Western Midstream Partners, LP (NYSE:WES) Q2 2023 Earnings Call Transcript

Western Midstream Partners, LP (NYSE:WES) Q2 2023 Earnings Call Transcript August 9, 2023

Operator: Good afternoon. My name is Brent, and I will be your conference operator today. At this time, I would like to welcome everyone to the Western Midstream Partners Second Quarter 2023 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] 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 Second Quarter 2023 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 Danny Holderman, our Senior Vice President Southern Operations. I will now turn the call over to Michael.

Michael Ure: Thank you, Daniel and good afternoon everyone. During the second quarter, we experienced increased natural gas and crude oil and NGLs throughput, which was driven by continued throughput growth from our Delaware Basin assets, a recovery in volumes from our assets in Utah and Wyoming and higher throughput from our equity investments. In fact, this was our second consecutive quarter of record-breaking natural gas and crude oil and NGL throughput in the Delaware Basin and the inclement weather that impacted our Utah and Wyoming assets during the first quarter subsided during the second quarter. While our natural gas and crude oil and NGLs throughput, and the associated adjusted gross margin increased on a sequential quarter basis, our adjusted EBITDA declined slightly, primarily due to higher operation and maintenance expense due to the seasonal increase in utilities and higher field level personnel expenses and increased property and other taxes.

As a reminder, our first quarter property and other taxes decreased substantially due to a reduction in the ad valorem property tax accrual. As such, second quarter property and other taxes have returned to a more normalized level. While the Delaware Basin, natural gas and crude oil and NGLs throughput increased on a sequential quarter basis, these increases were below our initial expectations, primarily due to producer operational challenges that appeared during the second quarter. Based on our analysis, producer operational challenges include delays in wells coming to market, unplanned maintenance and base well performance issues. Several new wells that came online during the second quarter outperformed relative to initial expectations and this outperformance led to challenges across the production chain, specifically with producer-based wells.

Based on discussions with our producers and after analyzing their revised forecasts, we expect these issues to be temporary in nature, but will continue into the second half of 2023. As such, we expect total average year-over-year throughput growth to increase at a slower pace than initially expected. These revised throughput expectations for the remainder of the year will result in WES coming in below the low end of our previously disclosed 2023 adjusted EBITDA guidance range. Therefore, we are revising our adjusted EBITDA guidance range to now be between $1.95 billion to $2.05 billion for 2023 or a $100 million decrease at the midpoint. Kristen will provide more detail on our revised expectations later in the call. With that said, we continue to provide the highest level of system reliability and we’ll continue to work hand-in-hand with our producers to provide flow assurance and together optimize field productivity.

Providing superior customer service is a core value at WES and our ability to maintain reliable flow assurance has been a driving factor behind the successful addition of multiple new customers over the last few years. In fact, we have been able to effectively manage our system and provide higher levels of system operability in the second quarter compared to the first quarter, even with the extreme heat as we experienced in West Texas this summer. Additionally, we remain confident in our producer’s ability to deliver on their volume expectations over the long run and these recent well results further support our belief that our assets service some of the best rock in the Delaware Basin. In fact, based on the outperformance of these recent wells, we expect higher base production in future periods coupled with a lower overall decline rate.

Without a doubt, this year is proving to be more of a transition year for WES than we originally anticipated. However, even though our 2023 throughput expectations and our associated adjusted EBITDA are declining relative to our initial expectations, we are still supported by stable long-term contract structures that contain either minimum volume or cost of service commitments. In situations such as these, when current year cash flow expectations decline due to volumetric changes, the protections included in our cost of service contracts should benefit WES in future periods, allowing us to still earn our stated rate of return over the life of the contract. Pivoting back to our recent accomplishments and subsequent to quarter end, we announced a 12.5% increase to the base distribution increasing the quarterly amount to just over $0.56 per unit, starting with the second quarter 2023 distribution.

We firmly believe that our base distribution is an important recurring component of our balanced financial policy. Even though we expect adjusted EBITDA and free cash flow growth to slide into 2024, our stable long-term contract structures give us confidence that we can sustain our base distribution through commodity cycles and producer forecast revisions. The minimum volume commitments and cost of service protections embedded in our contracts, coupled with our ability to meaningfully derisk our enterprise by reducing leverage and securing additional firm processing commitments gives us comfort that our business can support and maintain an increased base distribution. We also took advantage of opportunities in the market to repurchase $118 million of our senior notes due in 2025 through 2030 and these activities continued into the third quarter.

Our ability to opportunistically deploy cash towards reducing our debt further strengthens our balance sheet even as adjusted EBITDA declines relative to our initial expectations. Increasing the base distribution and reducing debt, further demonstrates our commitment to our balanced approach to capital return. Turning to operations. Over the past year, our commercial team has generated substantial value for our partnership by executing multiple long-term agreements that provide up to 950 million cubic feet per day of firm processing commitments, which are supported by either minimum volume commitments or substantial acreage dedications. We are already benefiting from a portion of these volumes but most of them are expected to come into our system in West Texas over the coming years.

We also announced the sanctioning of our North Loving plant, which should be operational by year-end 2024 or early 2025. The most recent amendment to Occidental’s natural gas processing agreement to provide up to 300 million cubic feet per day of firm processing capacity provides even greater certainty regarding WES’ future profitability and underpins our decision to sanction this additional plan. Going forward, we continue to look for ways to expand our asset base to support throughput growth in a capital-efficient manner. With that, I will turn the call over to Kristen to discuss our operational and financial performance.

Kristen Shults: Thank you, Michael, and good afternoon, everyone. Our second quarter natural gas throughput increased by 4% on a sequential quarter basis. This was primarily due to continued throughput growth from the Delaware Basin and increased throughput from our assets in Utah and Wyoming, which were negatively impacted by inclement weather in the first quarter. We also experienced increased throughput from our natural gas equity investments during the quarter. Our crude oil and natural gas liquids throughput increased by 3% on a sequential quarter basis. This was primarily due to increased throughput from our assets in Utah, which were negatively impacted by inclement weather in the first quarter and continued throughput growth in the Delaware Basin.

We also experienced increased throughput from our crude oil and NGLs equity investments during the quarter. Produced water throughput decreased by 1% on a sequential quarter basis, mostly due to temporary volume curtailments associated with activities to support adjacent producer development. While Delaware Basin natural gas and crude oil and NGL throughput increased on a sequential quarter basis and produced water volumes would have increased on a sequential quarter basis if not for the above-mentioned reasons. These increases were below our initial expectations coming into the second quarter, primarily due to the previously discussed producer operational challenges. We do expect these issues to impact our second half of 2023 throughput expectations and our momentum entering 2024, which I will discuss in more detail shortly.

Our per Mcf adjusted gross margin for our natural gas assets decreased by $0.04 compared to the prior quarter. This was primarily driven by increased throughput from our assets in Wyoming and Utah, which have a lower-than-average per Mcf margin as compared to our other natural gas assets. We expect our third quarter natural gas per Mcf adjusted gross margin to decrease slightly, compared to the second quarter primarily due to increased throughput from other assets, specifically in South Texas and from our equity investments, which all have a lower than average per Mcf margin as compared to our other natural gas assets. Our per barrel adjusted gross margin for crude oil and natural gas liquid assets decreased by $0.07 compared to the prior quarter, primarily due to decreased demand fee revenue and throughput in the DJ Basin, and increased throughput from our other assets in Utah, which have a lower than average per barrel margin, as compared to our other crude oil and NGL assets.

We expect our per barrel adjusted gross margin in the third quarter to be modestly lower than the second quarter, primarily due to increased throughput from other assets specifically in South Texas, which have a lower-than-average per barrel margin as compared to the other crude oil and natural gas liquids assets, and decreased demand fee revenue from the DJ Basin. Our per barrel adjusted gross margin for our produced water assets increased by $0.02 compared to the prior quarter, primarily due to increased throughput on certain fee-based contracts. We expect our per barrel adjusted gross margin in the third quarter to be in line with the second quarter. During the second quarter, we generated net income attributable to limited partners of $247 million.

Adjusted EBITDA in the second quarter totaled $488 million, which was a slight decrease compared to the first quarter. This was primarily due to higher operation and maintenance expense and increased property and other taxes. Relative to the first quarter, our adjusted gross margin increased by $12 million mostly due to increased natural gas throughput from our assets in Utah and Wyoming, increased distributions from our equity investments and continued natural gas and crude oil and NGL throughput growth from the Delaware Basin. However, Delaware Basin throughput increases were below our initial expectations coming into the second quarter, which resulted in our second quarter adjusted gross margin coming in less than our initial expectations.

As expected, we experienced a sequential quarter increase in our operation and maintenance expense, primarily due to increased utilities and field level personnel expenses. Consistent with prior years, we expect our operation and maintenance expense to trend higher in the second and third quarters due to higher utility and maintenance expenses. As we discussed on last quarter’s call, our property and other taxes returned to a normalized level in the second quarter, as our first quarter results included a reduction in the ad valorem property tax accrual related to the finalization of 2022 assessments at the DJ Basin. We expect our go-forward quarterly property and other taxes to be in line with our second quarter results subject to finalizing our annual assessments.

Turning to cash flow. Our second quarter cash flow from operations totaled $491 million, generating free cash flow of $340 million. Free cash flow after a first quarter distribution payment in May, which included our first enhanced distribution totaled $3 million. From a capital markets perspective, at the beginning of the second quarter, we issued $750 million of senior notes with 6.15% coupon, the proceeds from which were used to refinance the amount outstanding on our revolving credit facility and to provide liquidity for general corporate purposes. Additionally, throughout the second quarter, we used a portion of those net proceeds to retire $118 million of senior notes of various maturities that were trading at an average of 94% of par through open market transactions.

These activities have continued into the third quarter and to-date we have retired an additional $159 million of our near-term senior notes. These activities have extended the duration by approximately one year of our remaining senior note maturities to roughly 13 years reduced our net leverage ratio and further strengthened our balance sheet. Finally, in July, we declared an increased second quarter cash distribution of $0.5625 per unit payable on August 14 to unitholders as of July 31. Focusing on basin-specific activity, we still expect average year-over-year throughput to increase across all three products in the Delaware Basin. However, this throughput growth will be at a slower pace than our initial expectations, primarily due to the previously mentioned producer operational challenges that caused second quarter throughput to come in below our initial expectations and revised producer forecast.

We still expect average year-over-year throughput decreases for both natural gas crude oil and NGLs in the DJ Basin. The natural gas throughput decline will be a similar percentage to last year. A steady on-load activity and increased producer activity levels will be offset by base production declines. For both products, we expect volume declines to flatten out in the third quarter as additional wells come online and we expect to see a modest increase in volumes for both products during the fourth quarter. Keep in mind, that these projected changes in natural gas and crude oil and NGL throughput in the DJ Basin are expected to have a minimal impact on our adjusted EBITDA due to demand and efficiency fee revenues we collect associated with minimum volume commitments.

We expect a slower rate of growth in the Delaware Basin to reduce 2023 throughput expectations especially for natural gas and produced water. As a result when comparing expected average 2023 throughput to average 2022 throughput, we now expect low single digit growth for natural gas throughput and upper teens percentage growth for produced water. We expect crude oil and natural gas liquids growth of low single digits to remain unchanged as decreased throughput expectations from the Delaware Basin were offset by improved forecast for both our equity investments and other assets specifically in South Texas. Keep in mind that our crude oil and NGLs growth expectations for 2023 exclude the impact of Cactus II from our 2022 throughput actuals. Pivoting to guidance as Michael previously mentioned, we are revising our adjusted EBITDA guidance range to be between $1.95 billion to $2.05 billion as a result of producer operational challenges experienced in the second quarter and revised producer throughput expectations for the remainder of the year.

However, even though our 2023 throughput expectations and our associated adjusted EBITDA are declining relative to our initial expectations, we are still supported by stable long-term contractual structures that contain either minimum volume or cost of service commitments. With that said and all else being equal, we would expect our cost of service rates to reset at an increased level at the beginning of 2024 due to the decline in 2023 volume expectations. Our capital guidance, which includes expenditures for Mentone III and the North Loving plant remains between $700 million to $800 million in line with our announcement in mid-May. As an update, we now expect Mentone Train III to be operational during the first quarter of 2024, primarily due to vendor specific supply chain delays.

However, we still expect the project to be within budget and we do not expect any volume curtailments as we have secured offloads throughout this period. We are also revising our free cash flow guidance range to be between $900 million and $1 billion consistent with our tempered expectations for adjusted EBITDA in 2023. Additionally with the 12.5% increase in the base distribution to $0.5625 per unit announced in July, we also increased our full year distribution guidance to at least $2.1875 per unit for 2023. Our enhanced distribution framework remains in place with a net leverage threshold of 3.2 times for year-end 2023. With that, I will now turn the call back over to Michael.

Michael Ure: Thank you, Kristen. I want to highlight that we are preparing to release our annual sustainability report in the coming weeks, which will detail our 2022 sustainability accomplishments. From achieving our goal of completing capital projects to reduce WES’ methane intensity by 5% on an annualized basis between 2020 and 2022 to launching new greenhouse gas tracking and reporting processes, we have continued to look for ways to minimize our environmental footprint through emissions reductions and by considering the impact of new and existing infrastructure on our environmental footprint. In fact, we received the GPA Midstream Association’s Environmental Award for our work to reduce crankcase emissions from our natural gas-fired compressor engines.

You’ll be able to read more about these accomplishments along with discussions pertaining to our volunteering program in the forthcoming 2022 report. We look forward to building on this momentum in the years ahead as we continue to advance energy by enhancing the sustainability of our operations. Before we open it up for Q&A, I would like to highlight a few key points and reiterate why we believe WES and its stakeholders continue to be well-positioned. We continue to be a market leader in generating a superior total capital return yield amongst midstream companies when taking into account distribution increases and unit buybacks. This is even more pronounced when considering the enhanced distribution that was paid on May 15th. When comparing the midstream sector relative to members of the Russell 3000 Index, WES and select midstream companies are some of the only investments with an investment grade credit rating and at least a 7% annual dividend or distribution yield.

Considering the changes to current year volume expectations, I feel it is important to reiterate that WES is supported by stable, long-term contract structures that include either minimum volume or cost of service commitments. These cost of service contract structures provide additional protection from producer and market-driven weakness by establishing targeted rates of return over the life of the agreement through annual rate redeterminations. Said another way when current year cash flow expectations declined due to volumetric changes these annual rate redeterminations in future periods allow us to earn our stated rate of return over the life of the contract. We continue to be prudent allocators of capital, demonstrated by the sanctioning of our North Loving plant, which was supported by up to 300 million cubic feet per day of firm processing commitments, supported by significant minimum volume commitments.

WES is well positioned to continue benefiting from producer growth in the core of the Delaware Basin for years to come. Finally, we have a strong balance sheet and remain focused on our balanced approach to capital return. This was further demonstrated by our recent debt reduction activities that continue to drive our net leverage ratio lower and by the 12.5% increase in our base distribution. We will remain focused on all three pillars of our balanced capital allocation strategy in order to continue generating substantial value and leading returns for all stakeholders. I would like to close the call by thanking the entire WES workforce for all of their hard work and dedication to our organization. I look forward to seeing all that we will accomplish in the second half of the year and ending the year on strong footing.

I look forward to updating you on additional progress on our third quarter call. With that we’ll open the line for questions.

Q&A Session

Operator: [Operator Instructions] Your first question is from the line of Brian Reynolds with UBS. Your line is open.

Brian Reynolds: Hi, good morning or good afternoon, everyone. Maybe to start off on just the return of capital. Just kind of curious of how we should think about WES’ forward total return yield after the announcement of the North Loving Plant. I’m just kind of curious of how potentially unit buybacks could perhaps be part of the return of capital structure in periods of dislocation here going forward, while still using the enhanced distribution on an annual basis to kind of target that optimized capital structure of three times. Thanks.

Michael Ure: Hey, Brian, it’s a great question. We are obviously, going to continue to utilize the unit repurchase on an opportunistic basis as we see dislocations in the marketplace. We’ve actually repurchased a significant amount of units, I believe peer-leading in that regard. And so it’s a tool that we’re firm believers in and we’ll definitely deploy if we see dislocations out there in the marketplace. As we think about the enhanced distribution again, the point of the enhanced distribution is that if we can’t find a better use of that capital whether that’s through incremental growth projects like Mentone and North Loving or opportunistically buying back units or debt throughout the year then we’re going to give that back to our unitholders.

So that is a philosophy that still holds today and we’ll continue to hold as we go into the future. Obviously, our confidence as it relates to the free cash flow yield after it is that we complete these new plants is very strong in light of the fact that we were comfortable increasing the base distribution because we do expect that that free cash flow yield will continue to improve as we get those projects online after that capital is spent to bring them online.

Brian Reynolds: Great. Really appreciate all that. Maybe to switch to operations. I appreciate all the color on just the quarterly performance around some of the new well designs at OXY. Well productivity for E&Ps has been topical year-to-date. So just kind of curious if you can discuss how some of these new wedge wells how interacting with legacy wells. And I think you talked about how there’s some near-term impacts that may reverse to some long-term improved efficiency. Just kind of wondering if you can give us a time line of maybe when is that expected? Could we see some 3Q performance, or is that more 2024 2025 kind of long-term lower decline rates that we should be seeing? Thanks.

Michael Ure: Yes. No, thanks Brian. Great question. So again, as we highlighted based on our analysis, it appears as if the factors really driving the underperformance again, it’s relative to expectations. We are still expecting volume growth on all three products for us. But relative to expectations it’s really challenges related to time to market some operability challenges, primarily driven by unplanned maintenance and then the high-performing wells really impacting base production. And again that latter part of it really is just impacting the rate of growth that we’re able to achieve. And as we work together to optimize some of those system constraints, which we expect that we’ll start to see some improvements in the back half of this year should impact the – or improve the ability to increase that rate of growth going forward.

We wouldn’t expect though that we’d be able to be complete in this regard until probably 2024, but we certainly expect that we’ll be able to debottleneck some of those challenges in the back half of this year.

Brian Reynolds: Great. Super. I’ll leave it there. Have a great rest of your afternoon. Thanks.

Michael Ure: Thanks, Brain.

Operator: Your next question is from the line of Jeremy Tonet with JPMorgan. Your line is open.

Jeremy Tonet: Hi, good afternoon.

Michael Ure: Hi, Jeremy.

Jeremy Tonet: I just wondered if you might be able to expand a bit more on the operational issues that were experienced during the quarter. It seems like the stronger well performance that kind of choked back the legacy wells as far as the flow is concerned. And just wondering if that’s the right way to think about it and the time line and ultimate scope of capital required to address these if you could provide a bit more color there that would be very helpful.

Michael Ure: Yeah, sure. So I think you highlighted that effectively in terms of the impact that we’re seeing and so the only real impact is that it’s just pushing a little bit to the right the volumes that we expect to come in system. There’s nothing that we’ve seen that would cause us any concern around the productivity of the wells in the area. In fact, it’s all incredibly positive. This is about just sort of pushing a little bit to the right, the growth rate that we’re expecting to come out of the assets. So long-term story, very, very well intact. While a little disappointing in the short term definitely not discouraging. The team’s very excited about the long-term prospects going forward. Right now, it’s difficult to say in terms of the capital requirements again on our side would expect that it would be relatively minimal.

And if there are — if there is some capital requirements then we’ll take the same approach that we always have which is that it needs to come with a requisite rate of return that is measured by the improved performance that we’re able to gather out of that in order to justify the capital spend.

Jeremy Tonet: Got it. And any rough scope for kind of time line to kind of rejigger the system to get past these issues?

Michael Ure: Again, we would expect that we’ll start to see some improvements in the back half of this year with the expectation that the challenges across the production value chain really will be finalized through 2024.

Jeremy Tonet: Got it. And then just coming back to the distribution increase here the level that was increased. Just wonder if you could expand a bit more on why now why less — why that level if not less or more just how you settled in on that amount?

Michael Ure: Yes. So, what we did is we took a look at the business and over the past 12 to 15 months, we’ve been able to receive close to one Bcf, a day of increased firm commitments. Overall, we sanctioned Mentone III as well as the North Loving plant. And so, as we forecasted out a sustained level of free cash flow, we always take a look at it as a management team and as a Board on a quarterly basis. And we take a look at what we believe to be a sustainable level through cycle that we can justify, overall. And in light of the business success that, the organization has been able to achieve, we then analyzed that this felt like a very sustainable level for us to be able to justify on the base distribution side, still allowing for increased free cash flow to utilize opportunistically on debt repurchases, on unit repurchases and/or new projects that might come in line.

So, it’s really a reflection of a lot of the positive dynamics that we’ve seen in our business, that it felt like now is a great time to increase that base distribution overall, to highlight the confidence that we have and being able to sustain at that level, all things considered.

Jeremy Tonet: Got it. That’s very helpful. I’ll leave it there. Thanks.

Michael Ure: Thank you.

Operator: [Operator Instructions] Your next question is from the line of Keith Stanley with Wolfe Research. Your line is open.

Keith Stanley: Hi, I just had one question about the declining leverage targets for 2023 and 2024. Do you think of those the leverage targets as solely for purposes of determining, if you can pay and enhance distribution, or is lower leverage in getting to 3x, an important priority for where you want the balance sheet when you’re thinking about capital allocation more broadly including buybacks and other initiatives?

Michael Ure: Yes. So, it’s a great question, Keith. That target was established first, because we feel like that’s sort of a prudent level for us to have leverage that provides us, both a derisked enterprise as well as the opportunity for us to go out and be proactive, as it relates to unit repurchases, potential M&A activities. We’ve operated at much higher leverage obviously, and so we feel comfortable the business can sustain higher leverage. But at those levels, we feel like it provides us with opportunities to be able to increase it on occasion, if there are business opportunities that we can pursue at that time. And so, again, those are targets in order to pay out the enhanced distribution, but the fundamental rationale for it, is that.

We want to make sure that as we make those decisions that we have flexibility to do so, as opportunities come up, by putting us at the lower leverage threshold — to lower leverage levels to be able to do that without materially harming the risk of the enterprise.

Keith Stanley: Got it. Thank you.

Michael Ure: Thank you, Keith.

Operator: 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. I would like to again, thank everyone, all the WES stakeholders and employees for their efforts thus far this year, and look forward to the third quarter call coming up. Thanks, all.

Operator: Ladies and gentlemen, this concludes today’s conference call. You may now disconnect.