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Presentation

Operator: Good afternoon. My name is Rob, and I will be your conference operator today. At this time, I would like to welcome everyone to the Western Midstream Partners’ Fourth Quarter 2022 Earnings Conference Call. I would now like to turn the conference over to Daniel Jenkins, Director of Investor Relations. Please go ahead.

Daniel Jenkins: Thank you. I’m glad you could join us today for Western Midstream’s fourth quarter and full year 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-K 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. Additionally, I’m pleased to inform you that Western Midstream Partners’ K-1 will be available on our website beginning March 9. Hard copies will be mailed out several days later. With me today are Michael Ure, our Chief Executive Officer; and Kristen Shults, our Chief Financial Officer. I’ll now turn the call over to Michael.

Michael Ure: Thank you, Daniel, and good afternoon, everyone. We are pleased to report another strong year of operational and financial performance at Western Midstream as we recorded the highest net income and adjusted EBITDA in the history of our partnership. We announced our 2023 guidance, which is primarily driven by continued throughput growth in the Delaware Basin, offset by DJ Basin declines. The capital investment necessary to complete the construction of Mentone Train III, and the growth capital needed to support continued throughput growth expected in 2024. Also, I’m very pleased to announce that we have recommended an enhanced distribution to our Board of Directors that, if approved, would be paid in conjunction with our first quarter 2023 base distribution in May, all of which I will discuss in more detail later in the call.

Before we discuss our fourth quarter results in more detail, there are several accomplishments in 2022 that have been instrumental in positioning WES for future growth and success. Specifically, our commercial teams created tremendous value for WES and built the foundation necessary to proceed with the decision to sanction Mentone Train III. We executed multiple long-term amendments with Occidental to their natural gas processing and crude oil treating agreements, supported by minimum volume commitments. In aggregate, these amendments provide up to 500 million cubic feet per day of incremental peak firm processing capacity and up to 57,000 barrels per day of peak firm treating capacity on our infrastructure. We expect volumes associated with these amendments starting in 2023 and growing over the coming years.

We also executed a long-term agreement with ConocoPhillips to service dedicated volumes and provide firm capacity on our system. We have already benefited from this agreement in 2022, and we anticipate ConocoPhillips to remain one of our largest natural gas G&P customers over the coming years. In aggregate, our teams achieved great commercial success with third-party producers throughout the year. By year-end 2022 in the Delaware Basin, third-party volumes accounted for approximately 56% of our natural gas throughput as compared to 52% at year-end 2021 and 20% of our produced water throughput as compared to 13% at year-end 2021. These commercial successes increased our confidence in sustainable volume growth and the need for Mentone Train III to fulfill these future obligations.

I’m pleased to report that the construction of Mentone Train III is progressing according to our initial expectations and should be operational by the end of fourth quarter 2023. We also executed a letter of intent with Occidental last year with the objective of pursuing opportunities to produce and deliver low carbon intensity oil and gas products to market through the development of carbon dioxide capture, transportation, utilization and sequestration opportunities in and around our existing asset bases in the Delaware and DJ Basins. Our teams continue to evaluate ways to create value for both organizations, and we look forward to updating you on our progress later this year. We also executed two notable M&A transactions in the second half of 2022.

The acquisition of our partner’s 50% equity interest in the Ranch Westex natural gas processing facility for $40 million, which is already tied into our West Texas Complex and the sale of our 15% interest in the Cactus II crude oil pipeline for $265 million, which included approximately $2 million of pro-rata distributions through closing. These transactions were in line with our M&A philosophy of allocating capital towards accretive transactions and increasing our processing stack in the Delaware Basin. Additionally, upon closing the sale of Cactus II, we increased our unit buyback program to $1.25 billion, demonstrating our commitment to creating additional value for our unitholders through our capital return framework. This time last year, we refined our financial policy and established our enhanced distribution structure.

And in 2022, we executed on this capital return framework by increasing our base distribution retiring debt and buying back almost 50% of our initial three-year unit buyback authorization amount, which was subsequently increased by $250 million within the first year. Specifically, we increased the base distribution by approximately 56% to $2 annualized per unit beginning with our first quarter 2022 base distribution that was paid in May of 2022. In calendar year 2022, we paid out an aggregate amount of $736 million in base distribution payments. We retired $504 million of senior notes in 2022, driving our year-end net leverage ratio to 3.1 times, well below our year-end threshold of 3.4 times. In January 2023, we retired $213 million of floating rate senior notes.

Our next debt maturity comes due in 2025. With this recent retirement, all of our remaining senior note obligations are fixed rate. In 2022, we repurchased 19.5 million units for aggregate consideration of $488 million at an average price of approximately $24.96 per unit. This included the repurchase of approximately 1.6 million units for aggregate consideration of $41 million in the fourth quarter of 2022. We estimate that our 2022, unit buyback activity will reduce future base distribution obligations by approximately $39 million in aggregate on an annualized basis. We have recommended to our Board that they consider an enhanced distribution payment based on our strong 2022 financial performance, our current business outlook and our greatly improved balance sheet.

Our consistent efforts over the past several years resulted in net leverage of 3.1 times at year-end 2022. As we look to the future, we expect our adjusted EBITDA and free cash flow generation to remain strong permitting us to continue funding the near-term needs of our business with operating cash flow. Additionally, by repurchasing $488 million of units and reducing net debt by $128 million, we have permanently reduced our annual interest and distribution burden, which more than offsets the loss of free cash flow from the sale of Cactus II. Therefore, we recommended that the Board uses discretion and consider WES’ 2022 net proceeds from asset sales of $224 million as cash flow available for distribution when it formerly considers an enhanced distribution in April.

Based on these considerations, we expect to announce an enhanced distribution of $140 million or approximately $0.36 per unit based on current unit count outstanding to be paid in conjunction with our first quarter 2023 base distribution in May. We view our overall capital return framework and specifically our enhanced distribution as a way to create substantial long-term value for our unitholders and to further differentiate WES relative to our midstream peers. With that, I will turn the call over to Kristen.

Kristen Shults: Thank you, Michael, and good afternoon, everyone. Our fourth quarter natural gas throughput decreased by 1% on a sequential quarter basis, primarily due to lower throughput from certain noncore assets and slightly lower throughput in the Delaware Basin associated with the impact of Winter Storm Elliott. We also experienced lower throughput on our natural gas equity investments during the quarter. Our crude oil and natural gas liquids or NGLs throughput decreased by 9% on a sequential quarter basis. This was primarily due to the divestiture of Cactus II that closed in early November. Excluding the sale of Cactus II, our crude oil and NGL throughput would have decreased by 1% sequentially. Produced water throughput decreased by 3% compared to the prior quarter, primarily due to the impact from Winter Storm Elliot.

Our fourth quarter per Mcf adjusted gross margin for our natural gas assets decreased by $0.06 compared to the prior quarter. This decrease was primarily driven by lower contribution from our retained residue and NGL volumes combined with lower overall residue and NGL pricing as well as contract mix in the Delaware Basin. This was all partially offset by a favorable revenue recognition cumulative adjustment recorded in the fourth quarter associated with the higher cost of service rate pertaining to our South Texas asset. We expect our first quarter per Mcf adjusted gross margin to be in line with the fourth quarter. Our per barrel adjusted gross margin for crude oil and NGL assets for the fourth quarter increased by $0.20 compared to the prior quarter, primarily due to the divestiture of Cactus II equity investment.

While throughput declined quarter-over-quarter as a result of the sale, we received distribution payments in early November, which positively impacted the per unit margin. The positive impact was partially offset by an unfavorable revenue recognition cumulative adjustment recorded in the fourth quarter associated with lower cost of service rates at our DJ Basin oil system. We expect our first quarter per barrel adjusted gross margin to increase modestly relative to the fourth quarter, mostly due to the unfavorable revenue recognition cumulative adjustment recorded in the fourth quarter and the impact of the sale of Cactus II. Our per barrel adjusted gross margin for our produced water assets decreased by $0.02 compared to the prior quarter, primarily due to lower deficiency fee revenue.

We expect our first quarter per barrel adjusted gross margin to decrease modestly relative to the fourth quarter, mostly due to a cost of service rate redetermination that became effective on January 1. During the fourth quarter, we generated net income available to limited partners of $329 million and adjusted EBITDA of $516 million. Relative to the third quarter, our adjusted gross margin decreased by $35 million, primarily due to lower overall throughput and the effects from Winter Storm Elliot. Additionally, we experienced less margin contribution from our retained revenue and NGL volumes combined with lower overall residue and NGL pricing. During the fourth quarter, we also recorded revenue recognition cumulative adjustments associated with redetermined cost of service rates on certain contracts.

The overall cumulative impact of these recorded adjustments to fourth quarter, net income and adjusted EBITDA was neutral to WES. But as previously mentioned, the individual adjustments impacted our adjusted gross margin per unit for both our natural gas and crude oil and NGL assets. As expected, we saw a sequential quarter decrease in our O&M expense, primarily driven by lower utility expense associated with lower natural gas pricing and electricity usage and certain maintenance projects shifting into early 2023. The third quarter also included field-level project costs to support our transformation efforts. As we look towards the future, we expect our 2023 O&M expense to trend modestly higher than 2022, primarily due to higher personnel and land-related costs pertaining to our produced water business.

As a reminder, we expect seasonality associated with our utility expense due to greater energy consumption during the summer months. Turning to cash flow. Our fourth quarter cash flow from operations totaled $489 million, generating free cash flow of $366 million. Free cash flow after our third quarter distribution payment in November totaled $169 million. We also declared our fourth quarter cash-based distribution of $0.50 per unit paid on February 13. This distribution is equal to the prior quarter’s distribution and is consistent with the previously announced annualized base distribution target of $2 per unit. Turning to our full year results. Our average throughput portfolio-wide for all three products increased year-over-year. Full year 2022 natural gas throughput averaged 4.21 billion cubic feet per day.

which increased by 1% compared to full year 2021. Full year 2022, crude oil and NGL throughput averaged 676,000 barrels per day, an increase of 3% compared to full year 2021. Full year 2022 produced water throughput averaged 836,000 barrels per day, an increase of 19% compared to full year 2021. These average year-over-year increases were primarily driven by increased throughput in the Delaware Basin in 2022. In 2022, our per Mcf adjusted gross margin for natural gas assets averaged $1.32, an increase of $0.08 year-over-year. This was primarily due to strong plant performance and contract mix, leading to increased retained residue and NGL volumes coupled with higher commodity prices. Additionally, throughput increase at the West Texas Complex, which has a higher than average per Mcf margin compared to other natural gas assets.

Our per barrel adjusted gross margin for crude oil and NGL assets averaged $2.46, an increase of $0.18 year-over-year, this was primarily due to increased throughput and deficiency fee revenues in the Delaware Basin, which has a higher than average per barrel margin as compared to our other crude oil and NGL assets, a smaller negative impact related to the cumulative catch-up adjustment for certain cost of service contracts at the DJ Basin oil system relative to 2021 and an increase in distributions from Cactus II. Our per barrel adjusted gross margin for produced water assets averaged $0.94, an increase of $0.01 year-over-year. As Michael previously mentioned, we recorded the highest net income and adjusted EBITDA in the history of our partnership in 2022, generating $1.19 billion and $2.13 billion, respectively.

Our adjusted EBITDA performance was primarily driven by increased throughput in the Delaware Basin for all three products and strong plant performance. This resulted in a margin uplift associated with retained residue and NGL volumes coupled with higher overall commodity pricing. This positioned WES to deliver operating cash flow of approximately $1.7 billion for 2022. Our capital expenditures totaled $538 million in 2022 and consisted mostly of expansion and well connect capital to support the growing needs of our customers. Our capital spend was below the low end of our 2022 guidance range, in part due to our team’s continued focus on disciplined capital spending throughout the year, some expansion and maintenance projects shifting into early 2023 and a refined construction timeline for Mentone Train III that included costs moving into 2023.

Our free cash flow generation totaled $1.268 billion in 2022, just above the low end of our 2022 guidance range. Our performance highlights our profitable asset base and our disciplined and consistent focus on capital spending. We achieved our full year 2022 base distribution guidance of $2 per unit on an annualized basis. Our ability to maintain a sustainable base distribution is a core component of our capital return framework. As we turn our attention to 2023, we expect our portfolio-wide average throughput to increase year-over-year by a mid-single-digit percentage for natural gas and a mid-20s percentage for produced water. For crude oil, we expect our average year-over-year throughput to increase by a low single-digit percentage after excluding the impact of Cactus II, which accounted for an average of approximately 65,000 barrels per day to WES in 2022.

In the Delaware Basin, we expect average year-over-year throughput to increase across all three products due to an increased number of wells coming online in 2023 relative to 2022. We expect producers to add approximately 340 wells this year in the Delaware Basin, which is a meaningful increase relative to approximately 246 wells that came online in 2022. As a result, we have allocated the necessary amount of expansion and well connect capital into our 2023 capital budget to service this projected incremental volume in 2024. In the DJ Basin, we continue to expect average year-over-year throughput to decline for both natural gas and crude oil and NGLs. We expect our overall natural gas throughput decline profile to continue to shallow out or be less steep consistent with 2022 results.

This is primarily due to the maturity of the wells on our acreage coupled with steady throughput from on loads. For crude oil and NGLs, we still expect our average year-over-year throughput to decline, but we’re expecting an inflection point in the third quarter as additional wells come online in the first half of 2023. As such, we expect crude oil and NGL throughput to begin growing in the back half of 2023. Keep in mind that this increase in crude oil and NGL throughput in the second half will have a minimal impact on our adjusted EBITDA due to deficiency fee revenue we collect associated with minimum volume commitments. As you know, we entered into and converted certain natural gas processing agreements from actual recoveries to fixed recoveries for several customers during the first half of 2022.

Based on these new contracts and contract amendments, we are providing our portfolio-wide commodity price sensitivity analysis for 2023. This analysis assumes expected recovery elections and normal plant operating conditions, and it includes our commodity price exposure through our legacy percent of proceeds and key pole contracts as well as these fixed recovery contracts. 2022 was an incredibly successful year, operationally and financially, for WES as we grew adjusted EBITDA by 9% compared to 2021. Our strong adjusted EBITDA growth was the result of increased throughput in the Delaware Basin, our contract structures that enable us to benefit from the commodity price environment on our retained residue and NGL volumes and diligently managing our cost structure during this period of price inflation.

Turning to 2023 guidance. We expect our 2023 adjusted EBITDA to range between $2.05 billion to $2.15 billion, which implies the midpoint of $2.1 billion. We expect the Delaware Basin to comprise 55% of our asset level EBITDA as throughput continues to grow on our position in the basin. We expect that increased adjusted EBITDA from the Delaware Basin will be partially offset by continued production declines in the DJ Basin and the impact from the sale of Cactus II. Additionally, we expect reduced efficiency fee revenue associated with our Maverick Basin assets in South Texas and with the expiration of certain long-term minimum volume commitments at our Capita facility in Utah. As we look to 2024 and beyond, we expect reduced deficiency fee revenue from our Maverick Basin assets.

However, we do not anticipate any material minimum volume commitment expiration on our owned assets. Finally, we expect the DJ Basin to contribute approximately 29% of our asset-level EBITDA in 2023 with the remaining 16% coming from our equity investments and other noncore assets. We expect our 2023 capital expenditure guidance to range between $575 million and $675 million, implying a midpoint of $625 million. We expect approximately 82% of our capital budget to be spent in the Delaware Basin, the majority of which will be expansion capital, including capital associated with the construction of Mentone Train III. We came in below the low end of our 2022 capital guidance range, mostly due to capital associated with Mentone Train III moving into 2023.

Additionally, we expect to have slightly higher maintenance capital associated with our expanded asset base, which includes the Ranch Westex acquisition. Taking both our adjusted EBITDA and capital expenditure guidance into account, we expect to generate free cash flow between $1.125 billion to $1.225 billion in 2023. We expect to maintain an annualized base distribution greater than or equal to $2 per unit. Also, as a reminder, any potential enhanced distribution payment in 2024 will be based on our full year 2023 financial performance, governed by our year-end 2023 leverage threshold of 3.2 times and subject to the Board’s discretion. I’ll now turn the call back over to Michael.

Michael Ure: Thanks, Kristen. We are pleased with our consistent effort to return capital to stakeholders through debt retirement, unit repurchases and distribution since becoming a stand-alone organization. Since our January 2020 senior notes issuance and through year-end 2022, we have now retired $1.65 billion of senior notes or 21% of the aggregate debt balance and reduced our net leverage ratio to 3.1 time at year-end. From a unit buyback perspective and including the Anadarko note exchange, we have now retired 61 million common units for a total aggregate consideration of $993 million at an average price of $16.28 per unit. This represents 13.7% of the unaffected common unit count since becoming a stand-alone organization at the beginning of 2020.

We have now paid out a total aggregate amount of $1.97 billion in base distributions since the first quarter of 2020, including the increase to the base distribution of 53% at the beginning of 2022. As of December 31, on a per unit basis, we have now returned $6.73 through debt retirement and unit repurchases and $5 in distributions for a total of $11.73 returned to unitholders since our January 2020 senior notes issuance, which excludes any market-driven appreciation in our current unit price. WES generated a substantial amount of free cash flow in 2022, and we plan to continue allocating free cash flow toward debt retirement unit repurchases and distributions in 2023. WES continues to be a market leader in free cash flow yield by maintaining the highest free cash flow yield relative to our midstream peers and large-cap publicly traded midstream companies, the S&P 500 Energy Index and by a wider margin relative to the S&P 500.

When evaluating our current trading valuation from a price-to-earnings perspective, WES continues to screen as one of the most attractive investment opportunities within the midstream and energy space. Additionally, when looking at total capital return yield, which focuses specifically on distributions and buybacks, WES has materially outperformed its midstream peers, large-cap publicly traded midstream companies and the market as a whole, we continue to be the market leader in generating a superior total capital return yield by using a balanced approach between distribution increases and unit buybacks. In addition to distributions and unit repurchases, we have reduced debt, both through open market repurchases and retirements as notes came due, maintaining a balanced approach of overall capital return.

As a result, we are among the leaders in debt reduction relative to our midstream peers and large-cap publicly traded midstream companies. One of the primary ways that WES demonstrates this leadership is through our generation of strong returns on capital employed, WES is in the top three amongst our midstream peers and large-cap publicly traded midstream companies. Over the past several years, our organization has remained focused on increasing profitability, lowering operational and administrative costs, diligently allocating capital, reducing debt and repurchasing units, all of which has resulted in a meaningful increase in WES’s adjusted EBITDA per unit and return on total assets. Relative to 2021, we increased our adjusted EBITDA by 9% and decreased our total unit count by 5% through our concerted effort to repurchase units last year, all of which resulted in adjusted EBITDA per unit increasing 15% year-over-year and approximately 43% since becoming a stand-alone organization in early 2020.

We have also reduced our net leverage ratio from 4.6 times in early 2020 to 3.1 times at year-end 2022. Additionally, WES is the leader in generating strong returns on total assets relative to our midstream peers and large-cap publicly traded midstream companies, which further demonstrates the earnings power and profitability of our asset base. Finally, as we look to the future, WES is well positioned despite recent market volatility. WES is on strong financial footing considering our greatly improved balance sheet and our stable long-term contract structures. In 2022, the majority of our natural gas, crude oil and NGLs and produced water throughput was either supported by minimum volume or cost-of-service commitments. About 93% of our natural gas and 100% of our crude oil and NGLs and produced water throughput were serviced under fee-based contracts in 2022.

And approximately 76% of our fee-based revenues included either some type of fee escalation or protection from inflation through a cost-of-service contract structure. Our contract structures have provided, and we expect will continue to provide financial stability during times of market volatility and cost inflation. Additionally, we will remain focused on our balanced capital return framework which will further position WES as a leader in total capital returns. I’d like to close the call by commending our employees and contractors for their hard work and keen focus on our business objectives throughout 2022. Your commitment and dedication has undoubtedly positioned our organization for great success in 2023 and beyond. With that, we’ll open the line for questions.

Operator: And your first question comes from the line of Spiro Dounis from Citi. Your line is open.

Spiro Dounis: I may want to start with the outlook beyond 2023. And maybe put just a finer point on it. So, if I look at your Delaware business, appears to be growing double digits. And so, it looks just a bit odd overall that we didn’t see that translate more to the overall EBITDA growth. And Kristen, you laid out a few factors there that sounds to me, kind of more temporary in nature that kind of really overshadowed that growth this year. So, I guess I’m curious, if you look at 2024, and I realize that’s far away at this point, you just gave ’23 guidance. But would you expect a lot of those headwinds, thinking things like NBC expirations, you touched on that a bit to really abate to the point where we can start to see more meaningful EBITDA growth show up.

Michael Ure: Hi, Spiro, this is Michael. Good question. A couple of things I would point to there. The deficiency fee loss that you experienced that we are expecting in 2023, we don’t expect to be a material factor in 2024. You also have, as we highlighted in our prepared comments, the number of wells coming online in 2023, far exceeding what we saw in 2022. A good portion of the should trail into volume growth as we go into 2024. So, part of the capital that we’re spending this year is to prepare for volumes to come on in 2024. We’re also talking about mid-single on the gas side, low single on the oil side, mid-20s on the water side, growth in 2023, which, again, will provide — should provide some tailwinds into 2024.

Spiro Dounis: Great. That’s helpful, Mike. Second one, just thinking about the enhanced distribution for next year and looking at your guidance, my math suggests it should be about $200 million left over by the end of the year. to use on buybacks for the enhanced distribution. And so maybe just a good time, just remind us about how you guys are thinking about buybacks this year, kind of what the trigger point is for you to go ahead and execute on those and whether or not that’s kind of a compelling use of cash for you here?

Michael Ure: Well, so we’re big believers in the buyback program. As we highlighted a little bit in the prepared remarks, we repurchased 61 million units, which based on today’s price, about $1.6 billion worth of total value overall that we’ve done through unit repurchase program. We’ve seen a lot of positive results based on that unit buyback program as a whole. Obviously, we’ve been the largest net purchaser over that period of time, demonstrating our optimism around the future of the company. And so, as we look at 2023, we’ll continue to have the same posture to opportunistically utilize the buyback program as we see opportunity out there, which, as you highlighted, would come into the enhanced distribution impact. I mean, again, the spirit of the enhanced distribution was — as we look at our full free cash flow, if we can’t find a better use for it during the year, we’re going to give it back to the unitholders.

We’ve got a commitment that we’re going to return of — our free cash flow back to the unitholders. And so that’s either through debt reduction year repurchases, and if there isn’t an opportunity during the year, then we’ll — then we intend to pay that back and enhance distribution.

Operator: Your next question comes from the line of Keith Stanley from Wolfe Research. Your line is open.

Keith Stanley: Good afternoon. Thank you. First, just curious if there’s any way to think about the financial impact this year of offloading gas in the Permian, as I imagine, you’re doing a fair amount of that? And how to think about the uplift when Mentone III starts up in 2024 and you don’t have to pay to offload anymore? And then relatedly, just latest thoughts on when you might start thinking about moving forward on another processing plant. It would seem like based on the volume growth that you would fill Mentone III up pretty fast and potentially need to start offloading again in ’24?

Michael Ure: Yes, Keith, both good questions. So, we do expect to have a margin impact in 2023 related to the offloads, part of the reason why we were expecting to have a slightly lower margin in ’23 versus ’22. And so that margin uplift would not be there in as much as we’re not utilizing those offloads in 2024 once Mentone III does come online. It’s a great point. And as it relates to future expectations on incremental processing capacity in the basin. It’s really tight right now. And with the expectations of activity levels that we’re seeing on our footprint as well as the basin as a whole, those offload arrangements are becoming fewer and more difficult to find. It’s — based on today’s world, it’s probably not too far into the future where additional processing capacity for us will be necessary.

Keith Stanley: That’s helpful. Second one, just a small one, but given — you talked to the DJ Basin declining in the first half of the year, you said the cost of service adjustment for that basin was a negative, which presumably means producer forecasts are increasing. So, can you just give some updated thoughts on where you see the DJ volumes going? You did reference it bottoming midyear. Are your producers now saying greater activity and a better outlook over the next few years? Or just what’s the latest view there?

Michael Ure: Yes, Keith, that’s exactly what it is that we’re hearing. I think you’ve started to see a lot of different approvals that have come in the basin, both within our footprint as well as other footprints in the area. As we sort of expected, it would take a little bit of time to — for people to work through the process to understand how it might function. And thus far, people have been successful getting approvals. And so, as a result, I think your observation is exactly correct around our producers being more optimistic around what else they can do there. Again, you’re saving off and — we’re expecting to save off the declines in the DJ during 2023. And then the impact on cost of service is a reflection of future expectations of increased volumes overall in the DJ as a whole.

Kristen Shults: And Keith, I think if you take a look to the materials that we provide, including the capital breakout, you’ll see that year-over-year step change in the capital in the DJ that’s all just further supporting Michael’s comments there.

Keith Stanley: Thank you.

Operator: Your next question comes from the line of Neel Mitra from Bank of America. Your line is open.

Neel Mitra: Hi, good afternoon. I appreciate the commodity disclosures. I just wanted to qualitatively make sure that I have all of the commodity exposure covered. So, it looks like you have some G&P commodity exposure in Wyoming and Utah, the liquids yield exposure in the Delaware? And could you remind me where the crude exposure would be? And if I’m missing anything else on the G&P side?

Michael Ure: Yes, Neel, you’ve got it. The crude impact is as it relates to the fixed recovery contracts and any excess volumes in excess of our contractual rates there. For everything that’s C3+ is we actually measure on an oil-linked basis, and so that’s where you’re seeing the sensitivity from a crude perspective. Instead of breaking out each of the individual components, we looked at it on an oil-linked basis in order to demonstrate the potential commodity price exposure there. But you had it exactly correct on the gas, which is why there’s very little impact from a gas price perspective, it’s on some of the legacy contracts in the Rockies. And then any component of C2 excess recoveries for C2 in the Delaware DJ Basins.

Neel Mitra: Got it. And then my second question. The impact of Cactus II sale was approximately $30 million, if I heard right, that’s not flowing into 2023. I know that was an accretive sale. But just looking at the other side, could you possibly quantify what the EBITDA uplift could possibly be from not offloading as much volumes with the Lynch Tech acquisition with the roughly 100 million cubic feet a day of additional capacity to use?

Michael Ure: Yes, Neel, it’s a good question. We don’t really measure because it’s a full processing system as a whole. We don’t actually measure it that way. It’s a part of a fully tied-in processing infrastructure throughout the entire basin. So, at any point in time, we’ll flow volumes to Bone Spring to Ramsey to our Mentone plants. And so, we think of it as a complex as a whole.

Kristen Shults: Yes. I think to further support that from Michael’s perspective, going back to my earlier comment, you can look back at those appendix with the pie chart back there and just see how much of the asset level EBITDA is coming from the Delaware Basin, and that’s going to be inclusive of what you’re talking about right there.

Neel Mitra: Got it. And just a follow-up to that. It looks like there’s a possible other JV where you could buy out the partner to get additional processing capacity with the Mi Vida plant, would you consider acquisitions like that? Or is Mentone III the next processing link?

Michael Ure: We’re always actively evaluating M&A opportunities and, in particular, in areas where we have needs that enhance our business as a whole. So, whether it’s Mi Vida or it’s other M&A opportunities in and around where our assets are. We’re always actively looking at that. And so, you saw in 2022, where we did execute on a couple of those, both on the divestiture as well as the acquisition side. So, we’re always on the look for ways that we can enhance the business from an M&A perspective.

Neel Mitra: Got it. Thank you for the call.

Operator: And there are no further questions at this time. Mr. Ure, I turn the call back over to you.

Michael Ure: Thank you, everyone, for joining the call. It was a wonderful year, 2022 for Western Midstream. We’re really optimistic for the future. I want to again thank our employees and contractors for their extra effort during 2022 and for the future that we have as an organization. Thanks, everyone, for joining the call.

Operator: This concludes today’s conference call. Thank you. You may now disconnect.