Western Midstream Partners, LP (WES) Q1 2022 Earnings Report, Transcript and Summary

Good afternoon. My name is Celina, and I will be your conference operator today. At this time, I would like to welcome everyone to the 1Q ‘22 Western Midstream Partners Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the conference over to Daniel Jenkins, Director of Investor Relations. Please go ahead.

Thank you. I’m glad you could join us today for Western Midstream’s first quarter 2022 conference call. I’d like to remind you that today’s call, the accompanying slide deck and last night’s earnings release contain important disclosures regarding forward-looking statements and non-GAAP reconciliations. Please reference Western Midstream’s most recent Form 10-Q and other public filings for a description of risk factors that could cause actual results to differ materially from what we discuss today. Relevant reference materials are posted on our website. With me today are Michael Ure, our Chief Executive Officer; Kristen Shults, our Chief Financial Officer; and Craig Collins, our Chief Operating Officer. I’ll now turn the call over to Michael.

Thank you, Daniel, and good afternoon, everyone. Yesterday, we reported another quarter of strong financial performance. We generated net income available to limited partners of $302 million and record-breaking adjusted EBITDA of $539 million, representing a sequential quarter increase of 27% and 12%, respectively. Taking a closer look at our first quarter results, the sequential quarter EBITDA increase was driven by the following factors. First, our contracts with minimum volume commitments and associated deficiency payments helped support our gross margin, despite volume declines across the portfolio relative to the fourth quarter. These declines were the result of well completion timing and weather impacts in the Delaware Basin, as well as expected declines in the DJ Basin and on our equity method investments. Craig will extend on throughput shortly. Second, we also entered into and converted certain natural gas processing agreements from actual recoveries, to fixed recoveries for multiple customers during the first quarter. As a result of strong plant performance leading to actual recoveries exceeding the contractually specified recoveries, we’ve retained excess natural gas liquid volumes in the Delaware Basin under these contracts. Therefore, these additional volumes along with high commodity prices led to an increase in gross margin, despite a decrease in throughput. Third, we realized lower operational costs during the first quarter relative to fourth quarter and our first quarter expectations. Compared to fourth quarter, we realized a 12% reduction in operational and maintenance expense, primarily due to lower utility costs, which is typical during the first quarter, lower equipment rental expense and reduced land costs associated with our produced-water business and a 13% reduction in general and administrative expense, primarily due to reduced corporate expense and lower contract labor cost, which fluctuates from quarter-to-quarter. Additionally, in the fourth quarter of 2021, we recorded $26 million of unfavorable revenue recognition cumulative adjustments associated with lower cost of service rates, predominantly at the DJ Basin oil system, which we did not see in the first quarter of 2022. Turning to cash flow. Our first quarter cash flow from operations totaled $276 million, which declined compared to the prior quarter, in large part, due to normal working capital changes, specifically changes in accounts receivable. Free cash flow totaled $200 million and free cash flow after the fourth quarter distribution payment in January totaled approximately $66 million. I’m incredibly pleased with our financial results this quarter, and I’m even more excited about our team’s success in creating additional value for WES. As Craig will discuss shortly, the team executed numerous contracts in both, the Delaware and DJ Basins that will generate incremental adjusted EBITDA in 2022 and beyond. I’d like to highlight a few of these recent successes in the Delaware Basin. First, we executed long-term amendments to Occidental’s gas processing agreement, increasing their firm capacity on our system. Second, we executed a new long-term gas gathering and processing agreement with ConocoPhillips to provide firm capacity for dedicated volumes on our system. Lastly, we added a new publicly traded customer to our gas and water portfolio, highlighting our ability to service multiple product lines in the basin. These new long-term agreements, along with increased producer activity levels support our need for additional gas processing capacity and solidify our decision to sanction a new 300 million cubic feet per day gas processing train at our existing Mentone plant, which is part of our West Texas complex. With this expansion, WES will be one of the top three gas processors in the Delaware Basin. The combination of our premier infrastructure, our ability to provide a three-stream midstream solution to producers and our continued success in expanding business with our existing customers and with new third-party customers solidifies us as a leading midstream provider in the Delaware Basin. Our exposure in the Delaware Basin is a competitive advantage relative to our peers, and we are excited to play an integral role in the growth of the basin in the country’s energy production as a whole. I’ll now turn it over to Kristen, who I would like to formally welcome as our newly appointed Chief Financial Officer, to discuss our financial performance. Kristen?

Thank you, Michael. We recently declared a first quarter cash distribution of $0.50 per unit payable on May 13th. This distribution represents a 53% increase over the prior quarter’s distribution and is consistent with the previously announced annualized base distribution target of $2 per unit. We continued to reduce leverage, ending the quarter with a net debt to trailing 12-month adjusted EBITDA leverage ratio of 3.3 times, and we expect to further reduce our net leverage as we continue to generate strong adjusted EBITDA and significant free cash flow. Additionally, on April 1st, we retired $502 million of senior notes. With this retirement, we’ve now retired $1.65 billion of senior notes or 20% of the aggregate debt balance since our January 2020 bond issuance. The market environment resulted in limited opportunities to execute on our $1 billion unit buyback program. Thus, we repurchased approximately 225,000 units for aggregate consideration of $5.1 million in the first quarter of 2022. Since January 2020, we have repurchased 41.7 million units or just over 9% of our unit count. On a per unit basis, we’ve now returned $5.24 through debt retirement and unit repurchases and $3.31 in distribution for a total of $8.55 returned to unitholders since the onset of the pandemic, which excludes any market-driven appreciation in our current unit price. We are committed to employing a balanced approach regarding capital allocation by retiring debt, increasing the distribution and returning excess cash to unitholders through the unit buyback program or potentially through an enhanced distribution. We continue to return value to stakeholders while adapting to the rapidly changing environment. Based on our performance this quarter and our updated expectations for the remainder of this year, we have reevaluated our previously announced 2022 guidance. As such, we’re revising our adjusted EBITDA, capital expenditure and free cash flow guidance ranges. Specifically, we expect adjusted EBITDA to range between $2.125 billion to $2.225 billion, an increase of $200 million to the midpoint from our previous guidance range of $1.925 billion to $2.025 billion. We expect a meaningful increase in rig activity and additional wells to come on line during 2022 in the Delaware Basin as compared to prior expectations. We also expect volumes associated with the new ConocoPhillips agreement to come on line during the first half of this year. We anticipate the strong plant performance we experienced during the first quarter to continue throughout this year. To the extent commodity prices remain elevated, we expect to generate incremental gross margin associated with the retained excess natural gas liquid volumes in the Delaware and DJ Basin. Volumes associated with an amended processing agreement with DCP Midstream and the DJ Basin, which Craig will discuss later in more detail, are already flowing and generating incremental adjusted EBITDA. We expect total capital expenditures to range between $550 million to $600 million, an increase of $150 million to the midpoint from our prior guidance range of $375 million to $475 million, due to additional well connect and expansion capital, which includes a portion of the capital needed to build Mentone Train III. We expect free cash flow to range between $1.250 billion to $1.350 billion, an increase of $50 million to the midpoint from our prior guidance range of $1.2 billion to $1.3 billion. The distribution guidance of at least $2 per unit remains unchanged. With that, I’ll now turn the call over to Craig to discuss our operational performance. Craig?

Thank you, Kristen. On a sequential quarter basis, natural gas throughput decreased by 3%. This decrease was primarily due to reduced throughput in the Delaware Basin due to well completion timing and instances of inclement weather during the quarter, lower expected volumes at our DJ Basin complex and on our equity method investments, and production declines in our other operated assets. Our crude oil and natural gas liquids throughput decreased by 4% on a sequential quarter basis, primarily due to lower volumes at the DBM oil system resulting from well completion timing and weather impacts as well as lower expected volumes in the DJ Basin and from our equity method investments. Produced-water throughput decreased by 5% on a sequential quarter basis due to decreased volumes at the DBM water system, primarily from lower production related to well completion timing and weather impacts. Our per Mcf adjusted gross margin for our natural gas assets increased by $0.08 relative to fourth quarter 2021, primarily due to strong plant performance and contract mix at the West Texas and DJ Basin complexes. These factors led to increased product recoveries and coupled with higher commodity prices resulted in increased gross margin. Our per barrel adjusted gross margin for our crude oil and natural gas liquids assets increased by $0.66 on a sequential quarter basis. This was primarily due to the annual cost of service rate adjustment that decreased revenue during the fourth quarter of 2021 at the DJ Basin oil system and the treatment of lease revenue under the operating and maintenance agreement with Occidental at the DBM oil system that was terminated effective December 31, 2021. We estimate the impact of the cost of service rate adjustment in the fourth quarter at the DJ Basin oil system was $0.47 per barrel. Additionally, deficiency fees recorded in the first quarter led to a higher per barrel adjusted gross margin than originally expected. Our per barrel adjusted gross margin for our produced water assets increased by $0.08 relative to last quarter, primarily due to deficiency fees recorded in the first quarter of 2022. As Michael mentioned earlier, we achieved significant commercial success in both, the DJ and Delaware Basins in the first quarter, particularly in our gas business. I want to thank all of our employees who are involved for their hard work in creating the substantial value for WES. In the DJ Basin, we executed a multiyear amendment to DCP’s gas processing agreement, providing an additional 60 million cubic feet per day of firm processing capacity fully backed by a minimum volume commitment with DCP retaining the right to increase their firm space by another 40 million cubic feet per day. This amendment highlights the creativity of our commercial team to cost effectively maximize throughput at our processing facilities. While we expect these volumes to help offset a portion of the forecasted gas throughput decline in the DJ Basin, we still expect both oil and gas volumes to decrease for the year, primarily due to the delayed development associated with the current permitting environment. We continue to maintain open dialogue with our producers and provide the necessary support as they navigate the permitting process. I’d like to point out that despite our declining volume outlook within the DJ Basin, our expected financial performance for the year underscores the strength and stability of the minimum volume commitment and cost of service contract structures we have in place. Turning to the Delaware Basin. We executed a long-term gas gathering and processing agreement with ConocoPhillips to provide up to 150 million cubic feet per day of firm capacity on our system to service dedicated volumes. By leveraging our expansive infrastructure, we secured the significant additional dedication that generates a high return and supports ConocoPhillips’ ongoing development of the acreage. Capital requirements are limited and are included in our 2022 capital guidance. We’re excited to grow our existing relationship with ConocoPhillips and to support their long-term success in the Delaware Basin. Throughout the quarter, many of our producers revisited and adjusted their drilling programs in light of the sustained high-commodity price environment. Both private and public customers are increasing activity on the acreage we service, which demonstrates confidence in our ability to provide flow assurance and competitive value for their products. Producers have recognized the need for additional capacity on our systems to support their growth and processing needs as capacity in the basin tightens. Our commercial teams have worked diligently to put the appropriate agreements in place. One such agreement signed this quarter was with Occidental. We executed long-term amendment to their existing gas processing agreement to provide an additional 250 million cubic feet per day of firm processing capacity supported by up to 200 million cubic feet per day of minimum volume commitments. This amendment reflects new firm commitments for volumes that were previously forecasted as well as newly anticipated volumes, demonstrating Occidental’s long-term commitment to allocating capital to the areas in which we operate and exemplifies the strength and foundation of our relationship. We’re excited to be their midstream provider of choice and continue to support their success in the Delaware Basin for years to come. The aggregate of our commercial success and the anticipated incremental throughput in 2022 has led us to update our outlook for our expected year-end exit rate percentage increases across the portfolio. We now expect water to grow by low-20s, gas by mid-single-digits and oil by low-single-digits. Our recent commercial success and increased producer activity levels in 2022 and beyond, underpin the need for additional processing capacity at our West Texas complex. Therefore, to secure additional capacity, our teams evaluated multiple options and thoroughly reviewed each to ensure we utilize capital in the most efficient manner possible. As a result, we are adding incremental capacity through the sanctioning of a new cryogenic gas processing train at our Mentone plant and the execution of offload agreements with third-party processors. The initial design and construction of the Mentone plant had already incorporated plans for a third processing train, making this expansion cost-effective relative to a new greenfield construction project. Mentone Train III will operate with a nameplate capacity of 300 million cubic feet per day, and we anticipate it to be operational in the fourth quarter of 2023. We believe increasing operated capacity in the Delaware Basin reflects our long-term commitment to our producers and further cements our position as a leading midstream service provider in the basin. While Mentone Train III is under construction, we have secured additional capacity through offload arrangements with third-party processors with excess capacity in the basin. These offload agreements are both economic to WES and further demonstrate our track record of taking actions to benefit our unitholders. A combination of our strong long-term commercial agreements backed by producer commitments and dedications and the overall tightening of processing capacity in the Delaware Basin, all contributed to us sanctioning Mentone Train III. Turning to our capital budget for the year. Our needs for 2022 relative to when we issued guidance have changed due to our commercial success and the expected increase of volumes onto our systems in the Delaware Basin. Therefore, as Kristen outlined earlier, we have provided revised 2022 capital guidance of $550 million to $600 million, which is an increase of $150 million to the midpoint of the prior guidance range. We continue to expect that the Delaware Basin will receive the majority of our capital spend for 2022 or about 80% of our total forecasted budget. Our expected spend on expansion capital has increased to 66% to account for this year’s portion of spending from Mentone Train III as well as the additional infrastructure necessary to service anticipated increased volumes. I’d now like to turn the call back over to Michael. Michael?

Before we open it up for Q&A, I would like to emphasize how WES and its unitholders are extremely well positioned to benefit from the greatly improved operating environment. Since becoming a standalone enterprise, we have focused on lowering our overall cost structure and increasing operational efficiencies, leading to increased opportunities to enhance existing relationships as well as attract new business. We have attracted additional volumes from legacy customers, including Occidental and ConocoPhillips. These meaningful agreements will be drivers of throughput growth and profitability for years to come. We’ve added new third-party customers, bringing approximately 15 customers into our water and gas portfolios. Our strong asset base, specifically in the Delaware Basin, allows us to capitalize on increasing producer activity levels. We were the first in the industry to focus on free cash flow generation, and we use that free cash flow to meaningfully derisk our enterprise through leverage reduction. We have been a leader in creating shareholder value through a balanced approach of capital return without putting our balance sheet at risk. As of quarter end, relative to various publicly traded midstream companies, WES leads in proportional debt reduction since January 2020. This has resulted in the lowest debt-to-EBITDA leverage ratio when taking into account the $502 million senior note maturity we retired in April of 2022. Additionally, WES leads in total units repurchased since January 2020, taking advantage of opportunistically repurchasing a significant amount of equity over the past couple of years. The distribution has also remained a core component of our capital return program. This has resulted in one of the highest aggregate payout since January 2020 as a percentage of enterprise value. WES still remains one of the highest yields even without taking into consideration the opportunity for a potential enhanced distribution, which is also the first of its kind in the industry. I truly believe that WES is firing on all cylinders and is now able to better capitalize on the improved operating environment to generate strong returns for our unitholders and to return incremental capital to stakeholders. I’d like to close by extending my appreciation to the entire WES workforce. All of our teams have worked tirelessly to enable recent commercial successes, ensure our system reliability remains high, and maintain excellent customer service, while staying focused on safely reducing costs. Our first quarter performance provides a strong start to the year and sets us up for great success for the remainder of 2022 and beyond. With that, we’ll open the line for questions.

[Operator Instructions] The first question comes from Spiro Dounis with Credit Suisse. Please proceed.

First question, Michael, maybe starting with commercial. You highlighted those two deals with Oxy and Conoco. And one of your Delaware peers last night also highlighted about 400 million cubic feet a day of new MVCs and also made a decision to increase processing capacity. So I don’t want to say it’s a trend or anything, but it seems like sort of a sudden acceleration of commercial activity. And a lot of us are sort of under the impression that a lot of this acreage has kind of already been dedicated. So, surprising to sort of see this all at once. So curious, I was hoping to get your view, maybe give us a sense on whether or not there’s kind of a growing shadow backlog out there if deals coming or is this kind of it for now?

Well, I’m definitely -- and thanks for the question, Spiro. I’m definitely not going to say that there aren’t new opportunities coming. We definitely continue to look for additional opportunities as it arises. But I think you are highlighting the incredible opportunity that exists within the Delaware Basin as it relates to potential volume growth coming out of it. I mean, just to highlight how significant that is for us, 400 million a day of new additions, a 30% increase on the volumes that we saw through our processing stack during the first quarter, that’s just in one quarter the additions that we were able to achieve. And that in and of itself, if all we did was process those increased commitments, it would have us approaching a top 10 position in total processing in the Delaware Basin. So, what you’re referring to there is an enormous amount of potential that exists for growth coming out of the basin and the opportunity that the WES is very well poised to be able to capitalize on.

Great. Second one, maybe for you, Kristen, just on capital return, a bit of a two-part question. But you’ve got this improved outlook now. And so, one, I was just curious to get your latest thoughts on how to think about the enhanced distribution and what that could look like later this year and early ‘23? And then, also on the buybacks, you did about $5 million this quarter. But I guess, I’m curious how much of a factor was it that you still had to repay the $500 million of senior notes? In other words, with that prepayment or repayment behind you now in April, does that sort of internally free you up to do more on opportunistic buybacks for the rest of the year?

Yes, so why don’t I go ahead and take that, and then Kristen, please feel free to add on as you see fit. You did highlight the key factors that we took into consideration in addition to just general overall market dynamics. But we had $500 million debt reduction paydown that we did on April 1st. We’re also in the midst of looking at our capital program for the year in light of the commercial successes that we were having. And so, you’re talking about a $150 million increase in capital on $500 million debt reduction. And so, it was prudent for us to take that into consideration in addition to normal market conditions as it relates to the buyback. But obviously, as my prepared remarks referenced, the buyback has been something that we have been utilizing very, very effectively over the past little while, industry-leading and being able to utilize the buyback program. So, it’s obviously a core component of how we think about potential return of capital. As it relates to the enhanced distribution, these updated guidance figures very much put as a potential opportunity and enhanced distribution to be paid in 2023. We think it’s a really exciting development in a lot of the successes that we’ve had this quarter and expect for the remainder of the year and very much was core to a thought about the financial policy for our unitholders to be able to get rewarded for the successes that we’re able to achieve during each annual year.

Your next question comes from the line of Colton Bean with Tudor, Pickering. Please proceed.

Just on Oxy’s call earlier, I think they mentioned some permitting delays in the DJ and the potential to reallocate activity to the Delaware as a result. So, maybe a two-part question for you. First, I wanted to confirm that was contemplated in the guidance update? And second, is that activity reallocation actually margin accretive, just given the broader scope of operations you have in the Delaware?

Go ahead, Kristen.

Yes. So, that was contemplated in the guidance that we just came out with and the revised guidance, not only the increase from the public side, like you’re seeing from Oxy on that acreage, but also on the private side, too. We’ve seen just increased activity from many of our providers on the acreage that we service. In general, it’s just along with that increase, we expect additional gross margin to come from the Delaware, 50% of our EBITDA for this year to come from the Delaware. And the capital spend that we’re spending, the majority of that is coming from the Delaware as well and really setting us up for what we see to be a really great 2023 as well.

And maybe just to follow up on that. On a like-for-like basis, if you had the option to put a rig in the Delaware versus the DJ, do you all have a preference, I guess, in terms of impact to your overall margins?

I think overall, they’re both great returning basins for us. The DJ, just from a capacity standpoint, we’ve got additional capacity in the DJ. And so, that’s always great to be able to fill out those plants and keep them full up what a midstream provider would like. So -- but the Delaware is a very competitive basin and where we’re seeing a lot of the growth coming from too.

Okay, great. And then, maybe on Mentone III, it seems like with the new processing agreements announced and then the offload capacity available to you in the interim, would you expect to bring Mentone III on at a fairly high utilization rate?

Yes. We anticipate Mentone III coming on line late 2023. And when it does come on line, we do expect it to be pretty full from the outset. And we’re continuing to monitor what our processing needs are going to look like going forward. And based on the recent success that we’ve had and the continued improvement or increased activity levels from our producers as well as new opportunities that I expect that we’ll be able to source and add to the portfolio. And we’re already starting to look at what else we may need beyond Mentone III.

Your next question comes from the line of Chase Mulvehill with Bank of America. Your line is open.

I guess, first question, do you have a view on natural gas egress bottlenecks in the Permian next year? And maybe if you see some tightness evolving in the first half of next year, what steps do you think you can take to be able to best manage any potential constraints in the Permian?

Yes. I think, we expect to see more of those constraints in 2024 and beyond. But I think in the interim, should there be some episodic tightness in the downstream takeaway markets. I think what we’ll naturally pivot towards is making sure that we’re recovering all the ethane that we can in order to lean out the residue gas streams. And I think that the physical volumes are going to be able to move out of the basin. I think it’s more of a pricing issue, particularly near term. There’s pipes going out to the West Coast, not really where molecules prefer to go from an economic standpoint. But physically, I think they’ll be able to move that way. And we have many of our larger producers take their resi gas in kind and make their own downstream marketing commitments, and we work with the balance of our customers to market their production or their residue on their behalf. And we’ve got a third-party marketer that we work very closely with, and we’re watching those downstream markets and really what -- how that situation may evolve. But I think we’ve seen here of late that there’s been a couple of expansions announced. I think an additional one is probably pending shortly. So, we’ll -- and those should be shorter turnaround expansions of the takeaway capacity. So, that should help.

Okay. Kind of a related follow-up. I guess, we’re now all the way through earnings season or midstream earnings season, and we’ve seen a lot of midstream companies add processing capacity in the Permian. And it’s hard for us to see exactly how much has associated MVC contracts with the capacity additions. But, it does seem like that the midstream companies are setting themselves up for significant production growth in the Permian. But, this significant growth actually is a bit contrast to what we’re hearing from at least public E&Ps. So, I guess, given -- do you feel like that the midstream is getting a different message from the E&P industry than what the market expects? In other words, do you think that the market should be set up for significant growth in the Permian, or do you think that there’s going to be more disciplined? And because I just -- we’re seeing all this capacity being added, but we keep hearing from E&Ps that they’re going to be more disciplined?

Yes. A couple of comments I would make there, and it’s a great question. First is, you obviously have to take into consideration a lot of the private companies. And frankly, a lot of them are of meaningful scale at this point and the acceleration of their development programs have been continued and strong and definitely don’t show any sign of reduction according to the conversations that we’re having. The second thing I would just make mention of is that when the upstream companies talk about visible, they’re very much talking about that really on a portfolio basis, right? And so, what you have to take into consideration is, are they reallocating capital to some of the highest return areas. And so, for us, where we take a look at the Delaware Basin as being in our footprint as being in the heart of the core of the core, if you have a limited amount of capital, you’re trying to utilize that capital to some of the shorter cycle development programs and in some of the best areas where you have an acreage position. And so, while definitely there has been a great sense of discipline from an aggregate basis, you really have to take it into consideration where that capital is being allocated -- allocated to. And so as we have conversations with our customers, where that capital seems to be finding its home is in the areas where we have core assets within the Delaware Basin.

Really helpful. If I could squeeze one more in real quick and just thinking about commodity exposure. And I know you disclosed that you’ve got 93% fixed-based gas contracts and 100% fee-based liquids contracts. But not sure on some of these contracts, if you have fee floors that provide you some commodity price upside? So, I guess, maybe if you could answer that or just maybe if you don’t want to answer that, then you think about the raise ‘22 EBITDA guidance of $200 million, how much of that was volume based versus commodity based?

Yes. So, I guess, there was a factor for both, obviously, that went into it. The vast majority of it, however, was an increase in activity, as we talked about. In addition to the -- just to add on top of the prepared remarks that we referenced, in some of our gas processing contracts where you have a fixed recovery rate in as much as we operate those plans more efficiently than what that fixed recovery rate would indicate, then the excess volumes are to our account. And so -- and as much as we continue to operate those plants more effectively, still a fixed fee as it relates to that processing contract. However, the excess, if there is some, as we continue to operate our plants more efficiently, that does come in the form of increased volumes for us and for our account. And so there is incremental commodity exposure from that standpoint despite the fact that it is still a fixed fee contract. Craig, is there anything else you’d add there?

Yes. I think the contract that you may be really asking about is I know some of our competitors, for example, may have a have a key -- or a percent of proceeds type contract structure with a minimum floor that’s fee-based. And that’s really not how our contracts are structured. They are predominantly overwhelmingly fee-based in terms of the economics they deliver. And then there’s just some additional economics on top to as Michael pointed out, to the extent we recover a higher percentage of the NGLs than what we owe the producer through the fixed recovery components in the contracts. But, the overwhelming majority is from the fee component versus having a highly variable component.

[Operator Instructions] Your next question comes from the line of Michael Cusimano with Pickering Energy Partners. Please proceed.

I wanted to follow on Colton’s question earlier on the DJ permitting. Just curious if you’re seeing similar issues in the DJ with any of your other operators, or if this is Oxy specific to the way they went about their planning process?

Yes. I wouldn’t say it’s Oxy specific. I think it really comes down to the specifics around the areas in which each of the producers is operating up there. Obviously, there’s a lot of urban development in the Greater Denver area. And I think the proximity of that urban development relative to the undeveloped acreage is really the key criteria for how those permitting processes go. And so I think some producers have had a lot more permits approved, I think, through the last few months, but I think they’re also probably much further removed from the urban development. And so, there just aren’t nearly as many concerns. And so, I think it really is less operator-specific and more acreage specific. And so, I think as they outlined, they’ve learned through the permitting process, and they’re optimistic about what that looks like going forward. And I think their comments speak for themselves.

Your next question comes from the line of Ned Baramov with Wells Fargo. Your line is open.

So, spending on Mentone III will likely continue throughout most of next year and you also noted increased producer activity in the Delaware. So, could you give us a rough indication of what is a good CapEx range for 2023? Or asked differently, do you still expect ‘23 spending to be lower than 2022 as some of the system investments you’re making this year will not be part of the budget next year?

Yes. I mean, we increased our 2022 capital program, as you saw. And that increase is really attributable to capital that we brought forward into 2022 to support the increase in activity levels that we see coming at us both this year as well as next year. And then, of course, the other large contributor to that capital increase for 2022 was based in the 2022 spend for Mentone III. And as you point out, that capital spend on the plant expansion will continue through the first three quarters or so of 2023. And as far as what 2023 looks like, I think we’ve outlined our program for this year, and we continue to update our outlook based on producer engagement. And I think it’s too early to tell what 2023 is going to look like, but we’re very encouraged by the overall levels of activity that we’re seeing, the producer commitment to developing acreage in and around our system. So frankly, it’s a pretty good time to be operating assets where we are.

That makes sense. And I guess, staying on Mentone III, could you maybe talk about the terms of the contract that underpin this facility and just broadly whether the economics are comparable to the economics of processing investments that you have made in the past?

Yes, great question. Ned, the way that we take a look at this, first of all, it becomes a part of our broader complex. And so, it services volumes that we have throughout the area, not necessarily just tied to a specific or a small group of contracts. The way that we look at it is that we set ourselves a threshold of a mid-teens hurdle rate. And this project, as we look at it, exceeds that hurdle rate. And so, we’re really excited about the opportunity, not only to grow into the future as this obviously points towards and our comments have highlighted there, but while growing at a really great rate of return.

There are no further questions at this time. Mr. Ure, I turn the call back over to you.

Thank you, everyone, for joining the call. I would like to reiterate my thanks to the employees for an excellent quarter and for the opportunity set that we have in front of us. As I mentioned in our prepared remarks, we’re really excited about the opportunity and prospects that we have and feel really great about the position that we find ourselves in and firing on all cylinders. So thanks, everyone, for this call, and look forward to speaking to you on the second quarter call in a couple of months’ time.

This concludes today’s conference call. You may now disconnect.