24 in a maintenance type scenario is around $600 million. You could see that be slightly less depending upon the setup we're thinking about for 2025.
In the years that follow for the for the opportunity when we would like to pull that into the program are more of an active basis, but again, we're highly focused on the Marcellus and for obvious reasons. When you look at the costs associated with the efficiencies and on top of it just the depth and quality of inventory that we have.
Thank you I appreciate the time.
Michael Scialla: Once we start to get to February, see what kind of winter we've got, um, LNG infrastructure billed out how that's further progressing along. So I think there's several variables that we would want to take into account. But I think the way to think about our program in a maintenance area was about $600 million. And it would be around 50 to 60 wells. I think historically we would have said 60 wells kind of year in and year out. But with the advancement in our lateral links, it could be somewhere closer to 50, um, depending upon what kind of inventory we would like to carry into the setup for 2025.
Thank you Jacob.
And one moment for our next question.
Michael Scialla: Very good.
Our next question will be coming from Iran. Jairam of Jpmorgan Securities. Your line is open.
Operator: Thank you. Thanks, Michael. In one moment for our next question. Our next question will be coming from Jacob Roberts of TPH and company. Your line is open.
Yes, good morning.
I just wanted to start with maybe a housekeeping question.
Quarter guide on volumes that you've provided on the call looks to be a touch shy of the street and what we're modeling and maybe we're a little surprised just given kind of the pull forward of activity, but any drivers of that that you could you could point to.
Yes, good morning, Arun I think what I would point to is really the extended laterals that we've been completing I think if you look at Q3.
Good example is the $2 2000, 21000 foot laterals and having that maintenance level program, coupled with the gathering system that we're keeping cool. So we're just going to do is it's going to allow us to keep production flatter.
As we start to transition into Q1, if you think about the past several years and what maintenance is looked like we tend to have our highest production in the back half of the year, but then youre going to see.
Jacob Roberts: I think you touched on this in response to Doug earlier, but I'm just curious if you could remind us the percentage of activity that has been on prior pads in recent years and where you expect that percentage to shift to over the next, what they told 24 months. Yeah, good morning, Jacob. Historically, we have been moving back to pads with the existing production for, you know, somewhere as low as 30%, but it's more closer to about 50% of our activity each year.
Some decline in the first portion of the year as we start to then catch back up with that higher activity cadence in the first half that translates into the uptick in production in the back half. We think this is going to actually translate into a little bit more of a level loaded production profile as we come out of Q4 through the winter months, where we have improved pricing and then through.
Not only the first part of Q1, but then as the start of Q2, so a little bit differently, what we've seen in the past couple of years.
Jacob Roberts: This past quarter kind of represents some of that fluctuation of what we see quarter in and quarter out. We're actually three quarters of our wells that we executed where on pads with existing production. But I think a good way of thinking about our program year in and year out is about half of our activity would be on pads with existing production. And again, part of that is to compliment something marked pitched on a few minutes ago.
Helpful.
Maybe next one is for Mark Mark you are really approaching.
Your your either debt reduction or your leverage target or your gross debt target pardon me and I just wanted to see if you could kind of give us a sense of from a timing perspective, when do you expect to get there.
Jacob Roberts: And that is utilization of the gathering system, compression pipes, and also our processing where we see those opportunities. So moving back to those pads not only provides capital efficiency improvements, but it also translates in our ability to keep our gathering system fully utilized in our cost structure as low as possible.
And thoughts on cash return as we move into a better.
Part of the gas cycle.
Sure.
Tough question to answer to give them the month in which we pass it.
This target range, if I had a perfect crystal ball for the weather and the pricing. This winter, we would be able to do that but I think what youre pointing to is the fact that we are right. There on the doorstep of entering the target threshold. We think we're in a great spot already with the balance sheet and that gives us flexibility today, but even more.
Dennis Degner: Okay, appreciate that. And then the second question, can you refresh us on where the understandings are on the Utica and Devonian and maybe where you hope to be in that understanding in the 2024, whether it's via your own pursuits or by peers in the area? Well, when we think about the Utica, I'll start off by saying we're awfully excited about the future potential of that asset. But when we think about our inventory runway on the Marcellus, the repeatability, we've got 1,500 wells that we've drilled and completed, we understand that the formation incredibly well.
For flexibility, we fully expect next year to use free cash flow and redeploy it whether it's through incremental share repurchases, whether there is a modest increase in the dividend or there's other forms of reinvestment directly into the business.
That gives us additional latitude we have available under our board approved buyback program of $1 1 billion all point to our activity last year, where we repurchased $400 million in shares. This year, obviously prices came off so we backed off a little bit. So we're just balancing that reinvestment our program.
Dennis Degner: And again, as I mentioned earlier, it's very repeatable for us. And so the improvements that we've made have really kind of underpin the resilience of our business. When you think about the future of the organization and the inventory bidding that we have, the low-break evens that we touched on earlier, our focus is clearly on the Marcellus as we go forward. In many cases, you're going to see others focus on the Utica because of potentially limitations they have either in their Marcel's inventory or the quality of that inventory they have.
We intentionally shied away to date from giving a formulaic approach, we like the optionality of being able to take advantage of opportunities in the market to reinvest at opportune times. So just to give extreme examples if we saw a huge pullback in the stock.
Dennis Degner: We think we can be patient, we can sit back, we can do industry surveillance, watch what others are doing, and then translate that into how we would advance the technical model in the years that follow for the opportunity when we would like to pull that into the program and have a more of an active basis. But again, we're highly focused on the Marcellus and for obvious reasons when you look at the costs associated with it, the efficiencies, and on top of it, just the depth and quality of the inventory that we have.
Arun Jayaram: Thank you. Appreciate the time. Thanks, Jacob. In one moment for our next question. Our next question will be coming from Arun Jayaram of J.P.
We would consider hard whether it's time to put more of our cash flow sooner rather than later back into the buyback program.
Alternatively prices are soft will remain conservative and focus on the balance sheet. So we're so close to that target.
Alex sheet range that we like the flexibility to get today and I'll just highlight again and I think that gives us even greater latitude as we get into 2024 and after.
Sure.
Thanks, Mark for the thoughtful response toxin.
Thank you.
Thank you and that will be our last question. This concludes today's question and answer session I would like to turn the call back over to Mr. Degner for his concluding remarks.
We'd like to say thanks for everyone joining us on the call. This morning. If you have any follow up questions. Please don't hesitate to follow up with the Investor Relations team. Thank you.
Thank you for your participation in today's conference you may now disconnect.
Arun Jayaram: Morgan's Security. Do you line it open?
Dennis Degner: Yeah, good morning. Douglas wanted to start with maybe a housekeeping question. The fourth quarter guide on volumes that you provided on the call, look at the touch shy of the street and what we're modeling. And maybe we're a little surprised as given kind of the pull forward of activity. But any drivers of that that you could point to?
[music].
Okay.
Yes.
[music].
Yes.
Arun Jayaram: Yeah, good morning, Arun. I think what I would point to is really the extended laterals that we've been completing. I think if you look at Q3, good example is the 220, 21,000 foot laterals and having that maintenance level program coupled with a gathering system that we're keeping hold. So what it's going to do is it's going to allow us to keep production flatter as we start to transition into Q1. If you think about the past several years and what maintenance has looked like, we tend to have our highest production in the back half of the year.
Yes.
Okay.
Okay.
Okay.
[music].
Yes.
Yes.
Okay.
Yes.
[music].
Okay.
[music].
Okay.
[music].
Sure.
Arun Jayaram: But things you're going to see some decline in the first portion of the year as we start to then catch back up with that higher activity cadence in the first half that translates into the uppicking production in the back half. We think this is going to actually translate into a little bit more of a level loaded production profile as we come out of Q4 through the winter mides where we have improved pricing and then through not only the first part of Q1, but then it's the start of Q2. It's a little bit different from what we've seen in the past couple of years. That's helpful.
Okay.
Sure.
<unk>.
Okay.
Sure.
[music].
So.
Okay.
[music].
Mark Scucchi: Maybe next one is for Mark. Mark, you're really approaching your debt reduction or your leverage target or your gross debt target pardon me. I just wanted to see if you could kind of give us the sense of from a timing perspective when you expect to get there and thoughts on cash return as we move and do a better part of the gas cycle.
Okay.
Okay.
Okay.
[music].
Yes.
Okay.
Okay.
[music].
Yes.
[music].
Mark Scucchi: Sure. That's a tough question to answer to give the months and which we pass into the target range. If I had a perfect crystal ball for the weather and the pricing this winter, we'd be able to do that. But I think what you're pointing to is the fact that we are right there on the doorstep of entering the target threshold. We think we're in a great spot already with the balance sheet and that gives us flexibility today.
Yes.
[music].
Yes.
Yes.
Yes.
Okay.
Okay.
Okay.
Okay.
Mark Scucchi: But even more flexibility, we fully expect next year to use free cash flow and redeploy it, whether it's through incremental sharey purchases, whether there's a modest increase in the dividend, whether there's other forms of reinvestment directly into the business that that gives us additional latitude. We have available and report approved buyback program 1.1 billion. I'll point to our activity last year where we repurchased $400 million in shares. This year obviously prices came off, so we backed off a little bit.
Okay.
Yes.
Okay.
Yes.
Yes.
Okay.
Okay.
Sure.
Yes.
Okay.
Mark Scucchi: So we're just balancing that reinvestment. Our program, we intentionally shied away today from giving a formulaic approach. We like the optionality of being able to take advantage of opportunities in the market to reinvest it in opportune times. They're just to give extreme examples. If we saw a huge pullback in a stock, we would consider hard whether it's time to put more of our cash flow sooner rather than later back into the buyback program.
Okay.
Okay.
[music].
Yes.
Yes.
Okay.
[music].
Okay.
Sure.
Okay.
Okay.
Mark Scucchi: Alternatively, prices are soft. We'll remain conservative and focus on the balance sheet. So we're so close to that target balance sheet range that we like the flexibility to get today, and I'll just highlight again that I think that gives us even greater latitude as we get into 2024 in it.
Okay.
[music].
Yes.
Okay.
Okay.
[music].
Yes.
[music].
Arun Jayaram: Doctor. Thanks, Mark, for the thoughtful response, Tuxen. Thank you.
Yes.
Okay.
Yes.
Yes.
Okay.
Okay.
Okay.
Okay.
Okay.
Okay.
Yes.
Okay.
Yes.
Okay.
Okay.
Helpful.
Yes.
Okay.
Okay.
Okay.
Yes.
Okay.
[music].
Okay.
Yes.
Okay.
[music].
Sure.
Okay.
Okay.
[music].
Thank you.
Yes.
Sure.
Okay.
Yes.
Okay.
Okay.
Okay.
Okay.
Yes.
Okay.
Okay.
Sure.
Yes.
[music].
Okay.
Okay.
Yes.
Okay.
Yeah.
Yes.
Yes.
Yes.
Okay.
Yes.
Yes.
Okay.
Okay.
Okay.
Okay.
Yes.
Okay.
Okay.
Okay.
Okay.
Okay.
Okay.
Okay.
Okay.
[music].
Okay.
Okay.
Okay.
Okay.
Okay.
Yes.
Okay.
Okay.
Okay.
Yes.
Yes.
Sure.
Yes.
Okay.
Welcome to the range resources third quarter 2023 earnings conference call. All lines have been placed on mute to prevent any background noise statements made during this conference call that are not historical facts are forward looking statements such statements are subject to risks and uncertainties, which could cause actual results to differ materially from those in forward looking statements.
After the Speakers' remarks, there will be a question and answer period at this time I would like to turn the call over to Mr. Laith Sando, Vice President Investor Relations at range Resources. Please go ahead Sir.
Thank you operator.
Morning, everyone and thank you for joining our ranges third quarter earnings call.
Speakers on today's call are Dennis Degner, Chief Executive Officer, and Mark <unk>, Chief Financial Officer.
Hopefully you've had a chance to review the press release and updated Investor presentation that we've posted on our website.
We may reference certain of those slides on the call. This morning.
You will also find our 10-Q on ranges website under the investors tab.
You can access it using the Sec's Edgar system.
Please note, we'll be referencing certain non-GAAP measures on today's call. Our press release provides reconciliations of these to the most comparable GAAP figures.
We've also posted supplemental tables on our website.
That includes realized pricing details by product along with calculations of EBITDAX cash margins and other non-GAAP measures.
With that let me turn the call over to Dennis.
Thanks, Laith and thanks to all of you for joining the call today.
As we finish out our 2023 program ranges business plan is on track and we're making steady progress on the following key objectives. We've shared with you throughout this year.
Operating safely while driving continued operational improvements.
Generating free cash flow through the cycles, where the peer leading full cycle cost structure.
And prudent allocation of that free cash flow balancing our strong balance sheet with returns of capital to shareholders and the long term development of our world class asset base.
I believe our most recent quarters are a great example of consistent advancement against these objectives.
And the results reflect the resilience and durability of <unk> business.
During the third quarter, we successfully delivered on our operational plan safely with peer leading efficiencies.
And ranges competitive cost structure.
Low capital intensity liquids, optionality and thoughtful hedging allowed us to generated healthy full cycle margins, despite a lower commodity price environment.
These results are underpinned by ranges multi decade inventory and brought to fruition by a talented technical team that continues to innovate.
Walking through some of our quarterly results.
All in capital for the third quarter came in at $151 million with your year to date capital spending totaling $478 million or approximately 80% of our annual plan.
This frontloaded capital spending is right on track and follows the activity cadence we outlined earlier this year.
As previously discussed we ran two frac crews for most of the third quarter, which aligns with our back half way to turn in line count and production trajectory.
The second spot crew was released in early Q4 and as of today, we're back down to one dedicated horizontal rig and one data <unk> frac crew as planned.
Production for the quarter came in at 212 Bcf equivalent per day.
Adding an average of approximately 40 million cubic feet equivalent per day versus the prior quarter.
And placing us on track for a fourth quarter production increase that aligns favorably with the current shape of the forward commodity curve.
Supporting our production profile, we turned to sales 19 wells during the third quarter.
Operator: Thank you, and that will be our last question.
13 of these wells are located in our dry acreage position, but the other six located in our wet and Super rich acreage all in southwest Pennsylvania.
As has become a hallmark of our operations over three quarters of the wells are located on pads with existing production.
Minimizing our operating surface footprint.
Supporting nimble operations and driving ranges cost efficient development approach and peer leading capital efficiency.
Operator: This concludes today's question and answer session.
Looking at operations.
Just under 1100 Frac stages were completed on 18 wells during the quarter and southwest and northeast, Pennsylvania.
Dennis Degner: I would like to turn the call back over to Mr. Degner for his concluding remarks.
Demonstrating a continuation of our operational efficiencies, we averaged over nine frac stages per day for the quarter.
Representing a 17% increase versus the same time period in 2022.
Our second spot Frac fleet was utilized during the quarter and completed a return trip to an existing producing pad in our northeastern Pennsylvania acreage.
Adding three new wells to the pad site.
Consistent with what we've seen this year in southwest PA.
Our completion metrics for this pad improved dramatically versus our initial development.
This was accomplished through our continual learnings and improvements, which drive ranges best practices and logistics planning.
Laith Sando: I'd like to say thanks for everyone joining us on the call this morning. If you have any follow-up questions, please don't hesitate to follow up with the investor relationship.
Water operations optimization and service partner Kpis.
Operator: Thank you. Thank you for your participation in today's conference.
Altogether. This resulted in an increased number of frac stages per day.
Our reduced cycle time to complete this pad site and drove an 80% improvement in overall completions efficiency.
Operator: You may now disconnect.
Operator: Dr. Paret, Dr. Paret, Dr. Degner, Dr. Degner, Dr. Paret[inaudible] .
Also during the quarter range successfully completed two of the longest laterals and ranges Marcellus program history.
But both lateral lengths exceeding 21000 feet.
And when factoring in the total drill footage from surface to the end of the lateral that total distance exceeded five five miles per well.
Operator: Welcome to the Range Resources 3rd Quarter 2023 Earnings Conference Call. All lines have been placed on you to prevent any background noise. Statements made during this conference call that are not historical facts are forward-looking statements. Such statements are subject to risk and uncertainties which could cause actual results to differ materially from those in forward-looking statements. After the speakers remarks, there will be a question and answer period.
As a result of the team's success in increasing lateral lengths in the 2023 program, we're able to complete this year's program with fewer turn in lines than originally planned.
Laith Sando: At this time, I would like to turn the call over to Mr. Laith Sando, Vice President, and Vester Relations at Range Resources. Please go ahead, sir. Thank you, operator. Good morning, everyone, and thank you for joining Range's 3rd Quarter Earnings Call. The speakers on today's call are Dennis Dagner, Chief Executive Officer, and Mark Skooky, Chief Financial Officer. Hopefully you've had a chance to review the press release and updated investor presentation that we've posted on our website.
We still plan to turn to sales approximately 650000 lateral feet. However, we will be doing this with 51 wells turned to sales or 16% fewer than what we had planned at the start of the year.
This will drive a <unk> production increase of approximately 40 to 60 million cubic feet equivalent per day over the third quarter and given the flatter production profile of these long laterals. It sets us up well heading into early 2024 and to what we expect will be improved pricing.
Laith Sando: We may reference certain of those slides on the call this morning. You'll also find our 10Q on Range's website under the Investors tab, or you can access it using the SEC's Edgar system. Please note, we'll be referencing certain non-gap measures on today's call. Our press release provides reconciliations of these to the most comparable gap figures. We've also posted supplemental tables on our website that includes realized pricing details by product along with calculations of evidence, cash margins, and other non-gap measures.
Dennis Degner: With that, let me turn the call over to Dennis. Thanks, Laith, and thanks to all of you for joining the call today. As we finish out our 2023 program, Range's business plan is on track, and we're making steady progress on the following key objectives we've shared with you throughout this year. Operating safely while driving continued operational improvements. Generating free cash flow through the cycles with the pure leading full cycle constructs, and Prudent Allocation of that pre-cash flow, balancing a strong balance sheet with returns of capital to shareholders, and the long-term development of our world-class asset base.
I congratulate our team on this tremendous accomplishment as we continue to advance efficient long lateral development for rages assets.
Of course record completion efficiencies aren't possible without an integrated water operations and logistics group.
Dennis Degner: I believe our most recent quarters are a great example of consistent advancement against these objectives, and the results reflect the resilience and durability of range's business. During the third quarter, we successfully delivered our operational plan safely with peer-leading efficiencies, and range's competitive cost structure, low capital intensity, liquids optionality, and thoughtful hedging allowed us to generate healthy, full-cycle margins, despite a lower commodity price environment. These results are underpinned by range's multi-decade inventory and brought through fruition by a talented technical team that continues to innovate.
In the third quarter. The team continued to build upon rages ongoing water recycling effort through strategic partnerships with other producers and third party treating facilities, resulting in water savings of over $2 $4 million in Q3.
Dennis Degner: Walking through some of our quarterly results, all in capital for the third quarter came in at $151 million, with year-to-day capital spending totaling $478 million, or approximately 80% of our annual plan. This front-loaded capital spending is right on track, and follows the activity cadence we outlined earlier this year. As previously discussed, we ran two frat crews for most of the third quarter, which aligns with our back half-weighted turn-in line count and production trajectory.
Dennis Degner: The second spot crew was released in early Q4, and as of today, we're back down to one dedicated horizontal rig and one dedicated frat crew as planned. Production for the quarter came in at 2.12 BCF equivalent per day, adding an average of approximately 40 million cubic feet equivalent per day versus the prior quarter, and placing us on track for a fourth quarter production increase that aligns favorably with the current shape of the forward commodity curve.
As mentioned earlier the team operated in both our southwestern and northeastern PA acreage during the quarter.
Even while concurrent operations were being performed over 200 miles apart the team maximize efficiencies across these jobs to achieve our highest recorded water volume delivered in over five years by moving over 200000 barrels of water on multiple days, while establishing a new range record of handling over <unk>.
800000 barrels and four days.
Dennis Degner: Supporting our production profile, we turned to sales 19 wells during the third quarter. 13 of these wells are located in our dry acreage position, with the other six located in our wet and super-rich acreage, all in southwest Pennsylvania. As has become a hallmark of our operations, over three quarters of the wells are located on paths with existing production, minimizing our operating surface footprint, supporting nimble operations, and driving ranges cost efficient development approach and peer leading capital efficiency.
This is an outstanding achievement and demonstrates the team's focus on peer leading capital efficiency and supports our overall financial results that Mark will touch on in just a moment.
Before moving back to marketing I want to touch briefly on service cost.
We recently launched our annual RFP process for services needed in 2024.
The process is in the initial phases, but early indications suggest prices are softening for certain services and consumables versus the start of 2023.
Most notably we have seen a reduction in tubular goods pricing this year.
Dennis Degner: Looking at operations, just under 1,100 frat stages were completed on 18 wells during the quarter in southwest and northeast Pennsylvania. Demonstrating a continuation of our operational efficiencies, we averaged over nine frat stages per day for the quarter, representing a 17% increase versus the same time period in 2022. A second spot frat fleet was utilized during the quarter, and completed a return trip to an existing producing pad in our northeastern Pennsylvania acreage.
And as a result, we've locked in steel pricing for our 2020 for a program at approximately a 30% discount to what we saw in 2023.
For sand, we've seen similar signs of cost reduction and anticipate those savings could remain in place throughout 2024.
Other consumables like diesel fuel have moved higher and could remain elevated for next year.
While we have a natural hedge against diesel prices with our condensate production, we've secured pricing for a portion of our 2024 development plan further mitigating pricing risk.
Dennis Degner: Ridge, adding three new wells to the pad site. Consistent with what we've seen this year in Southwest PA, our completion metrics for this pad improved dramatically versus our initial development. This was accomplished through our continual learnings and improvements which drive range as best practices in logistics planning, water operations optimization, and service partner KPIs. All together, this resulted in an increased number of frag stages per day, a reduced cycle time to complete this pad site, and drove an 80% improvement in overall completion sufficiency.
Similar to our 2023 development program range will continue to utilize a super spec drilling rig and an electric Frac fleet in 2024.
Day rates for rigs and 24, showing signs of decline versus peak levels seen over the past 12 months.
Certainly influenced by the current U S rig count.
But super spec rigs remain in high demand.
Similarly for completions electric Frac fleets are operating at a high level of utilization, resulting.
Dennis Degner: Also during the quarter, range successfully completed two of the longest laterals in Ranges, Marcella's program history, with both lateral links succeeding 21,000 feet. And when factoring in the total drill footage from surface to the end of the lateral, the total distance succeeded five and a half miles per well. As a result of the team's success in increasing lateral links in the 2023 program, we were able to complete this year's program with fewer turning lines than a regionally planned.
Resulting in comparable year over year pricing. Despite this year's overall rig count reduction across the U S.
To secure this portion of our program ranges contracted an electric fleet for two years that is scheduled to commence operations on January one 2024.
In aggregate, we anticipate RFP process will generate a modest year over year cost savings across various services.
We will have the numbers formalized by year end and at the end of the day, we fully expect to remain at the leading edge of capital efficiency, when compared to our peers and other basins.
Dennis Degner: We still plan to turn to sales approximately 650,000 lateral feet. However, we will be doing this with 51 wells turned to sales, or 16% fewer than what we had planned at the start of the year. This will drive a 4-q production increase of approximately 40 to 60 million cubic feet equivalent per day over the third quarter. And given the flatter production profile of these long laterals, it sets us up well heading into early 2024.
We look forward to sharing our 2024 plans with you on the next call.
Turning to the NGL macro and pricing.
Third quarter saw prices increase across the board for both Ngls and condensate.
Overall liquids pricing was supported by upward trending crude values and lifted further by strengthening supply demand fundamentals for Ngls.
Dennis Degner: And to what we expect will be improved pricing. I congratulate our team on this tremendous accomplishment, as we continue to advance efficient, long lateral development for Ranges assets. Of course, record completion efficiencies aren't possible without an integrated water operations and logistics group. In the third quarter, the team continue to build upon Ranges ongoing water recycling effort through strategic partnerships with other producers and third party treating facilities resulting in water savings of over $2.4 million in Q3.
Anthony fundamentals strengthen on increased domestic demand and third quarter exports that were up 19% year on year.
While LPG balances improved on stronger domestic propane demand and exports and increased 16% versus the prior year's quarter.
At the same time third quarter global LPG balances tightened 14% year on year.
As a result of improving NGL fundamentals range was able to realize $24 44 per barrel in the third quarter.
A 14% increase over the prior quarter.
Dennis Degner: As mentioned earlier, the team operated in both our southwestern and northeastern PA acreage during the quarter. Even while concurrent operations were being performed over 200 miles apart, the team maximized efficiencies across these jobs to achieve our highest recorded water volume delivered in over five years by moving over 200,000 barrels of water on multiple days, while establishing a new range record of handling over 800,000 barrels in four days. This is an outstanding achievement and demonstrates the team's focus on peer leading capital efficiency and supports our overall financial results that Mark will touch on in just a moment.
This realized price represents a 63 per barrel uplift versus the Mont Belvieu index.
Reflecting ranges advantaged portfolio of NGL contracts.
And access to international markets.
And as a reminder, each $1 per barrel increase in ranges NGL per barrel price represents $30 million in incremental cash flow generated.
As we enter the winter months, we expect fundamentals to remain strong and our NGL price realizations to remain in the $1 minus to $1 per barrel premium for the fourth quarter <unk>.
Generation of strong premium to Mont Belvieu for the year.
Dennis Degner: Before moving back to marketing, I want to touch briefly on service cost. We recently launched our annual RFP process for services needed in 2024. The process is in the initial phases, but early indications suggest prices are softening for certain services and consumables versus the start of 2023. Green. Most notably, we've seen a reduction in tubular goods pricing this year. And as a result we've locked in steel pricing for our 2024 program at approximately a 30% discount to what we saw in 2023.
On the natural gas front incremental gas demand for power generation, we touched on during the last quarter proved resilient in the months that followed as the summer expired.
This incremental power demand, coupled with industrial demand growth exports to Mexico and continued LNG commissioning.
It's the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rig activity reductions we've seen in the haynesville.
To follow we then see further strengthening with increased LNG exports next year.
Dennis Degner: For sand, we've seen similar signs of cost reduction and anticipate those savings could remain in place throughout 2024. Other consumables like diesel fuel have moved higher and could remain elevated for next year. While we have a natural hedge against diesel prices with our condensate production, we've secured pricing for a portion of our 2024 development plan for their mitigating pricing risk. Similar to our 2023 development program, Range will continue to utilize a super-spec drilling rig and an electric frat fleet in 2024.
And beyond.
We are excited about the future of natural gas and Ngls, but regardless of the macro backdrop.
Team remains focused on advancing our overall efficiencies.
Delivering repeatable well performance across our large contiguous inventory.
While bolstering our strong balance sheet with returns of capital to shareholders.
These are the building blocks that underpins the resilience of ranges business through the cycles and I believe the positive results. We've seen year to date are a reflection of that.
I'll now turn it over to Mark to discuss the financials.
Thanks Dennis.
Dennis Degner: Day rates for rigs in 2024 are showing signs of decline versus peak level seen over the past 12 months. Certainly influenced by the current US rig count. But super-spec rigs remain in high demand. Similarly for completions, electric frat fleets are operating at a high level of utilization, resulting in comparable year-over-year pricing despite this year's overall rig count reduction across the US. To secure this portion of our program, Range is contracted an electric fleet for two years that is scheduled to commence operations on January 1, 2024.
As we turn to the financial results I think some context is helpful to frame upstream companies results in relation to the macroeconomic backdrop.
During the first nine months of 2023, Nymex natural gas prices averaged $2 71 per Mcf.
Compared to $6 77 for the same period of 2022.
<unk> oil prices were roughly $77 per barrel in the first nine months of 2023 compared to $98 in 2022.
These price declines have led to our natural gas focused rig count drop of 27% since April with U S natural gas production now stabilizing.
Dennis Degner: In aggregate, we anticipate our RFP process will generate a modest year-over-year cost savings across various services. We'll have the numbers formalized by year end. And at the end of the day, we fully expect to remain at the leading edge of capital efficiency when compared to our peers and other basins.
The read through is it prices experienced year to date are below maintenance levels at least for marginal producers.
With a market that is at low tide when troops are revealed hopefully the investor task of comparing upstream companies is a bit easier.
Dennis Degner: We look forward to sharing our 2024 plans with you on the next call.
Lower prices highlight the quality of assets.
Mark Scucchi: Turning to the NGL macro and pricing, the third quarter-solve prices increase across the board for both NGLs and compensate. Overall, liquids pricing was supported by upward-training crude values and lifted further by strengthening supply-demand fundamentals for NGLs. Ethane fundamentals strengthen on the increased domestic demand and third quarter exports that were up 19 percent year-on-year, while LPG balances improved on stronger domestic propane demand and exports that increased 16 percent versus the prior year's quarter.
The durability of business model and identify those that not only survive, but thrive through cycles.
Despite commodity prices experienced in 2023 range is having a successful year focused on creating value today, while also positioning the company for long term value creation.
What does that mean.
It means range has reduced debt and paid cash dividends, while fully funding our capital reinvestment program that efficiently sustained production. While also positioning the company for the long term as a responsible reliable supplier to growing global demand for U S natural gas.
Mark Scucchi: At the same time, third quarter global LPG balances tightened 14 percent year-on-year. As a result of improving NGL fundamentals, range was able to realize $24.44 per barrel in the third quarter, a 14 percent increase over the prior quarter. This realized price represents a 63 cents per barrel uplift versus the Montville view index, reflecting range's advantage portfolio of NGL contracts and access to international markets. And as a reminder, each $1 per barrel increase in range's NGL per barrel price represents $30 million in incremental cash flow As we enter the winter months, we expect fundamentals to remain strong and our NGO price realizations to remain in the $1- to $1 per barrel premium for the fourth quarter, generating a strong premium to Mont Bellevue for the year.
Putting ranges success in numbers.
Third quarter analyst cash flow totaled $240 million funding $151 million in capital investments.
And the $19 million quarterly dividend.
While maintaining balance sheet strength.
Cash flow was driven by strong production.
Achieving pre Nymex <unk>.
<unk> realization of $2 79 per Mcf during the third quarter.
This realized unit prices 24 above Nymex Henry hub, demonstrating the value of ranges diverse sales outlets for natural gas and the pricing uplift from natural gas liquids and condensate.
During the third quarter ranges realized NGL price was $24 44 per barrel or $4 seven on an mcf equivalent basis.
<unk> portfolio of transportation capacity and customer contracts supported differentials delivering roughly 80% of natural gas out of basin.
Mark Scucchi: On the natural gas front, incremental gas demand for power generation we touched on during the last quarter proved resilient in the months that followed as the summer expired. This incremental power demand coupled with industrial demand growth, exports to Mexico, and continued LNG commissioning sets the tone for the domestic natural gas market to gradually rebalance, particularly when considering the meaningful rigout activity reductions we've seen in the field. To follow, we then see further strengthening with increased LNG exports next year and beyond.
Virtually all natural gas liquids out of basin.
Generating roughly 90% of revenues from diverse growing premium markets.
In addition, <unk>.
<unk> approach to hedging provide additional support to per unit realizations for hedged realized price of $3 nine per Mcf.
Hedged cash margin per unit of production with a resilient $1 23.
Benefiting from our persistent focus on efficiency and the right way risk of certain price linked to call.
Total cash unit costs improved by 29.
Mark Scucchi: We are excited about the future of natural gas and NGOs, but regardless of the macro backdrop, the team remains focused on advancing our overall efficiencies, delivering repeatable well performance across our large, continuous inventory, while bolstering a strong balance sheet with returns of capital to shareholders. These are the building blocks that underpin the resilience of a range of business through the cycles, and I believe the positive results we've seen year-to-date are a reflection of that.
Versus third quarter last year.
The change from prior year, primarily relates to savings and processing fuel and power costs.
Related to NGL and natural gas prices.
And demonstrate the resilience full cycle cost structure of ranges business.
Cash interest expense declined by $8 million for the quarter compared to Q3 last year on reduced debt balances.
Ranges financial hedging program supported realized prices for the third quarter with approximately $59 million in Nymex related gains.
Mark Scucchi: I'll now turn it over to Martin to discuss the financials. Thanks, Dennis. As we turn to the financial results, I think some context is helpful to frame upstream companies' results in relation to the macroeconomic backdrop. During the first nine months of 2023, 9x natural gas prices averaged $2.71 per MCF compared to $6.77 for the same period of 2022. WTI oil prices were roughly $77 per barrel in the first nine months of 2023 compared to $98 in 2022.
Looking forward range is natural gas is approximately 50% hedged for the balance of 2023 with an average $3 40 <unk> floor.
Providing continued confidence and range of free cash flow profile.
For 2024, we have hedged approximately 50% of natural gas at an average floor price of $3 68.
Using a combination of $4 swaps and.
And colors, retaining upside to roughly $5 30.
Our modest 2025 hedge position on natural gas with an average price of $4 12 did.
Mark Scucchi: These price declines have led to a natural gas-focused rig count drop of 27 percent since April, with new U.S, natural gas production now stabilizing. The re-true is that prices' experience year-to-date are below maintenance levels, at least for marginal producers. With a market that is at low tide when truths are revealed, hopefully the investor task of comparing upstream companies is a bit easier. Lower prices highlight the quality of assets, the durability of business models, and identify those that not only survive, but thrive through cycles.
It did not materially change quarter over quarter.
The objective of this program is essentially to cover fixed costs at attractive levels, enabling consistent free cash flow, while maintaining exposure to a market poised we expect to positively respond to new LNG facilities coming online alongside rising domestic demand with U S natural.
Gas supply flattening as a result of significantly reduced industry activity.
Turning to the balance sheet.
At the end of Q3, we held cash balances of $163 million.
Mark Scucchi: Despite commodity prices' experience in 2023, range is having a successful year focused on creating value today while also positioning the company for long-term value creation. What does that mean? It means range has reduced debt and paid cash dividends while fully funding a capital reinvestment program that efficiently sustains production will also positioning the company for the long-term as a responsible, reliable supplier to growing global demand for U.S, natural gas, of Gas, Putting Ranges Success in Numbers, Third Quarter Analyst, Cash Flow, Total $240 million, Funding $151 million in Capital Investments, and the $19 million quarterly dividend, while maintaining balance sheet strength.
Which is essentially unchanged from last quarter.
We will continue to manage our cash balance.
To retain flexibility for efficient working capital management bond redemption and share repurchases.
This cash balance combined with future free cash flow and $1 2 billion available on our Undrawn revolving credit facility provide ample liquidity to efficiently operate our business and take advantage of opportunities the market may present.
We've been focused on a target capital structure for several years and as of quarter end, we have reduced debt net of cash by roughly $2 5 billion.
It peaked in 2018.
This places us very close to our target range of one to $1 5 billion and net debt.
Mark Scucchi: Cash Flow was driven by strong, productive, achieving pre-NIMEX hedge realization of $2.79 per MCFE during the third quarter. This realized unit price is $0.24 above NIMEX Henry Hub, demonstrating the value of Ranges' diverse sales outlets for natural gas, and the pricing uplift from natural gas liquids and condensate. During the third quarter, Ranges realized NGL price was $24.44 per barrel, or $4.07 on an NCS equivalent basis. Ranges portfolio of transportation capacity and customer contracts supported differentials, delivering roughly 80% of natural gas out of basin, virtually all natural gas liquids out of basin, generating roughly 90% of revenues from diverse, growing, premium markets.
With current leverage of roughly one times debt to EBITDAX.
In close proximity to our balance sheet targets. We believe the company is in great shape to continue value creation on a stable financial base throughout the business cycle.
Successful results this year combined with a positive industry backdrop for range going forward support our confidence in the return of capital program discussed on previous calls.
We believe a reliable fixed cash dividend is appropriate at this time and in this market while remaining opportunistic in our share repurchases with capacity available totaling $1 1 billion.
As we look to 2024 with an expected even stronger balance sheet, we will be in a position to evaluate the size and speed at which we deploy free cash flow.
We believe that will provide greater flexibility around our capital allocation priorities of balance sheet strength returns of capital and growth at an appropriate time.
Mark Scucchi: In addition, Ranges' approach to hedging provide additional support to per unit realizations for a hedged realized price of $3.9 per MCFE. Hedged cash margin for unit of production was a resilient $1.23 benefiting from a persistent focus on efficiency and the right way risk of certain price-linked costs. Total cash unit costs improved by $0.29 versus third quarter last year. The change from prior year primarily relates to savings in processing, fuel, and power costs, which are related to NGL and natural gas prices, and demonstrate the resilient full-cycle cost structure of Ranges' business.
Fundamentally we will prioritize financial strength.
And remain responsive to market conditions project returns.
And prudent reinvestment.
In a commodity business prices will fluctuate design.
Designing a business to be successful in both high prices and lower prices is challenging it requires.
Quality assets and a creative dedicated disciplined team.
The range team across every facet of the business.
And act like owners of the business.
Striving to make the best decisions.
For the safest cleanest and most economic results.
A few commonly used words apply to our story.
Mark Scucchi: Cash interest expense declined by $8 million for the quarter, compared to Q3 last year on reduced debt balances. Ranges' financial hedging program supported realized prices for the third quarter with approximately $59 million in NIMEX-related gains. Looking forward, Ranges' natural gas is approximately 50% hedged for the balance of 2023 with an average $3.40 floor providing continued confidence in Ranges' free cash flow profile. For 2024, we have hedged approximately 50% of natural gas at an average $4 price of $3.68 using a combination of $4 swaps and collars retaining upside to roughly $5.30.
Unique differentiated peer leading.
Other superlative.
Instead, I'll point to the data.
Low base decline.
Lower full cycle cost structure.
Larger quality acreage position.
And more than a decade of positive performance revisions of proved reserves.
Combination that we believe creates an E&P company built for the long haul.
With a strong financial foundation, and our largest portfolio of quality inventory in Appalachia.
Paired with transportation to delivery points across key U S and international markets. We seek to continue this trend of disciplined value creation for our shareholders.
Dennis back to you.
Thanks Mark.
Before moving to Q&A I'll reiterate a message we've shared previously that is as important today as ever given the current world events.
Mark Scucchi: A modest 2025 hedge position on natural gas with an average price of $4.12 did not materially change quarter of a quarter. The objectives of this program is essentially to cover fixed costs at attractive levels enabling consistent free cash flow while maintaining exposure to a market poised we expect to positively respond to new LNG facilities coming online alongside rising domestic demand with US natural gas supply flattening as a result of significantly reduced industry action.
As the world continues to move towards cleaner more efficient fuels natural gas and Ngls will be the affordable reliable and abundant supply that helps power our everyday lives. While also helping billions of others improve their standard of living.
We believe Appalachian natural gas and natural gas liquids are positioned to meet that future demand.
And within the Appalachian Basin range has de risked a large inventory of high quality wells across our $5 million net acre position and translated that into a business capable of generating free cash flow through commodity cycles.
Mark Scucchi: Activity. Turning to the biology, the end of Q3, we held cash balances of $163 million, which is essentially unchanged from last quarter. We will continue to manage our cash balance to retain flexibility for efficient working capital management, bond redemption, and share on revolving credit facility, provide ample liquidity to efficiently operate our business and take advantage of opportunities the market may present. We've been focused on a target capital structure for several years, and as a quarter end, we have reduced debt net of cash by roughly $2.5 billion, since its peak in 2018.
All while leading the way on capital efficiency emissions intensity and transparency.
With that we'll open the line for questions.
Thank you Mr. Degner the question and answer session will now begin if you would like to ask a question. Please indicate by pressing the star key Dan One line.
If youre using a speakerphone please pick up your handset before asking your question. If you would like to withdraw. Your question you may do so by pressing star one again.
Once again, please press star one to ask a question in one moment for our first question.
Our first question will be coming from Scott Hanold of RBC capital markets. Your line is open.
Mark Scucchi: This places us very close to our target range of one to one and a half billion dollars in net debt. With current leverage of roughly one times debt to EBDAX and close proximity to our balance sheet targets, we believe the company is in great shape to continue value creation on a stable financial base throughout the business cycle. Successful results this year combined with a positive industry backdrop for range going forward, support our confidence and the return of capital program discussed on previous calls.
Yes, thanks, good morning.
I thought it was pretty interesting.
Ability for you guys to reduce the well counts so dramatically this year with the longer laterals.
Can you give us some color and context around the overall capital efficiency, what do you think like.
On an annual basis, you could save with drilling less top holes and how does that manifest into or how are you.
And when does that manifest into stronger free cash flow.
Mark Scucchi: We believe a reliable, fixed cash dividend is appropriate at this time and in this market, while remaining opportunistic and our share repurchases with capacity available totaling $1.1 billion. As we look to 2024 with an expected even stronger balance sheet, we will be in a position to evaluate the size and speed at which we deploy free cash flow. We believe that will provide greater flexibility around our capital allocation priorities of balance sheet strengths, returns of capital, and growth at an appropriate time.
Yes, good morning, Scott I'll start and this may be something that Mark and I both tag team.
Across this this discussion here, but.
When you look over the past several years I will take about a half step back first year over year, we continue to see the team demonstrates the ability to advance our efficiencies and what thats transitions into is the ability to drill longer laterals. I think you heard us talk about it not only in today, but in some of the prior quarters were not alone.
We will be drilling our longest laterals, but our fastest stays where we saw an improvement at the mid year point of a 40% improvement in our drilling efficiencies just to the first half of the year versus 2020 two's full year average.
Mark Scucchi: Fundamentally, we will prioritize financial strengths and remain responsive to market conditions, project returns, and prudent reinvestment. In a commodity business, prices will fluctuate, designing a business to be successful in both high prices and lower prices is challenging. It requires quality assets and a creative, dedicated, disciplined team. The range team across every facet of the business think and act like owners of the business, striving to make the best decisions for the safest, cleanest, and most economic results.
Completions is seeing the same thing.
You've seen approximately a 20% to 25% improvement in completion efficiencies this year versus last year. Some of this with procedures rooting out nonproductive time, and then having the ability to reduce overall cycle time as you.
Basically execute these pad sites. So it's a multi variable type of assessment. When you start to then translate that into our capital efficiency.
If you just do a spreadsheet exercise and you compare on a 10000 foot program with 61 laterals like we originally communicated to something more like we're seeing today for the year. It really changes our capital efficiency by as much as 15% to $20 per foot so pretty exciting about when you think about it from that perspective, but what that also.
Mark Scucchi: A few commonly used words apply to our story, unique, differentiated, peer leading among other superlatives. Instead, I'll point to the data, low-based client, low-full-fleckle-cost structure, largest quality acreage position, and more than a decade of positive performance revisions of proved reserves, a combination that we believe creates an ENP company built for the long haul. With a strong financial foundation and the largest portfolio of quality inventory in Appalachia, paired with transportation delivery points across key US and international markets, we seek to continue this trend, the discipline value creation for our... Chairholders. Dennis, back to you. Thanks, Mark.
So does at the same time is it pulls activity that would have been executed in let's just say the first half of Q1 has the ability to pull that into the back half of Q4, and so when you think about our guidance that we provided early on this year from a capital window perspective, and we're looking at both land and other aspects to this part of.
That was us looking forward and anticipating some of these capital are these operational efficiency improvements and what that could set us up for in 2020 for having these longer laterals is going to present, a flatter production profile that carries into the early part of 2024, So we really like the setup and seeing how.
Dennis Degner: Before moving to Q&A, I'll reiterate a message we've shared previously that it is as important today as ever given the current world events. As the world continues to move towards cleaner, more efficient fuels, natural gas and NGOs will be the affordable, reliable, and a abundant supply that helps power our everyday lives, while also helping billions of others improve their standard of living. We believe Appalachian natural gas and natural gas liquids are positioned to meet that future demand.
This then translates into year over year further improvements and then the last thing I'll certainly throw out is.
Congratulations to the team for all their hard work on this it is.
All supervisor my used to say success begets success, and so the momentum I think behind everyone in what we've been able to accomplish by returning to pad sites is now what we're seeing in our peer leading capital efficiency the ability to maintain that 76 per mcf fee.
Dennis Degner: And within the Appalachian Basin, Range has derives the large inventory of high quality wells across our half million net acre position and translated that into a business capable of generating free cash flow through commodity cycles. All while leading the way on capital efficiency, emissions intensity, and transparency.
<unk> molecule this year last year's 64.
So however, it shapes up with what pulls in this year, we fully expect that to be another component that allows us to be on that peer leading edge.
Okay, and just specifically on the on the cost savings are those.
Operator: But that will open the line for questions. Thank you, Mr. Degner.
If we're looking at 10 less wells on it.
Operator: The question and answer session will now begin. If you would like to ask a question, please indicate by pressing the star key, then one one. If you're using a speaker phone, please pick up your handset before asking your question. If you would like to withdraw your question, you may do so by pressing star one one again. Once again, please press star one one to ask a question in one moment for our first question.
This year for example, like what does that save you.
If were to look at that in isolation, just as a reference point.
Well again from a from a simplistic standpoint, I would say ultimately you could if you start to remove top holes out of the program and you start to look at savings for facilities construction that could represent approximately $10 million.
But when you start to think about that activity that pulls in then at the end of the year essentially that gets redeployed two drilling rigs frac activity that ultimately when you have that operational fork in the road of it doesn't make a whole lot of sense to release rigs comfort December ones. Only then pick it back up in January one as we sample so.
Scott Hanold: Our first question will be coming from Scott Handel of RBC Capital Market. The line is open. Yeah, thanks. Good morning. I thought I was pretty interesting the the ability for you guys to reduce the well-consod dramatically this year with the longer laterals. Can you give us some color and context around the overall capital efficiency? What do you think, like on an annual basis, you could save with, you know, drilling less top holes?
It maintains that ability to continue on with your operational efficiencies, but at a high level spreadsheet exercise it would be around $10 million, but it really provides us the flexibility year in and year out to make that judgment call.
We reached the year end.
Yes, no I appreciate that as you know, we do a lot of spreadsheet exercise on the side of the table, but.
Scott Hanold: And how did that manifest into or how and when did that manifest into stronger free cash flow? Yeah, good morning, Scott. I'll start in this maybe something that Mark and I both tag team across this discussion here. But when you look over the past several years, I'll take about about a half step back first year over year. We continue to see the team demonstrate the ability to advance our efficiencies. And what that's transitioned into is the ability to drill longer laterals.
Yes.
My second question and it's going to be along the same lines look it sounds like then you're going to have more ducks at the end of the year and can you talk about having that larger DUC build the setup for 2024 and maybe into 2025, how you look at potentially utilizing that.
More aggressively or just has a lower kind of free cash or free cash flow buffer.
Scott Hanold: I think you heard us talk about it not only in today, but some of the prior quarters where not only where we drilling our longest laterals, but our fastest days where we saw an improvement at the mid-year point of a 40% improvement in our drilling efficiencies just of the first half of the year versus 2022's full year average. Completions are seeing the same thing. They've seen approximately a 20 to 25% improvement in a completion efficiencies this year versus last year.
Into 2024.
Well I'll start off with this and when we think about the again at a high level what it does allow us from a flexibility standpoint is to deploy a completion crew January one instead of maybe waiting to see that DUC inventory build thats more just in time within that completions activity.
Starts with just a little bit later into the first quarter. So it really does provide a nice setup for us and how we then see that production come online hopefully it.
Scott Hanold: Some of this with procedures, rooting out non-productive time, and then having the ability to reduce overall cycle time as you basically execute these pathsides. So it's a multi-verbal type assessment when you start to then translate that into our capital efficiency. If you just do a spray feed exercise and you compare a 10,000 foot program with 61 laterals, like we originally communicated something more like we're seeing today for the year, it really changes our capital efficiency by as much as 15 to 20 dollars per foot.
More favorable pricing opportunities I think the activity that not only gets pulled forward in 2024, but at the end of this year. Also then makes that equivalent impact from a cash flow perspective.
Just frame it at a high level as to say, we see that helping us take either capital pressure off for next year, where depending upon the set up that we're going to consider for 2025 that will communicate at the next earnings call along with our 2020 for budget. We think it provides a really healthy optionality for us to either think about.
Scott Hanold: So pretty exciting about when you think about it from that perspective. But what that also does at the same time is it pulls activity that would have been executed in, let's just say the first half of Q1 has the ability to pull that into the back half of Q4. And so when you think about our guidance that we provided early on this year from a capital window perspective and when looking at both land and other aspects to this, part of that was us looking forward in anticipating some of these capital or these operational efficiency improvements and what that could set us up for in 2024.
Growth win.
That opportunity persist or how it further supports our maintenance level program whichever path is most prominent.
I appreciate the color. Thank you.
Thank you Scott.
One moment for our next question.
And our next question comes from Doug Leggate of Bank of America. Your line is open.
Okay.
Thank you good morning, everyone. Dennis I appreciate all the details. This morning, there was obviously Scott.
Scott Hanold: Having these longer laterals is going to present a flatter production profile that carries into the early part of 2024. So we really like the setup and seeing how this then translates into year over year further improvements. And then the last thing I'll certainly throw out is, is you know, again, a congratulations to the team for all our hard work on this. It is as an old supervisor, am I used to say success gets success.
Scott hit a couple of the key.
Issues are obviously going to impact your outlook for 'twenty four so I have a simple question to try and summarize.
All the moving parts what do you think has happened or will happen to your corporate level breakeven gas price and the reason I'm asking is.
It looks to us that you were pretty close to breakeven ex hedges in 'twenty three.
Scott Hanold: And so the momentum I think behind everyone and what we've been able to accomplish by returning to PagSides is now what we're seeing in our peer leading capital efficiency, the ability to maintain that 76 cents per MCFE for the replacement molecule this year, last year, 64 cents. So however it shapes up with what pulls in this year, we fully expect that to be another component that allows us to be on that peer leading.
Third quarter of 2003.
But at $2 50.
Henry hub gas price, we've got a forward curve north of four it seems to us the market continues to grossly underestimate the free cash flow capacity of the portfolio. So I'm trying to understand what you would.
You would draw the line in terms of what you think Youre 24, corporate breakeven can look like.
Quick follow up please.
Sure Good morning, Doug Thanks for the question.
Scott Hanold: Page. Okay, and just specifically on the the cost things of those, you know, if we're looking at, you know, ten less wells, you know, on it on, you know, this year, for example, like, what would that save you? If we were to look at that nice relation, just as a reference point? Well, again, from a from a simplistic standpoint, I would say, you know, ultimately you could, if you start to remove top holes out of the program and you start to look at savings for facilities, construction, that could represent approximately $10 million.
I think as we think about the breakout of our inventory on slide five it's something we've walked through a number of times with folks, but we've made the transition from really talking about wells from an EUR per thousand foot perspective, and really starting to talk about the breakeven, which youre addressing.
We basically look at it from our standpoint, we've got the 2500 locations that basically have a breakeven of $2 50 or less.
With further improvements in our capital efficiency Youre always going to have fluctuations in service costs that are going to take place just given what's going on in the market. We would expect that to be incredibly stable and be opportunity to further improve that as we look at expanding areas like water recycling as an example, and further trends translate.
Scott Hanold: But when you start to think about that activity that pulls in then at the end of the year, essentially, that gets redeployed to drilling rigs, frack activity. That ultimately, when you have that operational fork in the road of, it doesn't make a whole lot of sense to release the rigs to come for December 1 to only then pick it back up in January 1, as an example. So it maintains that ability to continue on with your operational efficiencies.
Some of the record efficiencies that we've been talking about this year into more repeatable performance certainly its fun to talk about the records, but really in order to be successful. We know it's important that we'd be repeatable. So how do you translate it into repeatable formats, and we think that has the opportunity to further improve our overall.
Scott Hanold: But at a high level, spreadsheet exercise, it would be around $10 million, but it really provides us the flexibility, year in and year out to make that judgment call when we reach the year in. Yeah, no, I appreciate that as, you know, we do a lot of spreadsheet exercises on the side of the table. But, you know, it's my second question, and it's going to be along the same lines. You know, look, it sounds like then you're going to have more ducts at the end of the year.
Breakeven costs from that inventory bidding perspective.
Hey, Good morning, Jeff This is mark yeah, sorry.
Alright got it.
Dollar per foot levels, the corporate level not the not the well levels sorry, Mark go ahead.
Sure I think stepping back and look at the corporate level cash flow third quarter. This year is really.
Scott Hanold: And can you talk about, you know, having that larger duct build, the setup for 2024 and maybe into 2025. I have how you look at, you know, potentially utilizing that, you know, more aggressively or just as a lower, you know, kind of free cash or a free cash flow buffer into 2024. Well, I'll start off with this and when we think about the, you know, again, at a high level, what it does allow us from a flexibility standpoint is to deploy a completion crew January 1.
An exemplary example of what this asset can do.
We generated greater than $90 million in free cash flow.
We intentionally reinvested and deploy that maintain the balance sheet strength pay the dividend continued to maintain and improve the balance sheet. Because this asset in <unk> can be viewed like an annuity I know, that's one lens through which you used to value the company.
Scott Hanold: Instead of maybe waiting to see that duct inventory build that's more, quote, just in time for then that completion activity starts with just a little bit later into the first quarter. So it really does provide a nice setup for us and how we then see that production come online, hopefully at, at more favorable pricing opportunities. I think the activity that won't not only gets pulled forward in 2024, but at the end of this year also then makes that that equivalent impact.
As we fast forward and look at what this company can do Theres a few scenarios in our deck to talk about free cash flow hypothetical scenarios.
Approach $4 Youre generating what we think is a reasonable perhaps conservative estimate of $1 billion per year corporate level of free cash flow and greater and I think it's notable also that that incorporates an assumption, but I'm fairly conservative NGL realizations. So there is basically an option an upside option embedded in that as well. So if we're thinking about our main.
Scott Hanold: From a cash flow perspective, you know, I'll just frame it at a high level is to say we see that helping us and take either capital pressure off for next year or depending upon the setup that we're going to consider for 2025 that will communicate at the next earnings call along with our 2024 budget. We think it provides a really healthy optionality for us to either think about growth when that opportunity persists or how it further supports our maintenance level program, whichever path is most prominent. Appreciate the color. Thank you. Thank you Scott.
Vince scenario that represents an enormous significative cash flow ranges that we've talked about before and as Dennis has already said, we are very mindful of positioning the business to be resilient. If prices are soft, but also to position ourselves to participate in growing demand, whether that's 25 pick your timeframe.
Dennis Degner: One moment for our next question.
Range has the capacity of the willingness and the ability to to grow to grow efficiently and generate what we think will be some of the most competitive margins out there. So.
I think the repeatability of that also to them at this point is key inventory depth multiply that out across a couple of decades times, a $1 billion of free cash flow annually at the corporate level and improving as we pay off debt.
Douglas Leggate: And our next question comes from Doug Legate of Bank of America. Your line is open. Thank you. Good morning, everyone. Dennis, I appreciate all the details this morning. There's obviously Scott hit a couple of the key issues that are obviously going to impact your outlook for 24. So I have a simple question to try and summarize. Highs, All the Moving Parts. What do you think has happened or will happen to your corporate level break even gas price?
Other corporate costs reduce on an mcf basis, expanding your per unit margins.
That.
I think really does represent a unique opportunity in this space.
Marcos Thanks for the clarification guys.
You are right I mean thats the other thing too many companies can claim the inventory depth. So I don't know that I would say when you look at everything of annuity but.
Douglas Leggate: And the reason I'm asking is, it looks to us that you are pretty close to break even ex-hedgies in 20 as third quarter 23, but at a 250, Henry Hub gas price, we've got a forward curve north of four, seems to us the market continues to grossly underestimate the free cash flow capacity of the portfolio. So I'm trying to understand where you would draw the line in terms of what you think your 24 corporate break even can look like.
But.
Certainly inventory depth is a big constraint on valuation for sure. So thank you for that clarification quick follow up guys.
If your inventory depth as defined on 10000 foot laterals, which I believe it is but youre drilling significantly longer laterals and improving capital efficiency.
Much longer do you think I mean, how long do you think the program can continue to step up into those longer laterals and I'll I guess, we'll see inventory that put the longer lateral just a question. So I'll leave it there. Thank you.
Douglas Leggate: And I've got a quick bubble up, please. Sure, good morning, Doug. Thanks for the questions. I think as we think about the breakout of our inventory on slide five, it's something we've walked through a number of times with folks, but we've made the transition from really talking about wells from an EUR for a thousand foot perspective and really starting to talk about the break evens which you're addressing. We basically look at it from a standpoint, we've got the 2500 locations that basically have a break even of 250 or less with further improvements in our capital efficiency.
Thank you, Doug I think Theres a lot of running room. When you think about the ability to further extend our laterals and what that means to our overall program. If you look back over the past, let's just say three years I'll pick something reasonably near term year over year, we've seen a continued theme of incrementally in.
Increasing our overall lateral links and I know we've talked about this on previous calls, but also while return to pad sites with existing production. So this isn't this is certainly what we would call clean sheet development, where you are moving out into the fringes of your asset base. This is in and around prior producing wells and taking the learnings from those historical execution.
Douglas Leggate: You're always going to have fluctuations in service costs that are going to take place just given what's going on in the market. We'd expect A, that to be incredibly stable and B, opportunity to further improve that as we look at expanding areas like water recycling as an example and further translating some of the record efficiencies that we've been talking about this year into more repeatable performance. Certainly, it's fun to talk about the records, but really in order to be successful, we know it's important that we be repeatable.
<unk> and translating that into more efficient execution and planning. So we see the 21000 foot laterals that we drilled this year is a good reflection of that.
Got in excess of 60 wells that are at 15000 foot and horizontal length. So again, we'll move methodically through equipment upgrades procedures, TPI tracking and make sure that we're extending our laterals in the most efficient and prudent way.
Douglas Leggate: So how do you translate that into repeatable formats? We think that has the opportunity to further improve our overall break even cost from inventory bidding perspective. Thank you, Martin. This is Mark. Oh, sorry. The corporate level, the corporate level, not the well level. Sorry, Mark, go ahead. Sure. I think stepping back and looking at the corporate level, cash flow. Third quarter, this year is really an exemplary example of what this asset can do.
And look at the end of the day, we've got an inventory runway even with exceeding of these laterals. That's 30 greater than 30 years with break evens that are in the $2 range or better and so we think this is going to bode well as we think about the runway of this inventory development process.
Gentlemen, thanks for your time I appreciate the color the answers.
Thanks, Doug and one moment for our next question and our next question will come from Jean Ann Salisbury of Bernstein. Your line is open gene.
Douglas Leggate: We generated greater than $90 million in free cash flow. We intentionally reinvested and employed that, maintain the balance sheets, strengths, pay to dividend, continued to maintain and improve the balance sheet, because this asset in one sense can be viewed like an annuity. I know that's, you know, one lens which you used to value a quarter is we fast forward and look at what this company can do. There's a few scenarios in our deck to talk about free cash flow, hypothetical scenarios.
Hi, Good morning, one more follow up on the dry barriers at the longer laterals and fewer turned in line and how material is the shape of the forward curve and that decision. For example, if the forward curve goes into backwardation with that with that kind of push you to stop extending lateral length or even potentially get a shorter laterals.
I think maybe from an economic.
Standpoint, I'll start this one off.
The shape of the forward curve.
Douglas Leggate: As we approach $4, you're generating what we think is a reasonable, perhaps conservative estimate of a billion dollars per year, corporate level of free cash flow. And greater, and I think it's notable also that that incorporates an assumption of fairly conservative and GL realization. So there's basically an upside option embedded in that as well. So if we're thinking about a maintenance scenario that represents an enormous annuity of cash flow, ranges we've talked about before, and as Dennis has already said, we are very mindful of positioning the business to be resilient of prices or soft, but also to position ourselves to participate in growing demand.
<unk>.
<unk> will be the primary driver in that decision, making process as we look at efficiency and driving Lewis maintenance capital number possible.
Is optimizing those capital Reinvestments it is creating a company with <unk>.
Call, it, 40% or better reinvestment rate to hold production flat in that.
70, some cents per Mcf capital expenditure to hold production flat. So the shape of the curve as we think about the overall economics. It's also impacted by the flat decline rate.
Douglas Leggate: Whether that's 25, pick your time frame, range has the capacity, the willingness and the ability to grow, to grow efficiently and generate what we think will be some of the most competitive margins out, there. So, I think the repeatability of that also to Dennis's point is key. This inventory depth multiply that out across a couple of decades times a billion dollars free cash flow annually at the corporate level and improving as we pay off debt and other corporate costs reduce on an NCFE basis, expanding your per unit margin that I think really does represent a unique opportunity in this space.
<unk>, a 19% decline rate so as you flatten that out over time, we're looking at a price three year through the seasonality what the sustainable price levels car and of course, that's also bolstered by the hedging program. So prices will move they will move radically our balanced program.
<unk> generates significant contribution from the liquids cut as well.
Find with the natural gas along with sales points across the U S.
<unk> of the curve doesn't necessarily impact us deciding to drill 12 to 15000 foot lateral really it comes back to what's the economics, what's the space in the existing system, where are we placing that to optimize the use of the existing surface facilities existing compression gathering and long haul transport so.
Douglas Leggate: Mark, thanks for the clarification, guys. Mark, did you, you're right. I mean, I don't think too many companies can claim the inventory depth, so I don't know that I'd say we look at everything in this inventory, but, but you know, it certainly inventory depth is a big constraint on valuation for sure. So, thank you for that clarification. Quick follow up, guys, um, if your inventory depth is defined on 10,000 food laterals, which I believe it is, but you're drawing, you know, significantly longer laterals than improving capital efficiency.
Not to talk around the question, but its just a multifaceted equation.
That evaluation, we do to make sure we can get the most out of it reinvested dollar yes, no that makes sense. Thank you and then your differential guidance for the year it was slightly.
Slightly 40 to 45 cents and can you give any more color on whether that was specific end markets getting a little bit worse.
Douglas Leggate: How much longer do you think? I mean, how long do you think the program can continue to step up into those longer ladders? And I'll, yeah, I guess we'll see inventory depth of the longer ladders as a question, so now leave it there. Thank you. You know, thank you, Doug. I think there's a lot of running room when you think about the ability to further extend our ladders and what that means to our overall program.
And based on pricing.
Life can add some details to that but I think the short version is we all know in shoulder seasons.
And where storage levels were in the third quarter. There were some soft spots in the in basin markets in particular in Appalachia, but fortunately.
80% of our gas out of <unk>.
Douglas Leggate: If you look back over the past, let's just say three years, I'll pick something reasonably near term, year over year, we've seen a continued theme of incrementally increasing our overall ladder links. And I know we've talked about this on previous calls, but also while returning to pet sites with existing production. So this isn't necessarily what we would call clean sheet development where you're moving out into the fringes of your asset base.
And basically all of our liquids over 90% of our revenue is out of basin. So that's a reflection of that minority of the production that sold in basin.
It is bolstered by our by our basis hedging program and effectively a basis hedging program embedded in the physical sales and diversity of customers we have but.
That's the long and short of it Theres been no substantial change to our portfolio of customers, we still sell across greater than 30 different natural gas pricing points, and we'll look to keep optimizing that program over time that portfolio over time.
Douglas Leggate: This is in and around prior producing wells and taking the learnings from those historical executions and translating that into more efficient execution and planning. So we see, you know, the 21,000 foot ladders that we drilled this year as a good reflection of that. We've got in excess of 60 wells that are at 15,000 foot in horizontal length. So again, we'll move methodically through equipment upgrades, procedures, KPI tracking and make sure that we're extending our ladders in the most efficient, improved way.
Great. Thanks, that's all for me.
And one moment for our next question.
Our next question will be coming from Kumar Choudhary of Goldman Sachs <unk> Company. Your line is open.
Hi, good morning, and thank you for taking my questions.
My question. My first question was on the NGL macro I appreciate all the details on your slide deck.
Prices have been weak this year.
Especially for LPG and you've seen a pickup in exports recently, but the 30 basis had been high dose So would love your thoughts around the LPG outlook heading into next year.
Douglas Leggate: And look, at the end of the day, we've got an inventory runway, even with the extending of these ladders, that's 30, you know, greater than 30 years, but break evens that are in the $2 range or better. And so we think this is going to both well as we think about the runway of this inventory development process. Thank you for your time. Appreciate it. Quite the answers. Thank you.
Operator: And one moment for our next question.
You bet good morning <unk>.
I think as we start to think about.
I'll start with propane first when you think about.
What we've seen clearly stock levels have been elevated were running around 100 million barrels in inventory levels.
Operator: And our next question, we'll go make from Jean and Fallsbury of Bernstein. Your line is open. Jean. Hi. I'm good morning. One more follow up on the drivers of the longer laterals and fewer turned in line wells. How material is the shape of the forward curve in that decision? For example, if the forward curve goes into backwardation, would that kind of push you to stop extending lateral length or even potentially go to shorter laterals?
That's clearly on the back of the weaker winter from this past year and also maybe a little bit of a slower progression to the chemical markets than what had originally been anticipated.
I think if you start to think about 24, which was the crux of your question.
A couple of things.
See or we see is underpinning.
Positive movement going forward and one is the PVH infrastructure and incur.
In cracker infrastructure, that's been in the process of being commissioned seeing improving run rates month over month, but also additional infrastructure that will get commissioned so it's around 400000 barrels a day and infrastructure. This year and next year. It's in excess of 400000, So <unk> got back to back years of what we'll call incremental.
Operator: I think maybe from an economic standpoint, I'll start this one off. The shape of the forward curve won't be the primary driver in that decision making process. As we look at efficiency and driving the lowest, maintenance capital number possible, it is optimizing those capital reinvestments. It is creating a company with a call it 40%, or a better reinvestment rate to hold production flat and that 70% per MCFE capital expenditure to hold production flat.
Needs in an infrastructure thats going to get commission, that's going to help with this stock level perspective in view.
The other side of this equation is you have got really strong exports. If you look at year to date values. We've seen a range of one five to $1 7 million barrels a day.
Average is a little over one five for the year.
Operator: So the shape of the curve is we think about the overall economics. It's also impacted by the flat decline rate that range at 19% decline rate. So as you flatten that out over time, we're looking at a price three years through the seasonality of what the sustainable price levels are. And of course, that's also bolstered by the hedging program. So prices will move, they will move erratically our balance program that generates significant contribution from the liquid's cut as well.
A few years ago that would've been a peak moment and a record $2 two but now it's good strong repeatable performance month in month out so thats certainly helping with the equation. When you think about days of supply, though when you translate that back to where we're at today really 3% below the five year average. So when you think about all the demand component in getting through the winter setup that.
We have ahead of us we see stock levels, starting to re normalize as you get into the through the first half of 2024.
Operator: Combined with an after-gas cut, along with sales points across the US, you know, the shape of the curve doesn't necessarily impact us deciding to drill a 12,000 to a 15,000-foot lateral. Really, it comes back to what's the economics, what's the space in the existing system, where are we placing that to optimize the use of the existing surface facilities, existing compression, gathering, and long-haul transport. So not to talk around the question, but it's just a multifaceted equation and evaluation we do to make sure we can get the most out of $200.
<unk> is tighter.
The supply on that side is around 18 days in storage levels are just below 50 million barrels that we continue to see strong interest from our traditional counterparties on additional ethane opportunities and so we would expect to see.
Some spikes at times and pricing like we've seen over the past three to six months that's been reflective in how the market has been tightened we would expect to see some ongoing volatility as we move forward and of course once we start to see net gas storage levels get re normalized as well you would expect to see further improvements in ethane treating then on the back.
Operator: Yes, no, that makes sense. Thank you. And then your differential guidance for the year moved. It was slight, but moved slightly to the 40 to 45 cents. Can you give any more color around whether that was specific in market, getting a little bit worse or in basin pricing? Life can add some details to that, but I think a short version is we all know in shoulder seasons and where storage levels were in the third quarter, there were some soft spots in the in basin, markets in particular in Appalachia, but fortunately 80 plus percent of our gas is out of basin and basically all of our liquids over 90% of our revenues out of basin.
What's happening on the gas front as well.
I will join in here as well as we think about the valuation impact of that commentary in the backdrop that creates today, we're seeing NGL realizations in the 35% tightened as it could mid thirty's.
GW Ti as we think about a more normalized level that we have.
Would fully expect to be well in excess of 40% what youre seeing is an embedded option value within range for that re rating for the normalization of propane inventories and while nominally they are high on a days to cover basis like many many of the other commodities there are not that far off of five year averages. So with these high export levels growth and demand the speed at which they can recover to normal.
Operator: So that's a selection of that minority introduction that sold in basin. You know, it is bolstered by our by a basis hedging program and effectively a basic hedging program embedded in the physical sales and diversity of customers we have, but that's that's the long and short of it. There's been no substantial change to our portfolio of customers. We still sell across greater than 30 different natural gas pricing points and we'll look to keep optimizing that program over time that portfolio over time. Great. Thanks. That's all for me.
Model nominally and actually become tight in reality.
Really highlights the value of that embedded option of Ngls within the range story.
Okay.
Another option that you have.
So on growth given you're a differentiated inventory.
Anything you would like to see on local demand.
You are seeing on gas marketing, which kind of unlock that potential.
Heading into next year.
Umang Choudhary: In one moment for our next question, our next question will be coming from among Chargery of Goldman Sachs and company your lines open.
And the next few years.
Yes, I think when you start to think about the opportunity for growth and in we'll just say in basin demand clearly a shell cracker is a good example of.
Dennis Degner: Hi, good morning and thank you for taking my questions. My first question was on on the NGL macro appreciate all the details on the slide deck prices have been weak this year, especially for LPG and you've seen a pickup in exposed recently, but the free prices have been high too. So we'd love your thoughts around the LPG outlook heading into next year. You've had good morning among. I think as we start to think about, you know, we're I'll start with propane first when you think about, you know, what we've seen clearly stock levels have been elevated.
Ongoing commissioning getting to higher run rates.
The course of time, and it's working through but we would kind of view as normal Greenfield startup type.
Challenges, but also successes in the same breath. So I think Thats a good example, I think the other part is is you've got coal retirements that are going to be taking place over the balance of the next few years opportunity for Nat gas and range to backfill those opportunities for power generation I think if we learned anything this past summer.
Dennis Degner: We're running around a hundred million barrels in inventory levels. That's clearly on the back of a weaker winner from this past year and also maybe a little bit of a slower progression to the chemical markets than what had originally been anticipated. I think if you start to think about 24, which was the crux of your question, you know, a couple of things I see are we see is underpinning, you know, a positive movement going forward and one is the PDH infrastructure.
Yes, really stood strong for that backfill of power generation, adding two five bcf roughly an incremental power to power generation and occupying that space.
<unk> wind and others were below forecast. So we see those as kind of more in the near term I think when you start to get past 2024, you really start to have the question of what additional power generation is going to get put into place from a combined cycle standpoint, I think youre seeing a lot of dialogue now around the grid reliability, how you expand.
Dennis Degner: And and cracker infrastructure that's been in the process of being commissioned seeing improving run rates month over month, but also additional infrastructure that will get commission. So it's around 400,000 barrels a day in infrastructure this year and next year it's an excess of 400,000. So you've got back to back years of what we'll call incremental needs and infrastructure that's going to get commission that's going to help with this stock level perspective and view.
If we're going to have further electrification and bolstering of the grid.
That's going to come with a reliable fuel source, which we say range in that gas is going to play a huge role in that and I think the second thing I would throw out on the future is EV battery industrial type development manufacturing if you start to look at where some of this.
Incremental in future.
Dennis Degner: Other side of this equation is you've got really strong exports. If you look at your today values, we've seen a range of 1.5 to 1.7 million barrels a day average is a little over 1.5 for the year. A few years ago that would have been a peak moment and a record to point to, but now it's good strong repeatable performance month in and month out. So that's certainly helping with the equation.
Manufacturing and industrial demand is pointing to to be constructed it's not too far away from some of the transport that range has in our portfolio that gets us to the Gulf to the Midwest. So again, we really see this as being a bright future for not only Nat gas and Ngls, but how is the role that range could play in that.
As you start to see inventory exhaustion by others and also then underpinned by the quality and runway of inventory that range and so we think it's a bright future.
Dennis Degner: When you think about days of supply, though, and you translate that back to where we're at today, we're really 3% below the five year average. So when you think about all the demand component and getting through the winter setup that we have ahead of us, we see stock levels starting to re-normalize as you get into through the first half of 2024. Ethane is tighter. The basis of supply on that side is around 18 days and storage levels are just below 50 million barrels and we continue to see strong interest from our traditional counter parties on additional F.A, and opportunities.
It's a multi variable perspective as you look forward.
Very helpful. Thank you so much.
Thank you.
One moment for our next question.
Okay.
Our next question will be coming from Michael <unk> of Stephens. Your line is open.
Hi, Good morning, guys does give some detail on the savings you anticipate for steel and sand maybe on rig costs as well.
Dennis Degner: And so we would expect to see some spikes at times in pricing like we've seen over the past three to six months. It's been reflected in how the market has been tightened. We would expect to see some ongoing volatility as we move forward. And of course, once we start to see net gas storage levels get renormalized as well, you would expect to see further improvements in F.A, and trading then on the back of what's happening on the gas spread as well.
But it looks like you kept your well costs in your investor deck unchanged from last quarter can.
Can you say.
Where do you think 24 costs will be.
Relative to 23.
Some of those savings get offset elsewhere I know you mentioned the.
The new Frac fleet.
Dennis Degner: I'll join in here as well. We think about the valuation impact of that commentary in the backdrop that creates, you know, today we're seeing in jail realizations in the 35% type zip code mid 30 relative to WTI. As we think about a more normalized level that we would fully expect to be well in because that's a 40% what you're seeing is an embedded option value within range for that rewriting for the normalization of prevent inventory.
Fleet.
Is that going to offset those savings or do you anticipate lower cost next year.
Yes, good morning, Michael I think I would I would start off by some.
Somewhat saying, we're super early in the process of our RFP.
Rollout that we just deployed here over the last several weeks so what I'm sharing with you is kind of some of those early indications in the prepared remarks. This morning, I think we're going to have a lot better view once we get towards the end of the year, we get that process wrapped up and we start to communicate how that translates into our execution for our plan for 2024. So.
Dennis Degner: And while normally they are high on a days to cover basis, like many many other commodities, they're not that far off of five year averages. So with these high export levels growth and demand, the speed at which they can recover to normalize levels nominally and actually become tight in reality really highlights the value of that embedded option of NGOs within the range story. Another option which you have is also on growth given you a differentiated inventory.
I think we'll have a lot better view at that point.
The numbers in the back of the slide deck habit change because ultimately we're still in the middle of that evaluation of that process and once we know what our full cost structure will look like then we will have again better updates you are seeing in our opinion I'll share. One final thought you are starting to see I see.
Dennis Degner: Anything you would like to see on local demand or anything you're seeing on gas marketing, which can unlock that potential heading into next year or in the next few years. Yeah, I think when you start to think about the opportunity for growth and and we'll just say in base and demand, you know, clearly a shell cracker is a good example of it's ongoing commissioning getting to higher run rates, you know, over the course of time and it's working through what we would kind of you as normal greenfield startup type.
A.
It may be cost are going to look differently than the traditional rig count service cost of rig count down service costs down across the board.
We tried to share some of that this morning in the prepared remarks, because youre still seeing a high level of utilization for for services. As an example, like Super spec drilling rigs and also the electric fracturing fleets, we think that could prevent could present some stabilization in that cost structure, maybe even some slight relief, but it'll be other areas that we may see.
Dennis Degner: You know, challenges but also success in the same breath. So I think that's a good example. I think the other part is, is you've got whole retirements that are going to be taking place over the balance of the next few years opportunity for, you know, Matt gas and range to backfill those opportunities for power generation. I think if we learned anything this past summer. You know, net gas really stood strong for that backfill of power generation, adding to and a half BCF, you know, roughly an incremental power, power generation and occupy in that space when, you know, at times, wind and others, you know, we're below forecast.
Again more relief, whether it's some of the consumables like tubular goods, where we're seeing that 30% relief for for next year and have done a job of securing that but also in areas like diesel fuel more stabilization on the frac sand side as well. So we'll have better numbers for everyone at the next call, but we would expect to see some.
Modest level of savings it could be.
Single digit type savings mid level, but we'll have a better answer when we get to February.
Dennis Degner: So we see those as kind of more in the near term. I think when you start to get past 2024, you know, you really start to have the question of what additional power generation is going to get put into place from a combined cycle standpoint, if you're seeing a lot of dialogue now around the grid reliability, how you expand that we're going to have further electrification and bolstering of the grid. That's going to come with a reliable fuel source, which we think range and that gas is going to play a huge role in that.
Understood. Thanks.
I guess given the longer laterals, the improved capital efficiency. It sounds like your base decline rate continuing to shallow can you say where maintenance capex or maybe <unk>.
Year maintenance activity level would need to be next year relative to 2023.
I think a way of thinking about our program for 24, and a maintenance type scenario is around $600 million.
Dennis Degner: And I think the second thing I would throw out on the future is ED battery industrial type development manufacturing. Chris, incremental and future manufacturing and industrial demand is is pointing to to be constructed. It's not too far away from some of the transport that range has in our portfolio that gets us to the Gulf, to the Midwest. So again, we really see this as being a bright future for not only that gas and AGLs, but how the role that range could play in that as you start to see inventory exhaustion by others.
You could see that be slightly less depending upon the setup. We're thinking about for 2025. Once we start to get to February you see what kind of winter we've got.
LNG infrastructure build out how thats further progressing along so I think there are several variables that we would want to take into account, but I think the way to think about our program and our maintenance scenario was about $600 million.
And it would be around 50 to 60 wells I think historically, we would've said 60 wells kind of year end and year out, but with the advancement in our lateral links it could be somewhere closer to 50.
Depending upon what kind of inventory, we would like to carry into the setup for 2025.
Dennis Degner: And also then underpinned by the quality and runway of inventory that range has. So we think it's a bright future. It's a it's a it's a multivariable perspective as you look forward. Betty has. Thank you so much. Thanks very much.
Dennis Degner: And one moment for our next question.
Very good thank you.
Thanks, Michael and one moment our next question.
Yeah.
Our next question will be coming from Jacob Robert.
Of Tpa <unk> company your line is open.
Michael Scialla: Our next question will be coming from Michael Salah of Stevens, your line is open. Hi, good morning, guys. Then give some detail on the savings the anticipate for steel and sand, maybe on rig costs as well. But it looks like you kept your well costs in your investor deck unchanged from from last quarter. Can you say where you think 24 costs will be relative to 23 do some of those savings get offset elsewhere.
Morning.
Thank you Doug you touched on this in a response to Doug earlier, but I'm just curious if you could remind us the percentage of activity that has been on prior pads in recent years, and where you expect that percentage to ship to over the next let's say 12 to 24 months.
Yes, good morning, Jacob historically, we have been moving back to pads with existing production for somewhere as low as 30%, but it's more closer to about 50% of our activity. Each year. This past quarter kind of represents some of that fluctuation of what we see quarter in and quarter.
Michael Scialla: I know you mentioned the new fraction fleet. Is that going to offset those savings or the anticipate lower cost next year? Yeah, good morning, Michael. I think I would I would start off by, you know, somewhat saying we're super early in the process of our RFP rollout that we just deployed here over the last several weeks. So what I'm sharing with you is kind of some of those early indications in the prepared remarks this morning.
We're actually three quarters of our wells that.
We executed were on pads with existing production, but I think a good way of thinking about our program Youre in a year out is about half of our activity would be on pads with existing production and again part of that is to complement something mark touched on a few minutes ago and that is utilization of the gathering system compression pipes.
And also our processing, where we see those opportunities so moving back to those pads not only provides capital efficiency improvements, but it also translates into our ability to keep our gathering system fully utilized in our cost structure as low as possible.
Michael Scialla: I think we're going to have a lot better view once we get toward the end of the year. We get that process wrapped up and we start to communicate how that translates into our execution for our plan for 2024. So I think we'll have a lot better view at that point. The numbers in the back of the slide deck have it changed because ultimately we're still in the middle of that evaluation of that process.
Okay I appreciate that.
And then second question could you refresh us on where the understandings are on the Utica Devonian and maybe where you hope to be in better understanding and into 2020 for whether it's via your own pursuits or by peers in the area.
Michael Scialla: And once we know what our full cost structure will look like, then we'll have, you know, again, better updates. You are seeing in our opinion, I'll share one final thought. You are starting to see I think a, it's maybe cost of going to look differently than the traditional recount up service cost of recount down service cost down across the board. And we try to share some of that this morning in the prepared remarks because you're still seeing a high level of utilization for services as an example, like super spec drilling rigs and also the electric fracturing fleets.
Well when we think about the Utica I'll start off by saying, we're awfully excited about the future potential of that asset, but when we think about our inventory runway on the Marcellus. The repeatability, we've got 500 wells that we've drilled and completed we understand that the formation incredibly.
Well and again as I mentioned earlier, it's very repeatable for us and so the improvements that we've made have really kind of underpins the resilience of our business. When you think about the future of the organization and the inventory bidding that we have with the low breakeven that we touched on earlier our focus is clearly on the Marcellus as we go forward.
Michael Scialla: We think that could prevent, could present some stabilization in that cost structure, maybe even some slight relief, but it'll be other areas that we may see. Again, more relief, whether it's some of the consumables, like tubular goods, or we're seeing that 30% relief for for next year and have done a job of securing that. But also in areas like diesel fuel, more stabilization on the practice fan side as well. So we'll have better numbers for everyone at the next call, but we would expect to see some modest level of savings.
In many cases youre going to see others focus on the Utica because of potentially limitations they have either in their marcellus inventory or the quality of that inventory. They have we think we can be patient. We can sit back we can do industry surveillance watch what others are doing and then translate that into how we would advance the technical model.
Michael Scialla: Secretary. Better stood, thanks. And I guess given the the longer laterals, the improved capital efficiency, sounds like your baseline rate is continuing to shallow, can you say where maintenance catbacks or maybe if it's easier maintenance activity level would need to be next year relative to 2023. I think a way of thinking about our program for 24 in a maintenance type scenario is around $600 million. You could see that be slightly less depending upon the setup we're thinking about for 2025.
<unk> in the years that follow for the for the opportunity when we would like to pull that into the program are more of an active basis, but.
Again, we're highly focused on the Marcellus and for obvious reasons. When you look at the costs associated with the efficiencies and on top of it just the depth and quality of inventory that we have.
Thank you I appreciate the time.
Michael Scialla: Once we start to get to February, see what kind of winter we've got LNG infrastructure build out how that's further progressing along. So I think there's several variables that we would want to take into account. But I think the way to think about our program in a maintenance area was about $600 million. And it would be around 60 wells. I think historically we would have said 60 wells kind of year in and year out. But with the advancement in our lateral links, it could be somewhere closer to 50 depending upon what kind of inventory we would like to carry into the setup for 2025. Very good. Thank you. Thanks, Michael.
Thanks Jacob.
And one moment for our next question. Our next question will be coming from Iran. Jairam of Jpmorgan Securities. Your line is open.
Michael Scialla: In one moment for our next question.
Yes, good morning.
I just wanted to start with maybe a housekeeping question.
Fourth quarter guide on volumes that you've provided on the call looks to be that.
Shy of the street and what we're modeling and maybe we're a little surprised just given kind of the pull forward of activity, but any drivers of that that you could you could point to.
Yes, good morning, Arun I think what I would point to is really the extended laterals that we've been completing I think if you look at Q3.
Good example is the $2 2000, 21000 foot laterals and having that maintenance level program, coupled with the gathering system that we're keeping cool. So we're just going to do is it's going to allow us to keep production flatter as we start to transition into Q1, if you think about the past several years and what maintenance has looked like.
Michael Scialla: Our next question will be coming from Jacob Roberts of TPH and company. Your line is open. Morning. I think you touched on this in response to Doug earlier, but I'm just curious if you could remind us the percentage of activity that has been on prior pads in recent years and where you expect that percentage to shift to over the next, let's say 12 to 24 months. Yeah, good morning, Jacob. Historically, we have been moving back to pads with the existing production for, you know, somewhere as low as 30% but it's more closer to about 50% of our activity each year.
<unk> tend to have our highest production in the back half of the year, but then youre going to see.
Michael Scialla: This past quarter kind of represents some of that fluctuation of what we see quarter in and quarter out. We're actually three quarters of our wells that we executed were on pads with existing production. But I think a good way of thinking about our program year in and year out is about half of our activity would be on pads with existing production. And again, part of that is to compliment something marked touched on a few minutes ago.
Some decline in the first portion of the year as we start to then catch back up with that higher activity cadence in the first half that translates into the uptick in production in the back half. We think this is going to actually translate into a little bit more of a level loaded production profile as we come out of Q4 through the winter months, where we have improved pricing and then through.
Not only the first part of Q1, but then as the start of Q2, so a little bit differently, what we've seen in the past couple of years.
Thats helpful.
Maybe next one is for Mark Mark you are really approaching.
Your your either debt reduction or your leverage target or your gross debt target pardon me and I just wanted to see if you could kind of give us a sense of from a timing perspective, when do you expect to get there.
And thoughts on cash return as we move into a better.
Part of the gas cycle.
Sure.
Michael Scialla: And that is utilization of the gathering system compression pipes and also our processing where we see those opportunities. So moving back to those pads not only provides capital efficiency improvements, but it also translates in our ability to keep our gathering system fully utilized in our cost structure as low as possible. Okay, appreciate that. And then the second question, can you refresh us on where the understandings are on the Utica and Devonian and maybe where you hope to be in that understanding in into 2024, whether it's via your own pursuits or by peers in the area?
Tough question to answer to give them the month in which we pass it.
This target range, if I had a perfect crystal ball for the weather and the pricing. This winter, we'd be able to do that but I think what youre pointing to is the fact that we are right. There on the doorstep of entering the target threshold. We think we're in a great spot already with the balance sheet and that gives us flexibility today, but even more.
For flexibility, we fully expect next year to use free cash flow and redeploy it whether it's through incremental share repurchases, whether there is a modest increase in the dividend where theres other forms of reinvestment directly into the business.
That gives us additional latitude we have available under our board approved buyback program of $1 1 billion all point to our activity last year, we repurchased $400 million in shares. This year, obviously prices came off so we backed off a little bit. So we're just balancing that reinvestment our program.
Michael Scialla: Well, when we think about the Utica, I'll start off by saying we're awfully excited about the future potential of that asset. But when we think about our inventory runway on the Marcellus, the repeatability, we've got 1500 wells that we've drilled and completed, we understand that the formation incredibly well. And again, as I mentioned earlier, it's very repeatable for us. And so the improvements that we've made have really kind of underpin the resilience of our business.
We intentionally shied away to date from giving a formulaic approach, we like the optionality of being able to take advantage of opportunities in the market to reinvest at opportune times. So just to give extreme examples if we saw a huge pullback in the stock.
Michael Scialla: When you think about the future of the organization and the inventory, beginning that we have the low break evens that we touched on earlier, our focus is clearly on the Marcellus as we go forward. In many cases, you're going to see others focus on the eutica because of potentially limitations they have either in their ourselves inventory or the quality of that inventory they have. We think we can be patient, we can sit back, we can do industry surveillance, watch what others are doing and then translate that into how we would advance the technical model in the years that follow for the opportunity when we would like to pull that into the program and have a more of an active basis, but again, we're highly focused on the Marcellus and for obvious reasons, when you look at the costs associated with it, the efficiencies and on top of it just the depth and quality of inventory that we have. Thank you. Appreciate the time. Thanks, Jacob.
We would consider hard whether it's time to put more of our cash flow sooner rather than later back into the buyback program.
Alternatively prices are soft will remain conservative and focus on the balance sheet. So we're so close to that target.
Alex sheet range that we like the flexibility to get today and I will just highlight again and I think that gives us even greater latitude as we get into 2024 and after.
Sure.
Thanks, Mark for the thoughtful response toxin.
Thank you.
Thank you and that will be our last question. This concludes today's question and answer session I would like to turn the call back over to Mr. Degner for his concluding remarks.
We'd like to say thanks for everyone joining us on the call. This morning. If you have any follow up questions. Please don't hesitate to follow up with the Investor Relations team. Thank you.
Jacob Roberts: In one moment for our next question, our next question will be coming from Arun Jayaram of JP Morgan Security, do you line it open? Yeah, good morning. Dennis, I want to start with maybe a housekeeping question. The fourth quarter guide on volumes that you provided on the call, look at the touch shy of the street and what we're modeling and maybe we're a little surprised as given kind of the pull forward of activity, but any drivers of that that you could point to?
Thank you for your participation in today's conference you may now disconnect.
Jacob Roberts: Yeah, good morning, Arun. I think what I would point to is really the extended laterals that we've been completing. I think if you look at Q3, good example is the 220, 21,000 foot laterals and having that maintenance level program coupled with a gathering system that we're keeping cold. So what it's going to do is it's going to allow us to keep production flatter as we start to transition into Q1. If you think about the past several years and what maintenance has looked like, we tend to have our highest production in the back half of the year, but things you're going to see some decline in the first portion of the year as we start to then catch back up with that higher activity cadence in the first half that translates into the uppicking production in the back half.
Jacob Roberts: We think this is going to actually translate into a little bit more of a level loaded production profile as we come out of Q4 through the winter months where we have improved pricing and then through not only the first part of Q1, but then as it started Q2. It's a little bit different from what we've seen the past couple of years. That's helpful. Maybe next one is for Mark. Mark, you're really approaching your debt reduction or your leverage target or your gross debt target pardon me.
Jacob Roberts: And I just wanted to see if you could kind of give us a sense of, from a timing perspective, when you expect to get there and thought some cash return as we move into a better part of the gas cycle. Sure, that's a tough question to answer to give the months and which we pass into the target range. If I had a perfect crystal ball for the weather and the pricing this winter, we'd be able to do that.
Jacob Roberts: But I think what you're pointing to is the fact that we are right there on the doorstep of entering the target threshold. We think we're in a great spot already with the balance sheet and that gives us flexibility today. But even more flexibility, we fully expect the next year to use free cash flow and redeploy it. Whether it's through incremental share repurchases, whether there's a modest increase in the dividend, whether there's other forms of reinvestment directly into the business.
Jacob Roberts: That that gives us additional latitude. We have available and report approved buyback program 1.1 billion. You know, I'll point to our activity last year where we repurchased $400 million in shares. This year, obviously, prices came off, so we backed off a little bit. So we're just balancing that reinvestment our program. We intentionally shied away today from giving a formulaic approach. We like the optionality of being able to take advantage of opportunities in the market to reinvest it in opportune times or just to give extreme examples.
Jacob Roberts: If we saw a huge pullback in a stock, we would consider hard whether it's time to put more of our cash flow sooner rather than later. Back into the buyback program alternatively, prices are soft will remain conservative and focus on the balance sheet. So we're so close to that target balance sheet range that we like the flexibility to get today. And I'll just highlight again that I think that gives us even greater latitude is we get into 2024. Doctor.
Jacob Roberts: Thanks Mark for the thoughtful response, Tuxen. Thank you. Thank you, and that will be our last question.
Operator: This concludes today's question and answer session. I would like to turn the call back over to Mr. Degner for his concluding remarks. I'd like to say thanks for everyone joining us on the call this morning.
Dennis Degner: If you have any follow-up questions, please don't hesitate to follow up with the investor relationship. Thank you.
Operator: Thank you for your participation in today's conference. You may now disconnect.