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. [Operator Instructions] 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 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.

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…

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…

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…

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

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.

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.

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?

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.

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

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?

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.

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?

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.

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.

Thank you.

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

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?

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.

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?

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.

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.

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?

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.

Got it. Thank you for the call.

And 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. 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.

This concludes today's conference call. Thank you. You may now disconnect.