Q4 2022 Western Midstream Partners LP Earnings Call
If you'd like to ask a question. During this time simply press star followed by the number one on your telephone keypad. If he would like to withdraw your question again Presti Star one. Thank you I would now like to turn the conference over to Daniel Jenkins Director of Investor Relations. Please go ahead.
I'm glad you could join us today for Western Midstream 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 <unk>. Most recent Form 10-K, and other public filings for a description of risk factors that could cause actual results to dish.
For 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, one will be available on our website.
March 9th hard copies will be mailed out several days later with me today are Michael here, our Chief Executive Officer, and Kristine Schulze, 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 D. J basin declines the capital investment necessary to complete the construction of mentor train three and the growth capital needed to support continued throughput growth expected in 2024 also I'm very.
Pleased to announce that we have recommended it 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 had been in.
<unk> and positioning <unk> 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 Menton train three we executed multiple long term amendments with Occidental to their natural gas processing and crude oil treating agreements supported by minimum volume commitments in.
In aggregate. These amendments provide up to 500 million cubic feet per day of incremental peak firm processing capacity and up to 57000 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 surface 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 N 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 Menton train three to fulfill these future obligations.
I am pleased to report that the construction of Menton train three 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.
Actions in the second half of 2022 the acquisition of our partner's 50% equity interest in the ranch West tax 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 two crude oil pipeline for 265 million.
Which included approximately $2 million of pro rata distributions through closing these transactions.
<unk> were in line with our M&A philosophy of allocating capital towards accretive transactions and increasing our processing stack in the Delaware Basin.
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.
<unk> <unk>, 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 and base distribution payments.
We retired $504 million of senior notes and 20 twenty-two driving our year end net leverage ratio to three one times well below our year end threshold of 3.4 times.
In January 2023, where you retired $213 million of floating rate senior notes.
Our next debt maturity comes due in 'twenty twenty-five 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 out activity will reduce future based distribution obligations by approximately $39 million in aggregate on an annualized basis, we've recommended to our board that they consider it an enhanced distribution payment based on our strong 20 twenty-two 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 three one 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 to therefore, we recommended that the board uses discretion and consider what.
Is 2022 net proceeds from asset sales of $224 million as cash flow available for distribution when it formally considers an enhanced distribution in April .
Based on these considerations, we expect to announce an enhanced distribution of $140 million or approximately 36 cents per unit based on current unit count outstanding to be paid in conjunction with our first quarter 'twenty twenty-three 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 unit holders and to further differentiate worse relative to our midstream peers.
With that I will turn the call over to Kristin.
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 Elliot.
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.
It was primarily due to the divestiture of cactus two that closed in early November excluding the sale of cactus to 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 natural gas assets decreased by six cents compared to the prior quarter. This.
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 20 cents compared to the prior quarter, primarily due to the divestiture of tactics to equity messaging.
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.
A 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 too.
Our per barrel adjusted gross margin for produced water assets decreased by two cents 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 one.
During the first quarter, we generated net income available to limited partners of $329 million and adjusted EBITDA of $516 million relative to the third quarter 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 residue and NGL volumes combined with lower overall residue and NGL pricing.
During the fourth quarter. We also recorded revenue recognition cumulative adjustments associated with re determined 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 us.
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 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.
Third quarter also included field level of 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 base distribution of <unk> 50 per unit paid on February 13th.
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 why 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 676000 barrels per day, an increase of 3% compared to full year 2021.
Full year 2022 produced water throughput averaged 836000 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, and 2022 or per Mcf adjusted gross margin for natural gas assets average $1.32 an increase of eight cents year over year. This was primarily due to strong plant performance and contract mix leading to increased retail.
And residue and NGL volumes, coupled with higher commodity prices. Additionally, throughput increase at the West, Texas complex, which is a higher than average per mcf margin compared to other natural gas assets are per barrel adjusted gross margin for crude oil and NGL assets averaged $2.46 an increase of 18 cents year over year. This was primarily due to.
To increase 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.
Mahler negative impact related to the cumulative catch up adjustment for certain cost of service contracts at the D. J basin oil system relative to 2021 and an increase in distributions from cactus to our per barrel adjusted gross margin for produced water assets averaged 94 cents an increase of one said year over year as Michael previously mentioned, we recorded the highest net.
And adjusted EBITDA in the history of our partnership in 2022, generating $1.19 billion and $2.128 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 her.
Residue and NGL volumes, coupled with higher overall commodity pricing.
This position west 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 are.
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 Menton train three that included costs moving into 2023, our free cash flow generation totaled.
One point to six $8 billion in 2020 to 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 as 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 in our mid twenties 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 to which accounted for an average of approximately 65000 barrels per day to us in 2022.
In the Delaware Basin, we expect average year over your throughput to increase across all three products due to an increased number of wells coming online in 2020 three 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 serviced as projected incremental volume in 2024, and the D. J basin. We continue to expect average year over year throughput 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 lids.
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 an converted certain natural gas processing agreements from actual recoveries to fixed recoveries for several customers during the first half of 2020 two.
Based on these new contracts and contract amendments, we are providing our portfolio wide commodity price sensitivity analysis for 2023.
Analysis of Sands expected recovery elections in normal plant operating conditions at it includes our commodity price exposure through our legacy per cent of proceeds and keep whole contracts as well as these fixed recovery contracts.
2022 is an incredibly successful year operationally and financially for west as we grew adjusted EBITDA by 9% compared to 2021 or.
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 a 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 D. J basin and the impact from the sale of cactus to Additionally, we expect reduced efficiency fee revenue associated with our Maverick basin assets in South, Texas and with the exploration of certain long term minimum volume commitments at our Chipita.
In Utah.
As we look to 'twenty 'twenty, four and beyond we expect to reduce deficiency fee revenue from our Maverick basin assets. However, we do not anticipate any material minimum volume commitment exploration on our owned assets.
Finally, we expect the D J 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, 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.
<unk> of Menton train three.
We came in below the low end of our 2022 capital guidance range, mostly due to capital associated with Menton train three moving into 2023. Additionally, we expect to have slightly higher maintenance capital associated with our expanded asset base, which includes the ranch West Tex acquisition.
Taking both our adjusted EBITDA and capital expenditure guidance into account, we expect to generate free cash flow between 1.125 to one point to two $5 billion in 2023 weeks.
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 'twenty 'twenty four will be based on our full year 2023 financial performance.
Earned 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 Thanks Kristen.
We are pleased with our consistent effort to return capital to stakeholders through debt retirement unit repurchases in distributions since becoming a standalone organization.
Since our January 2020, senior notes issuance and through year end 'twenty 'twenty. Two we have now retired $1.65 billion of senior notes or 21% of the aggregate debt balance and reduce our net leverage ratio to 3.1 times 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 standalone organization at the beginning of 2021.
We've now paid out a total aggregate amount of $1.97 billion in base distributions since the first quarter of 'twenty 'twenty, including the increase to the base distribution of 53% at the beginning of 2022.
As of December 31st 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 unit holders since our January Twenty-twenty senior notes issuance, which excludes any mark.
Kit driven appreciation and our current unit price west 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.
West 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, West continues to screen as one of the most attractive investment opportunities within the midstream and energy space. Additionally.
Additionally, when looking at total capital return yield, which focuses specifically on distributions and buybacks west has materially outperformed its midstream peers large cap publicly traded midstream companies in the market as a whole we continue to be the market leader in generating a superior total capital return yield by using a ban.
<unk> 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.
What are the primary ways that west demonstrates this leadership is through our generation of strong returns on capital employed west is in the top three amongst our midstream peers in 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 west is 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 become.
<unk> a standalone organization in early 'twenty 'twenty, we've also reduced our net leverage ratio from 4.6 times in early 'twenty 'twenty to 3.1 times at year end 2022.
Additionally, west as the leader in generating strong returns on total assets relative to our midstream peers in 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 West is well positioned despite recent market volatility west is on strong.
Long 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 2020, two and approximately 76% of our fee based revenues included either some type of fee escalation or protection from inflation through our 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.
Additionally, we will remain focused on our balanced capital return framework, which will further position west as a leader in total capital returned 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 position our organization for great success in 2020, three and beyond with that we'll open the line for questions.
At this time I would like to remind everyone in order to ask a question Press Star then the number one on your telephone keypad.
And your first question comes from line of Spiro <unk> from Citi. Your line is open.
Afternoon, guys.
Let's start with the outlook beyond 2023.
And then just a finer point on it so if I look at your Delaware business.
Appears to be growing double digits.
So it looks like it's a bit odd.
Rather we didn't see that translate more.
EBIT growth in Christian you laid out a few factors there and it sounds to me kind of a temporary nature that it kind of really overshadowed that group. This year. So I guess I'm curious have you looked at 2024.
And I realize it's far away at this point you just gave pretty clear guidance, but would you expect a lot of those headwinds thinking things like NBC explorations, you touched on that a bit to really get paid to the point, where we can start to see more meaningful EBITDA growth show up.
Hi, Spiro. This is this is Michael good question, a couple of things I would point to there.
The the deficiency fee loss that you experience 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 on line in 2023.
You know far exceeding what we saw in 2022 and a good portion of those should trail into volume growth as we 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 twenties on the water side growth in 2023.
Which again will provide should provide some tailwind into 2024.
Great.
Mike Thanks for that.
Secondly, just thinking about the enhanced distribution for next year and then 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 or the enhanced distribution.
So maybe just a good time to just remind us about how you guys are thinking about buybacks. This year kind of what the trigger point is for for you to go ahead and execute on those and whether or not that is 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've repurchased 61 million units, which based on.
Todays price about $1 $6 billion worth of total value overall that we've done through unit repurchase program we've seen.
Positive results.
Based on that.
Our buyback program as a whole obviously we've been to.
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 wood.
Come into the enhanced distribution impact I mean again, the spirit of the enhanced distribution was and so 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 unit holders. We've got a commitment that we're going to return all of our free cash flow back to the unit holders and so.
That's either through debt reduction share repurchases and if there isn't an opportunity during the year then well then we intend to pay that back and enhanced distribution.
Got it helpful color, Michael I'll hop back in the queue. Thanks, guys. Thanks Carol.
Your next question comes from the line of Keith Stanley from Wolfe Research. Your line is open.
Hi, good afternoon, and thank you.
First just it.
So curious if there's any way to think about the financial impact this year of Offloading gas in the Permian as I imagine Youre doing a fair amount of that and how to think about the uplift when menton three starts up in 2024, and you don't have to pay to to offload anymore, and then Relatedly just latest thoughts on when you might start.
Thinking about moving forward on another processing plant at <unk>.
Seemed like based on the volume growth that you would fill mento, three up pretty fast and potentially need to start offloading again in 'twenty four.
Yes, Keith both good questions. So we do expect to have a margin impact in 2023 related to the outflows as part of the reason why.
We're expecting to have slightly lower margin in 23 versus <unk> versus 'twenty two.
And so that margin uplift would not be there and as much as we're not utilizing those outflows in 2024 months meant on three 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.
Based on today's world, it's probably not too far into the future where additional processing capacity for us will be necessary.
Thanks, that's helpful.
Second one just a small one but given you talked to the D. J 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 pretty sure forecasts are increasing so can you just give some updated thoughts on where you see the DJ volumes going you did reference it bottoming in midyear or your producers now, saying greater activity and a better outlook over the next few years or just whats.
The latest view there, yes, Keith that's exactly what it is that we're hearing I think you started to see a lot of.
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 too.
For people to work through the process to understand how it might function and thus far people who've been successful getting approvals and so as a result.
I think your observation is exactly correct around.
Our producers being more optimistic around what is it they can do there again, you're saving also we're expecting to stave off the decline in the DJ During 2023 and then.
The impact on cost of service is a reflection of a.
Future expectations of increased volumes overall in the DJ as a whole.
Keith I think if you take a look to the materials that we provide including the capital break out you'll see that year over year step change in the capital in the D. J. This is Paul Thats further supporting.
Michael comment there.
Thank you.
And again, if you would like to ask a question Press Star then the number one on your telephone keypad.
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 just wanted to qualitatively make sure that I have all the.
The commodity exposure.
Covered so it looks like you have some GMP commodity exposure in Wyoming and Utah.
The liquids yields exposure in the Delaware and could.
Could you remind me where the crude exposure would be and if I'm missing anything else on the G&P side.
Yes, Neal 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 C. III plus is that we actually measure on an oil linked basis, and so thats, where youre seeing the sensitivity from a from a crude perspective instead of breaking out each of the individual components.
We looked at it on an oil link basis in order to demonstrate the potential commodity price exposure there, but you had it exactly correct on.
The gas, which is why theres very little.
From a gas price perspective.
Some of the legacy contracts in the Rockies and then any component of seed to excess recoveries for <unk> two in the Delaware and DJ basins.
Got it. Thank you and then my second question.
The impact of of Cactus to sale was approximately 30 million if I heard right.
That's not flowing into 2023 and no that wasn't 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 ranch Tech acquisition with the roughly 100 million.
Cubic feet, a day of additional capacity to use.
Yes, Neal it's good question, we don't we don't really measure because it is a full processing system as a whole.
We don't actually measure that measure it that way, it's a part of a fully tied in Prague.
Processing infrastructure throughout the entire basin. So at any point in time will flow volumes.
Two bone spring to Ramsey too Armento implants, and so when you think of it as a as a complex as a whole.
Yes, I got it.
Yes.
Michael perspective.
Going back to my earlier comment you can look back at the appendix with the Pie chart back there and just see how much at the asset level EBITDA is coming from the Delaware Basin, and that's going to be inclusive of what you are talking about right there.
Yes.
Got it and just a follow up to that it looks like you know there is a possible.
Other.
JV, where you could buy out the partner to get additional.
Processing capacity with an Mi Vida plant.
Would you consider acquisitions like that or is this meant to I'm sorry, 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 with either its other.
M&A opportunities that are out of our assets are we're always actively looking at that and so you saw.
2022 were.
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 all the color.
Thank you.
And there are no further questions at this time, Mr. <unk> 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. One again, thank all of 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.
Please wait the conference will begin shortly.
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