SilverBow Resources, Inc. (NYSE:SBOW) Q3 2022 Results Conference Call November 3, 2022 10:00 AM ET
Company Participants
Jeff Magids – Senior Manager, Finance & IR
Sean Woolverton – CEO & Director
Steve Adam – EVP & COO
Chris Abundis – EVP, CFO, General Counsel & Secretary
Conference Call Participants
Neal Dingmann – Truist Securities
Charles Meade – Johnson Rice
Tim Rezvan – KeyBanc Capital Markets
Donovan Schafer – Northland Capital Markets
Operator
Thank you for standing by. At this time, I would like to welcome everyone to the SilverBow Resources Third Quarter 2022 Earnings Conference Call. All lines have been placed on mute t prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you.
Jeff Magids, Director of Finance and Investor Relations. You may begin your conference.
Jeff Magids
Thank you, Cheryl, and good morning, everyone. Thank you very much for joining us for our third quarter 2022 conference call. With me on the call today are Sean Woolverton, our CEO; Steve Adam, our COO; and Chris Abundis, our CFO.
Yesterday afternoon, we posted a new corporate presentation to our website and we’ll occasionally refer to it during this call. We encourage listeners to download the latest materials.
Please note that we may make references to certain non-GAAP financial measures, which are reconciled to their closest GAAP measure in the earnings press release. Our discussion today may include forward-looking statements which are subject to risks and uncertainties, many of which are beyond our control. These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website.
With that, I will now turn the call over to Sean.
Sean Woolverton
Thank you, Jeff, and thank you, everyone, for joining our call this morning. SilverBow continues to execute on both our organic drilling program and our accretive A&D strategy. The third quarter marked a key inflection point in our growth strategy.
During the quarter, we announced our sixth and seventh acquisitions since August of last year. And operationally, we focused on the addition of a second drilling rig in the integration of the Sundance assets. We have added significant scale through acquisitions and high-return drilling over the last 18 months, and going forward, SilverBow is primed for further growth.
Before I lay out our multiyear strategic objectives, I would like to briefly review some notable highlights since our last call. In September, we announced a new 7,500 net acre position in the dry gas Dorado window of Webb County. This was the culmination of a series of bolt-on acquisitions, leasing deals and drill-to-earn agreements assembled over the last year.
The stacked pay codevelopment opportunity consists of over 50 net drilling locations, which are northeast of our existing Webb County position, and expands our high-return gas inventory in the Eagle Ford and Austin Chalk. As a result, at quarter end, our Webb County position totaled 17,000 net acres and nearly 200 drilling locations, with an average rate of return exceeding 100%.
At the beginning of October, we moved both of our drilling rigs to our Webb County gas area. This decision was based on continued strong Austin Chalk results. To date, we have brought online seven Austin Chalk wells, and all of them are exceeding expectations. In total, we will drill 16 wells at Fasken during the third and fourth quarters, with 15 of the 16 targeting the Austin Chalk and one targeting the Upper Eagle Ford. The returns we are generating in the Austin Chalk warranted this shift in our capital allocation, and much of this development should benefit from strong winter pricing.
In addition, specific to 12 of the 16 wells, our non-op partner elected not to participate in those projects. As a result, we will add an incremental 4.5 net wells to our ’22 development which increases our working interest in those wells from 64% to 100%. We really like this opportunity, and we estimate the PV-10 value of the incremental working interest to be approximately $100 million. The ability to execute on this opportunity highlights SilverBow’s operational flexibility. By the end of ’22, this rig will return to its planned liquids development, and we will reserve our balanced strategy of one gas-focused rig and one liquids-focused rig.
Also, in October, we announced the acquisition of 5,200 net acres in our Karnes trough position, which now spans Gonzales, DeWitt and Lavaca counties. I’m happy to report that we successfully closed the acquisition earlier this week. The Karnes trough assets significantly enhance our existing position by adding incremental working interest in new adjacent acreage, which provides for extended laterals, additional drilling locations and more efficient operations. Pro forma for this deal, we have a consolidated 13,000 net acre block, which now has 100 high rate of return locations spanning the Eagle Ford and Austin Chalk. We plan to allocate capital to this area early next year.
This has been a banner year for the Company, and we have significant momentum to build on for the remainder of the year and into 2023. SilverBow’s growth trajectory is driven by strong execution by our operational and business development teams as they drill high rate of return projects and make accretive acquisitions.
Having covered our recent results, I would now like to outline our multiyear strategic objectives and the road map ahead.
Our first objective is to drive double-digit growth while living within cash flow. Using 2022 as a baseline, we expect to grow production and EBITDA by more than 25% annually over the next two years. This growth will be governed by a reinvestment rate below 75% with free cash flow used to pay down debt.
Subject to reinvestment rate and leverage thresholds, we have contingent capital earmarked to deploy a third rig in the second half of 2023 in our Karnes trough area. With the addition of a third rig, we have visibility towards reaching a key scale target of over 0.5 billion cubic feet equivalent per day of production.
Our second key objective is portfolio expansion. SilverBow has added over 350 drilling locations year-to-date through acquisitions and currently has well over a decade of inventory life. As of today, 2/3 of our locations are oil-weighted, representing a major shift from SilverBow’s historical inventory mix and highlighting the meaningful change accomplished through our strategic A&D activity.
A core tenet of our strategy going forward will be to maintain a minimum inventory life of 10 years as we focus not only on sustaining but building scale. We believe the Eagle Ford remains an opportunity-rich area to add additional inventory as we’ve done in the past. We believe we can unlock additional potential through multiple avenues, including grassroots leasing, acquisitions and identifying stacked pay potential on existing acreage.
Our third key objective is to lead our peers in capital efficiency and cost structure. As shown on Slide 16 of our corporate presentation, SilverBow has one of the lowest breakeven costs across the domestic landscape. Additionally, as shown on Slide 17, SilverBow has drilled half of the top 50 Webb County gas wells.
Furthermore, favorable Gulf Coast pricing allows us to realize prices close to or above benchmarks and to deliver consistently higher netbacks. And finally, we have one of the lowest G&A platforms in the industry as we estimate next year’s per unit cash G&A to fall below $0.10 per Mcfe.
Our fourth objective is to delever our balance sheet and increase liquidity. Through September 30, we have funded $300 million in cash acquisition payments while simultaneously increasing liquidity by over $60 million and holding leverage flat from year-end. Through cash flow generation and debt reduction, we are targeting long-term leverage between 0.5 turn and 1 turn.
With these multiyear objectives in mind, we have provided an updated ’23 guidance. Our outlook incorporates the most recent acquisitions and third quarter production updates. We are raising our ’23 production guidance to average between 400 to 420 MMcfe per day with EBITDA of approximately $700 million.
As we settle into a leverage ratio below 1x next year, we’ll have contingent capital to deploy a third rig. As I mentioned earlier, this will accelerate our ability to build greater scale. We continue to see the highest near-term reinvestment opportunities through the drill bit and accretive acquisitions, with share repurchases being the priority of our future shareholder returns program.
Last, but not least, I’m excited to share that SilverBow will be publishing its inaugural sustainability report in the first half of next year. As a company that prides itself on operating in a responsible manner with steadfast transparency, we look forward to sharing our ESG best practice commitments, initiatives and goals.
With that, I will turn the call over to Steve to provide an operational update. Steve, please go ahead.
Steve Adam
Thank you, Sean. In the third quarter, we drilled 15 net wells and completed and brought online 11 net wells. The increase in our quarterly well counts reflects the addition of our second drilling rig in July. As Sean mentioned, the third quarter marks a key inflection point in SilverBow’s growth trajectory.
In our Webb County gas area, we had a full rig running throughout the quarter. We completed and brought online a two-well San Roman pad located on our recently announced Dorado acreage block. One of the wells on this pad targeted the Austin Chalk and represents the seventh and best-performing Chalk well that SilverBow has drilled to date. This two-well pad achieved an IP30 of 30 MMcf per day and continues to confirm our view of unlocking additional inventory in the Austin Chalk as we transition to full-scale development.
As shown on Slide 18 of our presentation, our Chalk wells pay back in less than a year and generate rates of return well above 100%. We also completed and brought online a three-well pad which is yet to reach 30 days of production and is performing above expectations.
In our central oil area, we also had a full rig running throughout the third quarter. We completed and brought online a two-well pad which had been drilled by the previous operator prior to SilverBow taking ownership on June 30. As noted in our press release, the performance from these wells has exceeded expectations, delivering an IP30 of 2,400 BOE per day with a 94% liquids cut. Additionally, we completed and brought online a three-well pad and are encouraged by the early results as we approach 30 days of production.
Third quarter production of 299 MMcfe per day was at the midpoint of our guidance, with our gas and NGL production at or above the high end of the range. Third quarter oil production fell below our guidance range. Early in the quarter, we experienced cycle time delays due to drilling inefficiencies and casing problems from the previous operator. The well with the casing problem has been temporarily abandoned. These transitory issues, in combination with underperformance from a non-operated pad brought online during the third quarter, drove quarterly oil volumes below our initial expectations.
For the fourth quarter, we are guiding to production of 322 MMcfe per day at the midpoint, with natural gas representing 70% of our production mix. Our guidance implies a 5% to 10% production increase sequentially in the fourth quarter. Incorporated in the fourth quarter guidance range is previously unscheduled plant maintenance on third-party systems. It is anticipated that these maintenance projects will impact dry gas volumes out of Webb County during the quarter. As Sean noted earlier, we plan to return to one gas rig and one oil rig by year-end.
Our updated full year 2022 CapEx guidance is $320 million to $340 million. We estimate the addition of the 12 Fasken wells into our drilling schedule, together with the recent land and leasing spend in Webb County to comprise roughly $30 million of incremental capital to our budget. It is worth noting that our full year CapEx guidance only increased $15 million at the midpoint as our team continues to find cost efficiencies elsewhere in our program.
Looking to 2023, our production forecast of approximately 400 to 420 MMcfe per day represents a 50% increase year-over-year. Roughly half of that increase is attributable to the acquisitions we have closed over the course of 2022. Our capital budget next year is expected to range between $450 million to $550 million, with the higher end reflecting the potential third rig added in our Karnes trough area in the second half of next year. As always, SilverBow optimizes its drilling schedule in real time to allocate capital to our highest return projects based on prevailing commodity prices, production timing and expected rates of return.
As has been discussed throughout the industry, cost inflation continues to move operating and capital expenses higher. We estimate costs are up approximately 25% year-over-year across all major basins. On the drilling side, the largest cost increases continue to come from casing, day rates, fuel and cement. On the completion side, horsepower logistics, sand and fuel are seeing the most pressure. Furthermore, the labor market remains tight across the service sector, which typically results in service-provided challenges. We experienced similar efficiency challenges with the rig we added back in July. After taking control of operations, the rig returned to expected efficiency levels, and we believe these issues to be transitory.
The SilverBow team continues to set the standard for safety amongst our peers. We again achieved a zero total recordable incident rate for the quarter. As we double the size of our drilling program, safety remains our top priority in the field. To all of our employees, contractors and service partners, thank you for upholding this core pillar of SilverBow’s culture.
With that, I will turn it over to Chris.
Chris Abundis
Thanks, Steve. In my comments this morning, I will highlight our third quarter financial results as well as our price realizations hedging program, operating cost and capital structure.
Third quarter oil and gas sales were $242 million, excluding derivatives, with natural gas representing 70% of production and 62% of sales. During the quarter, our realized oil price was 100% of NYMEX WTI. Our realized gas price was 95% of NYMEX Henry Hub, and our realized NGL price was 36% of NYMEX WTI. Our price realizations in line with benchmarks highlight SilverBow’s competitive advantage operating in the Gulf Coast markets.
Our realized hedging loss on contracts for the quarter was approximately $84 million. Nevertheless, SilverBow’s hedge book will strengthen over time as it rolls off below-market hedges and continues to lock in strong project returns with new hedges at attractive prices.
Based on our hedge book as of October 28, for the remainder of 2022, we have 167 MMcf per day of natural gas hedged, 8,400 barrels per day of oil hedged and 3,750 barrels per day of NGLs hedged. For 2023, we have approximately 180 MMcf per day of natural gas hedged, 7,300 barrels per day of oil hedged and 3,750 barrels per day of NGLs hedged. The hedged amounts are inclusive of both swaps and collars and include the assumptions of existing hedge books from our recent acquisitions. A detailed summary of our derivative contracts is contained in our presentation and 10-Q filing for the third quarter, which we expect to file later today.
Turning to cost. Lease operating expenses were $0.65 per Mcfe. Transportation and processing costs were $0.35 per Mcfe. Production and taxes were 5% of oil and gas sales. Cash G&A, which excludes stock-based compensation, was $3.2 million for the quarter. As we continue to add scale to the Company, a function of both organic and acquisitive growth, we do not anticipate a meaningful increase to our G&A. Rather, we expect G&A on a per unit basis to decline compared to historical ranges. Our third quarter cash G&A was $0.11 per Mcfe on a unit basis, which is roughly half of our unit cost in 2021. We consider our lean cost structure to be a differentiator, allowing SilverBow to sustain profitability during periods of volatile commodity prices.
Adjusted EBITDA for the third quarter was $115 million. As reconciled in our earnings materials, we recorded a slight free cash flow deficit for the quarter. Excluding $6 million of opportunistic leasing free cash flow would have been positive. Capital expenditures for the quarter on an accrual basis totaled approximately $110 million. This excludes acquisitions and divestiture activity.
Turning to our balance sheet. Total debt was $630 million. Higher adjusted EBITDA in the third quarter was offset by cash payments for deals associated with our Dorado position as well as the cash deposit for our Karnes trough acquisition, which together totaled $50 million. We funded these cash payments using our credit facility and operating cash flow. Irrespective of the cash outlay for land and acquisitions, we paid down $14 million of debt quarter-over-quarter. As of September 30, we had $295 million of availability under our credit facility and $2 million of cash on hand, resulting in $297 million of liquidity.
SilverBow in accordance with our credit facility includes contributions from closed acquisitions for the entirety of the LTM adjusted EBITDA period used for the leverage ratio calculation. On an LTM basis, for the period ending with the third quarter of 2022, the contributions from acquired properties totaled approximately $139 million, bringing our LTM adjusted EBITDA for covenant purposes to $495 million and our quarter end leverage ratio to 1.27x. Impressively, SilverBow has maintained a flat leverage ratio since year-end 2021 while funding over $350 million in cash acquisition payments. At the end of the quarter, we were in full compliance with our financial covenants and has sufficient headwinds.
With that, I will turn it over to Sean to wrap up our prepared remarks.
Sean Woolverton
Thanks, Chris. SilverBow continues to execute on its differentiated growth strategy. Between organic growth and in-basin consolidation, the Company is positioned for significant value creation going forward. We are prime for double-digit growth as we march towards our longer-term scale target of over 0.5 billion cubic feet equivalent per day of production. In the near term, a key catalyst for our stakeholders will be our industry-leading commitment towards safety and clean operations and the release of our inaugural sustainability report in the first half of next year.
As we find ways to increase cash flow and pay down debt, we continue to see the highest return on investment through the drill bit and accretive acquisitions. With production growth, debt reduction and a conservative reinvestment rate, our liquidity position should expand over time, providing us the dry powder to stay opportunistic in further consolidation within the basin.
I want to thank all our stakeholders for their continued support. We look forward to providing further updates on our next call.
And with that, I will turn the call back to the operator for questions.
Question-and-Answer Session
Operator
[Operator Instructions] Your first question is from Neal Dingmann of Truist Securities.
Neal Dingmann
I’m just wondering, could you talk a little bit on allocation between — you’ve talked a little bit in the press release about your Webb County play. Obviously, I like the returns on the gas side and, obviously, future Karnes trough. Just wondering how you think about allocation specifically in ’23 there.
Sean Woolverton
Yes, Neal, during the first half of ’23, we’ll plan to allocate half of the capital to Webb County and half of the capital to our oil locations, areas which include central oil and the Karnes trough area, so 50% to each area with one rig operating in each area. During the second half of ’23, as we move to three rigs, we see 2/3 of the capital will be allocated to liquids oil properties, both across our central oil area in the Karnes trough area and 1/3 of the capital allocation going to Webb County gas.
Neal Dingmann
And Sean, maybe just talk about M&A opportunities going forward, specifically as it relates to the Eagle Ford, obviously, after the big deal we’ve seen last night.
Sean Woolverton
Yes. Over the last four to five months, there’s been actually a couple large publicly announced transactions in the Eagle Ford as well as some private transactions that didn’t get announced. But in all of them, we feel like it’s a really good read-through to SilverBow and that they traded at valuations that would demonstrate the upside value that SilverBow has. So those announcements show that the Eagle Ford continues to be a great place to own assets.
In terms of go-forward inventory, we continue to see a tremendous amount of runway there. There remains a large inventory of private operators that have been in the basin and their investments for quite a long period of time. And we continue to have discussions with them amongst marketed deals as well as we look to continue to add deals. And so yes, we think that there’s a ton of runway going forward, and you’ll continue to see transactions occur in the Eagle Ford.
Operator
Your next question is from Charles Meade of Johnson Rice.
Charles Meade
I was wondering if I could start by asking about the Webb County, I guess, third-party midstream constraints. I guess, two questions. You upped your guide for ’23. Can you talk about what is implicit in that guide about the duration of those midstream constraints that you’re seeing?
Sean Woolverton
Yes. I appreciate the question. So as we look into ’24 and what’s implicit in the guide up in production, first is the activity in the fourth quarter and specifically, the increase of our working interest in our Fasken properties that resulted in 4.5 net wells, that essentially really drives an early production growth for us going into the first quarter of next year. So getting those higher net volumes due to the increased working interest is driving that growth early into next year. So that’s where that’s really being driven from.
In terms of the issues that we’re seeing out of Webb County, at this point in time, the maintenance is occurring throughout November and potentially early December. So we expect those to be resolved early into next year. But with that said, we’ll continue to watch. There’s been a tremendous amount of supply growth in Webb County.
And so infrastructure, for the first time in a long time, in that area is now starting to reach capacity. There’s future expansions being planned and one that’s been publicly announced out of Webb County. So I foresee that we get into early next year, and we shouldn’t see these constraints, but we’re also keeping a close eye on Webb County supply and takeaway capacity, and we’ll need to be doing that over the next quarters.
Charles Meade
Got it. That is helpful detail. And then as a follow-up, I want to ask about the third rig. And I think you addressed, in broad terms, how you’re going to approach that third rig. But I wonder if you could elaborate a little bit on the time line for your decision, like whether you’re going to have to decide at the end of 1Q to bring it on for the middle of the year. And then just maybe share a little more specifics on the key indicators you’re going to be looking at to decide whether you bring that third rig on.
Sean Woolverton
Yes. Great question. We are always in the market assessing rig availability, really around making sure that we have competitive pricing for our rigs. So Steve and his team are always looking at rig availability, and we have great dialogue with a number of service providers. So we’ll usually be — like you said, 90 days out in front of a decision and starting to get those rigs lined up. So it’s really in and around the end of the first quarter, early part of second quarter, that we’ll probably be looking at making a decision going forward with the third rig.
Criteria to make that decision, first, we plan to drill two wells early next year on our Karnes trough position. These will be longer laterals. We plan to target one in the Austin Chalk, one in the Eagle Ford, just to confirm the acquisition assumptions that we’ve made, that the reservoir is going to be as good as we anticipate and generate the returns we’re expecting. So that will be the first criteria.
Second will be commodity prices. If commodity prices remain where they’re at, those returns will be pretty substantial. So that will be the next check that, hey, commodity prices justify the returns to invest capital. And then the third is just the balance sheet. We want to again expect that we’ll be delever below one turn as we get into the early part of next year and move towards 0.5 turn mid- to late year. So that’s the last check that will make that, hey, the balance sheet is where we want it before we accelerate more capital spend.
Operator
Your next question is from Tim Rezvan of KeyBanc Capital Markets.
Tim Rezvan
Charles kind of stole my first question on the rigs, so I appreciate the color there. So I guess related to that 2023 commentary you provided, you talked about a 2023 EBITDA number of $700 million. Can you just kind of tell us what commodity prices sort of underwrite that outlook?
Sean Woolverton
Yes. That’s really strip pricing as of early to mid-October and it reflects our hedge book at that time as well. So that number may move around as we put on additional hedges as we go into ’23 and if strip prices changes, but that’s the assumptions that were used to generate that number.
Tim Rezvan
Okay. And then if I could, I guess, you haven’t really announced any capital return. You gave a little bit of color on repurchases. And I know it’s theoretical at this point. So I guess my question is, as a small-cap company with a really big kind of growth runway, why would you consider this at all at this time in your company’s growth stage? And why that form is what I’m getting at.
Sean Woolverton
Yes. Good question. And we agree that we continue to think the best returns on capital are, first and foremost, through the drill bit at these commodity prices. So that’s where we’ll continue to allocate the majority of the capital in through accretive acquisitions. And we fully believe that to continue to unlock value for SilverBow and to recognize higher valuations as we trade at a discount, scale is the primary driver there. So we do believe that’s where to put our investment.
As we think about going forward, one of the things that we’ll consider is just the volatility of our stock. We see some volatility in our stock as part of our acquisition program. We’ve put shares out to folks that we bought assets from. And so we think a shareholder — or a share repurchase program could be helpful to manage overhang in the stock going forward. And that would probably be the first use of share buyback program, is to kind of ensure that if the stock is pressured down due to some overhang selling, we’d support it with buybacks.
Tim Rezvan
Okay. And is there a certain threshold when you would maybe look to the board and gains for that? Is that leverage target an absolute debt target?
Sean Woolverton
Yes. We haven’t finalized the program. We’re signaling that it’s something that we’re thinking about, but we haven’t formally approved it. So right now, it would be, like I said, geared around where we’re at from a leverage standpoint, a liquidity standpoint, but don’t have like specifics that we’ve put in place yet as we’re still working on deciding if we formally announce and put the program in place.
Tim Rezvan
Okay. That’s helpful. And then if I could go back on that topic of debt and leverage, based on that strip pricing scenario and the parameters you put around 2023, how do you see leverage at the end of 2023 playing out? Under the two or three rig kind of scenarios, have you gone through that math? Or is there a certain target in place?
Sean Woolverton
Yes. As we thought through these questions that we’ve received around leverage, it’s always been, hey, you’re tracking towards 0.5 turn, and what do you do once you get there. Along the way, right, we’ve continued to find accretive acquisitions to do that periodically will drive that leverage up a little bit, and we saw that here in the third quarter with the transactions that we did all in cash. So I would tell you, our objective is probably to live within 0.5 turn and 1 turn. As we look at next year, and get towards the end of the year, it’s probably within that range, probably towards the middle to the lower side of that range.
Tim Rezvan
Okay. And then if I could sneak one more in, the Sundance acquisition obviously did quite a bit to diversify your inventory. But kind of given — you talked about the well failure on that acquisition, was that a due diligence issue? Was that something complete out of the blue? And I guess how do you think about like — I’m sorry, I’m rambling a bit. But what’s your kind of postmortem review of what happened and how you can kind of avoid that issue going forward given you’re clearly going to be acquisitive?
Sean Woolverton
Yes. No, great question. It was something we would view as a one-off. The wells on that pad were extended laterals that had a trajectory change in the middle of the lateral, something that, I think, in-house, we would have probably recognized that, that potentially would be creating a stress on the casing upon pressuring up at the beginning of the frac, it could cause a failure. And that’s what happened.
So yes, in retrospect, as you encounter this on any acquisitions, it’s working with the operator you’re acquiring from to really due diligence everything that’s part of the transaction but that’s ongoing from an operational standpoint as well. So we do, again, view it as a one-off. Could have we avoided it? Probably not. Two of the three wells didn’t fail, so we think it was just a one-off occurrence unfortunately.
Operator
Your next question is from Donovan Schafer of Northland Capital Markets.
Donovan Schafer
So I want to ask about the opportunity with the non-op partner, how you were able to increase your working interest. Is this something — it’s clearly kind of a great opportunity in this place where you feel really good about the quality of the block and the acreage and everything. So this is a case where, I guess, to me, I’m guessing it was kind of a no-brainer.
But I’m wondering if kind of going forward, if there are other dynamics where you see other opportunities like this, whether it’s with the same non-operator, maybe not, being in a position to — doesn’t have the cash available right now or other different non-operators around where you can — like just sort of the pricing environment or whether these are other companies that are global and are worried about other recession things or something and conserving cash. Is there like an opportunity out there to go after drilling locations where you can kind of essentially force the hand of someone else to maybe pass that on to you and allow you to gross up your interest?
Sean Woolverton
Yes. For the most part, it’s a limited opportunity set for us, and that’s driven by, pretty much across all of our asset base, we have nearly 100% working interest. So this happens to be one area on our Fasken block where we have 2/3 working interest in. Our partner has a 1/3 working interest in. And you characterized it correctly. I think it’s not that they feel like it wasn’t a great capital investment opportunity. It was through their budget process, they were limited in their ability to allocate capital to the increased activity late in the year. So we see that as probably a unique one-off occurrence for us.
Donovan Schafer
Okay. And then for the third rig for 2023, how far along are you in terms of kind of negotiations for that rig and just like the degree of confidence and visibility you have on what kind of a rate you could get? Or I guess presumably, you’re looking at the economics, and there’s an implicit assumption around what the associated drilling costs would be, and then even maybe talking about the frac rig too, I know you kind of lock in the rig for a period, sometimes there’s an aspect of that with the frac crews. So how far along are you in negotiations and how much confidence you have around those economic assumptions for that step-up in bringing on the rig?
Sean Woolverton
Yes. Something that just being a very active operator, we’re in-market always assessing rig availability and other service providers’ availability across our capital program. It’s something that we’re not actively negotiating on yet. We still have plenty of time there. But it’s something that we’ll take into consideration, right? Hey, we’re a returns-driven company. So in order to allocate capital and put it to work, it needs to meet favorable return thresholds. If the cost of the wells reach a point where the allocation is not justified, then we’ll back away from it. Right now, the current cost of picking up a rig and availability, we think that’s going to be there. And so that’s why we’re planning for it accordingly. But we’ll adjust as necessary.
And what’s nice is we have plenty of flexibility. Right now, the production guidance that we gave, that $420 million a day, reflects the third rig being added. That really drives growth into ’24. But I mean, we’re already growing 50% next year. So if we happen to slide that back down to two rigs and only run the two rigs to the year, we’re still going to have one of the largest growth trajectories of any of our peers, and then we’ll revisit where returns are at in ’24. So I think we’re positioned well to have flexibility around our decision to add the third rig.
Donovan Schafer
Okay. That’s great. And then for this winter and kind of how you’ve directed the two rigs to focus on gas and with timing of fracking and bringing them online and stuff, it seems like this is all around — it’s partly about the quality of the actual asset and those returns you can get just, in some way, sort of in the abstract. But it also seems like you guys have this view that you’ll be getting better winter pricing near term, this winter, with large volumes of gas you get with initial production.
So I’m kind of curious in general, if this is one of the common practices where you would see this, for instance, just being repeated in the future, in future winters. Or do you feel like you have a sort of differentiated view about specifically the gas prices at the hubs you’re selling into specifically this winter? And then do you see that as kind of a pure upside to that gas price exposure? Or there’s a certain amount of that, whatever that incremental would be, mitigated by hedging?
Sean Woolverton
Yes. No, from practice by the Company, this is something that we have, in the past, employed as well. That’s what we love about the Eagle Ford, and our position is we can move operations around and capital allocation around in a very short order. We love the Eagle Ford that you can drill gas one week and oil the next week. So we’ve employed this practice in the past to ramp our gas production into the fourth quarter and first quarters to take advantage of winter pricing. And it’s also we’re very bullish on gas prices over the winter and long term as well. So yes, it’s something that we have employed in the past and we’ll probably keep as a strategy going forward as well.
Donovan Schafer
Okay. Great. Well, that covers it for me. I’ll follow up off-line with any other questions.
Sean Woolverton
Okay. Appreciate it, Donovan. Have a good day. Thank you.
Operator
We have completed the allotted time for questions. I will now turn the call over to Sean Woolverton for closing remarks.
Sean Woolverton
Again, operator, thank you for moderating the call. I appreciate everyone’s interest in the Company, and we look forward to updating you on our next call.
Operator
This concludes today’s conference call. Thank you for your participation. You may now disconnect.
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