Western Midstream Partners, LP Q4 FY2020 Earnings Call

Good day, and welcome to the Western Midstream Partners Fourth Quarter 2020 Earnings Conference Call. I would now like to turn the conference over to Kristen Shults, Vice President, Investor Relations and Communications. Please go ahead.

Thank you. I'm glad you could join us today for Western Midstream's Fourth Quarter 2020 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 our 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 the Western Midstream Partners K-1s will be available on our website beginning March 12. Hard copies will be mailed out several days later. With me today are Michael Ure, our Chief Executive Officer and Chief Financial Officer; and Craig Collins, our Chief Operating Officer. I'll now turn the call over to Michael.

Thank you, Kristen, and good afternoon, everyone. Yesterday, we reported fourth quarter 2020 adjusted EBITDA of $484 million as a meaningful reduction in producer activity throughout the year relative to our plan, culminated with a decrease in fourth quarter throughput across all products. Remarkably, despite this reduced activity, we reported full year 2020 adjusted EBITDA in excess of $2.0 billion, a year-over-year increase of more than $310 million or 18%. Due to our increased focus on cost and capital discipline, we delivered fourth quarter 2020 free cash flow totaling approximately $465 million, a 37% sequential quarter increase. For the full year 2020, we generated free cash flow totaling $1.2 billion. That's roughly 10% of our year-end enterprise value. Early in 2020, we pivoted our focus to free cash flow as a financial performance indicator as opposed to the conventional MLP standard metrics of distributable cash flow and distribution coverage. By operating within free cash flow, we better align company and stakeholder interests in building a long-term successful organization while providing results that offer comparability in and outside our industry to demonstrate our excellent free cash flow and total return profile. During 2020, we generated $530 million of free cash flow after distributions by reducing cash capital expenditures by approximately 65% from 2019 and reducing the distribution. Although 2020 was the first year our company generated positive free cash flow after distributions, we have made a fundamental shift in our mentality as an organization to ensure this success continues. As we started 2020, we recognized it would be a historic year for WES as we executed several agreements with Occidental in December 2019 that established WES as a stand-alone midstream company. The ensuing global pandemic two months later confirmed the historic nature of 2020, but not for the reasons we initially believed. While the pandemic created numerous challenges that were not unique to us, our team seized the opportunity to reexamine every aspect of our operations to identify incremental cost-saving opportunities and pursue efficiencies. This deep dive into our business, continued producer outperformance, and additional cost efficiency realizations from deconsolidation enabled WES to exceed all expectations in our first year as a stand-alone company. We're moving more than $175 million of O&M and G&A costs compared to our original 2020 guidance contributed to the highest annual adjusted EBITDA in Western Midstream's history. We compounded these cost savings with the efficient execution of our capital program, landing $590 million below the original 2020 guidance midpoint and $100 million below the revised 2020 midpoint. We priced a $3.5 billion four-tranche senior notes offering, which was 6.2x oversubscribed with more than $21 billion of demand. At the end of the third quarter, we announced a $250 million common unit buyback program, of which we've repurchased $49 million as of today's call. The careful protection and efficient management of our balance sheet and the significant work by our employees to discover cost savings enabled us to return more than $1.2 billion to stakeholders through debt repurchases, cash distributions, unit buybacks, and units acquired through the Anadarko note exchange. Furthermore, as a result of the unit buyback program and the note exchange, we've increased our free cash flow after distributions by over $22 million. On a year-over-year comparison, we increased throughput in every one of our products with a 1% increase in natural gas throughput, a 7% increase in crude oil and NGL throughput, and a 28% increase in water throughput. Our teams implemented mutually beneficial commercial solutions with producers to keep volumes on our system and generate incremental capital-advantaged EBITDA for WES while also providing near-term relief to customers adversely affected by lower demand for their products. Operationally, we benefited from the completion of three significant projects in 2020. The second Latham train, which commenced operations in the first quarter, added 250 million cubic feet per day of total processing capacity in the DJ Basin, and Train III and Train IV at the Loving ROTF in the Delaware Basin, the latter of which was completed nearly two months ahead of schedule and required 35% less capital than our previous North Loving trains. Our staff put forth a tremendous effort to complete these organizational and operational changes in 2020, and we're confident that the foundation we developed will continue to inure to the benefit of our stakeholders in 2021. This provides us with momentum to work toward further sustainable cost efficiencies, safe and superior customer service, and returning value to stakeholders. Our previously communicated 2021 guidance of adjusted EBITDA between $1.825 billion and $1.925 billion and capital expenditures between $275 million and $375 million, along with maintaining our year-end debt to adjusted EBITDA ratio at or below 4.0x, is currently unchanged. While we are still evaluating the full financial impact of the recent winter storm, which will adversely affect our first quarter results, we do expect to make up those impacts throughout the year. We've already seen increased activity across the DJ and Delaware Basins at the end of 2020 and into 2021, and we expect these increased activity levels to continue throughout 2021, allowing us to exit the year at higher throughput levels than our 2020 exit rate. With the increase in activity, we expect our capital requirements to be slightly front-end loaded to the first half of 2021. We also anticipate that our EBITDA will trend upward throughout the year as increased activity levels yield increased throughput. Overall, we expect the DJ Basin to account for 37% of our asset-level EBITDA, with an additional 40% coming from the Delaware Basin. In a few moments, Craig will provide further detail around activity levels and capital requirements. But I wanted to take a few minutes to discuss the impact of our cost of service rate contracts on 2021 guidance. As a result of declining 2020 volumes, we experienced upward pressure on cost of service rates. Fortunately, the impact of these increases was partially and, in some cases, more than entirely offset by the significant cost and capital savings achieved in 2020, which we believe will be sustainable on a go-forward basis. Specifically, our Delaware water and oil cost of service rates decreased as a result of these achievements. These cost savings and resulting downward pressure on cost of service rates demonstrate the symbiotic relationship that WES values with its producer counterparts. We will continue to push forward cost reduction initiatives. These savings are proportionally shared with our partners, which we believe will continue to incentivize additional business. These are all reasons why WES is positioned to be the midstream provider of choice within the areas we operate, a goal we take very seriously. These anticipated rate changes were taken into consideration as we released our initial guidance at the end of the third quarter. The impact of the rate changes was deemed immaterial to the total guided amount, and that remains the same after our final calculations. Our 2021 guidance also includes nearly all of the $175 million of cost savings realized in 2020. Through optimization efforts in our existing assets, the transition to a stand-alone business model, and strengthening our relationship with Occidental, we've identified sustainable opportunities that improve operability, more efficiently deploy capital, and ultimately drive value for our stakeholders. To reiterate our third quarter call, our strategic contractual protections minimize the impact of potential declines in throughput on our EBITDA. Using 2021 guidance, as an example, if DJ and Delaware throughput levels decreased by an additional 10%, it would result in only a 5% to 6% decline in our asset-level EBITDA. With that, I'll turn the call over to Craig to discuss our fourth quarter operations and provide more thoughts on 2021 activity and capital requirements.

Thank you, Michael. Operationally, gas throughput decreased by approximately 282 million cubic feet per day or 7% on a sequential quarter basis as a result of minimal investment throughout 2020. Full year 2020 natural gas throughput averaged 4.3 billion cubic feet per day, representing a 1% increase from full year 2019. Our water throughput decreased by approximately 16,000 barrels per day, representing a 2% sequential quarter decrease as a result of lower producer activity in the Delaware Basin. Full year 2020 water throughput averaged 698,000 barrels per day, representing a 28% increase from full year 2019 resulting from additional volumes early in the year, the conversion of trucked water volumes from our existing producers onto our system, and incremental new business that we brought online throughout the year. Our crude oil and natural gas liquids assets experienced a sequential quarter throughput decline of approximately 70,000 barrels per day or 10%. During the fourth quarter, volumes decreased across the portfolio as a result of minimal investment throughout 2020. Full year 2020 crude oil and natural gas liquids throughput averaged 698,000 barrels per day representing a 7% increase from full year 2019. This growth was driven primarily by higher throughput from our DBM oil complex with the start-up of Loving ROTF Trains III and IV and higher throughput from our Cactus II equity investment. Our gross margin for crude oil and natural gas liquids increased by $0.15 for the quarter to $2.69 per barrel, which is attributed to the cumulative adjustment related to the annual cost of service rate resets. We expect 2021 crude oil and natural gas liquid margins to be slightly below third quarter 2020 margins as a result of lower Delaware Basin cost of service rates and lower gross margin contributions from equity investments. Before I provide some color around 2021 activity and capital requirements, I want to take a moment to thank our operational, engineering and commercial teams for an outstanding year. Their passion for improving customer service and consistent care and concern for one another through our LiveSAFE culture continues to serve as cornerstones to our continued success in such a challenging time. Our operations team worked effectively to maintain our system availability above 99% for 2020, outperforming our internal targets. Ensuring system capacity and operability enables us to move as much product as possible to market and further mitigate producers' needs to flare natural gas. Our commercial team's ability to create win-win solutions with producers during the depths of the pandemic helped to keep volumes on our system and protect our revenue streams. Finally, our engineering organization added 150,000 barrels per day of water disposal capacity, 210 million cubic feet per day of compression, and 60,000 barrels per day of oil treating capacity. They optimized processes, increased system reliability, reduced project cycle times, and identified significant cost savings, all of which enabled our commercial team to build on their recent success and aggressively compete in the marketplace. Turning to 2021, the return of activity toward the end of 2020 and into 2021 brings us great optimism. We're expecting rig count to remain relatively constant in the DJ and Delaware Basin over the course of the year. With the anticipated activity levels and DUC completions, we expect our producers to bring online approximately 315 wells across the portfolio in 2021, about 60% of which is located in the DJ Basin. We expect to exit 2021 with gas throughput relatively flat to our 2020 exit rate, while oil and water will increase compared to the 2020 exit rates by high single-digit and low double digits, respectively. As we look at the increased regulatory environment and our related risk profile, our federal land exposure in the DJ and Delaware Basins is incredibly limited. Currently in these areas, less than 5% of our gas throughput originates from New Mexico federal lands. Water and oil exposure is immaterial. In the event, federal land permitting issues jeopardize new volumes, we believe the impact to our 2021 adjusted EBITDA is immaterial to the guidance ranges provided. Our analysis contains various assumptions concerning permitting, locations, and timing, but this projection is another demonstration of the minimal impact federal land regulations would have on our portfolio. Turning to capital. We expect our capital requirements to be slightly front-end loaded to the first half of 2021 with the projected increase in producer activity. Our capital guidance of $275 million to $375 million supports a steady level of activity growth throughout 2021. Similar to recent years, we expect to deploy the majority of our capital, about 59% in the Delaware Basin. The majority of our capital will be spent on expansion projects, including saltwater disposal facilities, additional pipelines, and well connections. With excess capacity in the DJ Basin, we do not expect any sizable projects to materialize in the foreseeable future. While the Delaware Basin does not have as much excess capacity as the DJ Basin, we expect the intensity of capital spending to continue to decline. Capital will continue to be required for regional projects, including additional saltwater disposal facilities and compression as we alleviate areas of constraint. Now I'll turn it back over to Michael to discuss our focus areas for 2021.

Thanks, Craig. After executing separation agreements with Occidental in December 2019, much of our internal efforts last year were spent on standing up an organization, transferring more than 1,600 employees and contractors, establishing separate systems and processes, and creating an entrepreneurial culture unique to WES. As we move through 2021, we intend to further strengthen and refine our business model and internal processes, enhance our focus on customer service and operational excellence, and continue our active work to minimize our environmental footprint. On the financial front, we believe we have identified most of the available O&M and G&A savings as part of our 2020 transformation. However, it is part of who we are as a company to continually examine our operations and challenge the status quo to identify innovative ways to reduce our cost structure and work more efficiently. We believe this culture of cost management, continuous improvement, responsible operations, and the use of technology to enhance safety and efficiency is imperative to provide value to our stakeholders. We regularly monitor costs as a percentage of gross margin and throughput, questioning and challenging the use of capital and actively monitor spending to protect against cost creep when a higher level of activity returns. We remain committed to responsibly managing leverage and returning value to stakeholders through further debt repurchases, cash distributions, and unit buybacks. Our ability to generate free cash flow after distribution last year and into the foreseeable future enables us to repay all near-term maturities when due, totaling $1.2 billion in payments over the next four years. Coupled with expected EBITDA growth, we intend to further reduce leverage to at or below 3.5x at year-end 2022. In addition to debt repurchases, we want to remain flexible and opportunistic in how we return value to stakeholders. We expect full year 2021 distributions of at least $1.24 per unit, and we're committed to evaluating distribution increases on a quarterly basis as a potential avenue to return excess cash to unitholders. The remaining $201 million of the $250 million common unit buyback program provides us with additional options to return value to unitholders. As you've seen in our inaugural ESG report posted on our website, we're proud of our recent ESG performance and the passion our people have to address ESG issues in a transparent way. We believe the world will continue to require hydrocarbons, in particular, natural gas to power our lives. The recent freezing temperatures in the Southern U.S. is another example of the important role hydrocarbons play in providing fuel and warmth for our communities. We take seriously our responsibility to minimize emissions by thoughtfully designing, constructing, and operating our assets. Collaborating with state and federal regulatory agencies, environmental groups, producers, and the industry to find the best solutions to today's climate-related challenges. Our ESG philosophy is rooted in three pillars: creating sustainable environments, focusing on people, and operating responsibly. Our operational philosophy and the design of our facilities dating back more than 12 years ago are a testament to how we view ESG. Specifically, the design of our Colorado COSF and West Texas ROTFs enables us to gather oil directly from producers' well sites, eliminating the need for well site storage tanks and associated oil vapor flaring, leading to emission reductions across the upstream sector. As a proactive measure to minimize our facility emissions footprint, WES began installing electric-driven compression as early as 2008. Today, WES operates more than 350,000 horsepower of electric-driven compression, returning more than 22 billion cubic feet of gas to the market that would otherwise be combusted in natural gas-driven compression. We have also been progressively designing our facilities to limit our flaring activities to those required for safety purposes. For example, when feasible, we install closed-loop process vessels and systems to capture and transport gas to market instead of flaring product. We utilize technologies that recycle waste gases back into our process instead of flaring. It's not only the right way to operate our business, but it also ensures that our facilities can easily adhere to future regulatory changes. These forward-looking designs are unique to Western Midstream, and demonstrate how our creativity, ingenuity, and planning can provide solutions to deliver resources to an energy-hungry world while protecting the environment. In addition, our customer focus drives our level of commitment to ESG as our teams work closely with producers to minimize upstream flaring during the product life cycle. Our commercial team works to have all infrastructure and pipelines in place before production commences, as well as the contracted capacity and reliability to receive and transport our customers' products through our natural gas pipeline infrastructure, compressor stations, and processing facilities. Employees stationed at our regional control centers use automated remote sensing equipment to continuously monitor our gathering and processing infrastructure. This helps us to ensure system availability, which reduces producers' need to flare natural gas. To demonstrate that we're part of the solution, we firmly believe our industry must work together to bring greater transparency to our environmental impact and actively communicate our mitigation efforts. Over the last few months, we have worked closely with the Energy Infrastructure Council, EIC member companies, and investors to create a standardized ESG reporting template for the midstream sector. We've also taken an active role in drafting GPA Midstream's climate policy principles, which, in part, supports our technological advances and solutions that minimize GHG emissions. That collaboration extends to local governments and regulatory bodies as well to generate economic solutions to environmental issues. In 2020, WES supported a proposed rule from the Colorado Department of Public Health and Environment requiring emission reductions from existing natural gas-fired engines over 1,000 horsepower. As part of an effort to ensure real emission reductions occur, we will achieve NOx reductions by at least 800 tons over the next three years, starting in 2022. We also plan to permanently retire three natural gas-fired compressor engines by mid-2024, eliminating 17,000 metric tons of CO2. This commitment to be good stewards of the environment starts at the Board level and continues down through the organization to each of our employees. As further evidence of this commitment from the top, WES recently appointed a Board-level ESG committee, whose charter is to steer our efforts on issues and performance regarding environmental protection, social causes, and strong corporate governance. We, as a management team, are excited to work with this new committee to drive positive performance in each of these elements for the future. It's in that spirit of working together that I'm excited to announce our recent membership in ONE Future. The ONE Future Coalition is a group of 37 natural gas companies working together to voluntarily reduce methane emissions across the natural gas value chain to 1% or less by 2025. The coalition's approach to reducing emissions aligns with our priorities as we work together to identify policy and technical solutions that yield continuous improvement in the management of methane emissions. We look forward to continuing to demonstrate our commitment to ESG issues through operational changes, enhanced customer service, and partnerships like ONE Future. I'd like to close with my appreciation to the 1,600 employees and contractors at WES. While the global pandemic and the precipitous decline in commodity prices were not unique to WES, our team's resiliency, outstanding determination, and long hours to stand up an organization while working remotely provided our stakeholders with a historic performance, one that may be unprecedented for a first-year stand-alone midstream company. Thank you for your efforts. I would like to especially thank those hard-working people who work through these freezing temperatures to deliver valuable fuel to those in desperate need during the recent storms. Today, while we continue to work through the day-to-day challenges that are inherent in our business, we are committed to delivering long-term value to our stakeholders by operating safely, delivering exceptional customer service, and returning cash to stakeholders. Furthermore, if 2020 taught us anything at Western Midstream, it is the importance of remaining nimble and adaptable when change occurs. Excelling in an evolving and fluid environment is a skill we've been perfecting since we undertook our current focused midstream strategy. With that, I would like to open the line for questions.

Today's first question comes from Shneur Gershuni with UBS.

I would like to start by asking about the potential for operating leverage within the Western Midstream assets. I noticed on Slide 30 of your updated presentation that you discuss volume fluctuations and changes in EBITDA. For instance, your fourth-quarter throughput for natural gas was approximately 8% lower than your average for 2020. This suggests there should be some level of operating leverage. Can you share your thoughts on how much operating leverage you believe you have achieved without incurring any significant capital expenditures?

Yes, thank you for the question. I’d like to address that trend and its potential impact moving forward. As mentioned, we experienced a decline in volumes during the latter part of 2020, which we anticipated. We expect this trend to persist into the first half of 2021, as it takes time for the increased activity levels to translate into volumes in our system. We have some capital prepared to handle those volumes when they materialize. To provide some context, if the activity levels for 2021 continue similarly into 2022, and since we expect to finish 2021 at a higher level than 2020, we can anticipate that growth to carry over into 2022. The capital requirements for this growth are expected to be in line with what we have projected in our budget for 2021.

And just to clarify, do you have a sense of what your capacity actually is? So like just sort of following the forecast that you have right now, and you've given us the volume sensitivities, could '22 from a capacity utilization perspective, like entering '22, would you be at 80%, 85% or 90%? Like is there some sort of like utilization level that you can give us, so that we can sort of utilize the sensitivities that you outlined?

Yes. We don't actually provide specific details as it relates to our projected utilization. But again, I would indicate that even if you play that into forward years, we wouldn't expect that there would be a material increase in the amount of capital requirements for a foreseeable period of time. Obviously, there's limits to that. But as we project forward over the next several years, we wouldn't expect that there would be a material increase in capital if the activity levels continued into the future.

Okay. So you can handle a 20% volume increase without capital, is kind of the takeaway from that slide then?

Well, again, I never gave any specific details as it relates to a 20% increase in volumes, but I appreciate the probing question. But I did indicate that it would be on an upward trend going into 2022, and we would expect, therefore, the cash flow to increase in 2022 over 2021, and that the capital needs for that period would be relatively similar. And if you play that forward for a reasonable period of time, we would expect that similar type of operating leverage would continue without the need for significant additional infrastructure.

I would just add that given our extensive footprints in the Delaware and DJ basins, we continue to find ways to optimize and discover new capital-efficient methods to expand our system incrementally. Determining what that capacity is can be challenging because we are consistently finding ways to increase that number.

Yes, I definitely appreciate it. You've provided us with more information, though we always want more. Kudos to the team for that presentation. I have a follow-up question. You've had significant success adding third-party volumes this past year. Does it have the potential to reach a 55% or 60% level? Or will Oxy grow faster than that rate, mitigating the increase? I'm trying to consider whether you can dilute Oxy's exposure enough to influence the rating agencies' views on notching.

Yes, I’d like to point out that, from our perspective, we aim to expand the overall market. We don’t have a specific target level for any of our partners. Looking ahead to 2021, much of the growth will result from existing customers' activity levels. We are very optimistic that our cost-saving initiatives will enhance our competitiveness as new third-party opportunities emerge. If this leads to a decrease in customer concentration risk, that would be positive, but it’s not our main focus. Our priority is to ensure overall growth. Craig, do you have anything to add?

Yes. I think it's also important to note, just the size of the pie that we have, and it's tough for that number to materially move from one year to the next. Even given the successes that we've had in attracting new business. But what we love to see is the pie as a whole continuing to get larger and have each of our producers be as active as they can be in these basins. And so I think it's just tough to see a material change in that move or a material change in that allocation. But our focus is growing the pie.

And our next question today comes from Kyle May with Capital One Securities.

Michael, I appreciate that you are still evaluating the impact of the recent winter storm, but just wondering if you have any preliminary thoughts or estimates about the impact of the business?

We don't have anything definitive yet. We are conducting a comprehensive review, and it will certainly affect the first quarter. There was a period of about 10 days that saw reduced volumes, and we are still feeling the effects in terms of costs. However, we are now operating under what we consider normal conditions. The disruption was contained to a specific timeframe, and I commend the team for quickly getting back to operations despite the circumstances. We are still assessing the overall financial repercussions. At this point in the year, we believe there will be an opportunity to recover from the financial impact, but we have not fully assessed what that will entail.

Understood. That makes sense. And then although the guidance for this year has not changed since November, can you talk about the recent conversations that you've had with customers? Just curious if any plans or positioning has changed over the last few months?

Yes, we haven't observed significant changes in overall behavior in recent months. Generally speaking, some private operators have been quicker to respond to increased activity levels. Our public customers have tended to be more disciplined. Since the guidance was issued, we haven't noticed any material shifts or changes.

And our next question today comes from Spiro Dounis with Crédit Suisse.

I want to go back to leverage if we could and tying that back to your advancement towards investment-grade. Leverage so far tracking better than initial expectations. You put out that new number now of at or below 3.5x by 2022. And so as you continue to advance towards investment grade, can you just tell us what the factors are, you think that would be needed to get you there? Have the agencies set some targets for you? I guess how close do you think that is?

Yes, that's a great question. From our perspective, regardless of the actual rating, we consider ourselves to be in the investment-grade category from a credit standpoint. We appreciate your acknowledgment of the progress we have made so far. We had aimed for a target of 4.5x by the end of 2020, which we surpassed, and we set another target for 2022, resulting from our repayment of near-term maturities. We have a $431 million maturity to pay off in Q1, followed by a $581 million maturity in 2022. Along with the upward trend in cash volumes as we close out 2021, we believe we will reach those levels as projected. The conversations with the rating agencies have been very encouraging, and they seem to appreciate our commitment to reducing leverage. While the timing is somewhat out of our control, we are operating under the belief that we are functioning with a genuine investment-grade credit profile, regardless of the rating. Key factors include how we manage pandemic-related projections, the use of free cash flow, and customer concentration.

Got it. Okay. That's helpful. Second question is a bit of a two-parter on ESG. It sounds like you guys have been busy on that front since the last time we caught up last quarter. And so great initial steps. Obviously, on the emission reduction, you're joining some of these industry groups, I guess, as I think about next steps and other things you can do, you mentioned challenging the status quo. I guess, two things come to mind. And so I'm curious, are any resources being deployed now to potentially transition over to C-corp at some point in time? I'm sure you've been asked that in the past. And then as we think about advancing more commercial opportunities as opposed to just the operational ones you're working on now, I'm thinking, obviously, direct air capture, carbon capture and storage. How far away are those for you?

Yes, thank you for acknowledging the progress we’ve made. It's an initiative we are very passionate about, starting from the top with the establishment of a new ESG committee, which is a three-member standing Board committee. We are committed to ensuring we are as efficient as possible with our existing assets. Currently, we do not view a C-corp conversion as beneficial for us or our unitholders, so we don't see it as being in our best interest at this time. I apologize, but I didn’t catch your last question. Was it about commercial opportunity?

Yes. No worries. Yes.

Yes. So a couple of things that I would note there, and I'll turn it over to Craig for additional commentary. Again, with the creation of the ESG standing committee, obviously, that's going to give significant focus for the organization to make sure that we're being forward-leaning around ways in which we can participate in the efforts as a whole. That committee includes great connection back with Occidental, and we're very impressed overall with the efforts that they have made in that regard. And so obviously, it facilitates some partnership in the event that those types of opportunities find their way down there. We've also even reallocated some internal resources with a senior team that is focused on those types of opportunities. And so together with the Board committee, executive leadership allocation, and connectivity back with Occidental, we think that there are definitely ways in which we can try to find ways that will enhance return or certainly be productive from a return perspective, but also be conscious of the climate situation that we have today. Craig, anything else that you'd add there?

Yes. I would just add that the resources that we've pulled together to lead this effort are led by one of our top commercial talents that's been with us for several years. And we think that that's really going to be an important element of how we advance some of these ESG opportunities: to figure out how to commercialize and get into opportunities in a way that makes economic sense for us, as Michael points out. But also reiterates and underscores the commitment that we have to make in advances on the ESG front. And so we're excited by the team that we have assembled to help lead that for us. And we're looking forward to what those opportunities will deliver in the coming months ahead.

And our next question today comes from Sunil Sibal with Seaport Global Securities.

I just want to clarify a point regarding previous questions. You have outlined a three-year deleveraging plan. Is this based on your latest discussions with the rating agencies? If you follow through on that plan and if there are no changes in the macro environment, will that be enough for you to achieve investment-grade status, considering there are still some issues to address related to customer concentration and other factors?

Thank you for the question, Sunil. There’s a lack of specificity regarding the precise targets that need to be met to trigger an upgrade from rating agencies. Each agency has its own criteria for assessing ratings and credit, so I can't point to anything specific that would lead to an upgrade. However, we are doing everything possible to position ourselves favorably. We believe our metrics justify an investment-grade rating, particularly with how we are managing the repayment of our upcoming maturities and our overall leverage. That said, I cannot identify any specific trigger that would lead to an improvement in rating agency ratings.

Got it. And then on the portfolio rationalization side, obviously, you've done a little bit here, started it off. I was kind of curious, how should we be thinking about that, both in terms of divesting efforts or even maybe looking at other assets in other basins, which kind of give you more kind of ratable businesses, et cetera?

Yes, our stance remains unchanged; we will consider opportunities for both divestitures and acquisitions. The last year has been challenging for executing deals on either front, whether buying or selling. We are continually discussing certain assets that might be considered non-core. If someone values those assets higher than our assessment, we will consider those opportunities. I believe our activity levels are in a better fundamental position now compared to the past. We have maintained a mindset focused on continually optimizing our portfolio over the last 12 to 18 months.

And our next question today comes from Gabe Moreen with Mizuho.

I have a couple of questions about the cost of service arrangements and how cost reductions are integrated into these arrangements, as well as the mechanisms for sharing cost reductions. Can you explain how those cost reductions are applied within the cost of service? Are you sharing them with your customers? Is there a limit to the sharing? Additionally, how much flexibility do you have regarding cost of service savings, and at what point do you need to share everything with your customers? Sorry for the lengthy question.

Yes, that's a great question, Gabe. Let me address that, and then Craig can add anything I might overlook. Not all of our contracts operate on a cost of service basis. The calculation depends on cash flows from assets, capital and operating costs, and specific volumes for the relevant area of the cost of service contract. As costs are allocated, a decision is made regarding the rate based on historical volumes and future projections for that location. In 2021, we observed that the team's significant efforts to reduce costs and project volumes actually led to a decrease in rates for oil and water in the Delaware Basin. This is how the calculation works. We believe that every dollar spent should be carefully considered and must bring value, as any savings can either encourage further development on our acreage or benefit our unitholders. Craig, do you have anything to add?

Yes. I would like to add that a significant factor for this year, as we recalculated those rates, is that the 2020 volumes were much lower than we initially expected. Consequently, our capital expenditure in 2020 was also lower than planned. Additionally, an important aspect of our models is the projected future capital and operating expenses. By refining our estimates and improving our cost assessments for those facilities, we've better understood what will be required to achieve those future volumes. This includes our operating costs, and the total of these factors influences our internal rate of return calculations. Thus, this adjustment in rates is driven by both the impact of 2020 and our projections for delivering future volumes. We're pleased to have found ways to reduce costs. As Michael mentioned, this is specific to certain customers. As we improve our ability to lower facility and operating costs, it benefits not only those specific service contracts but also extends to all other contracts we have that operate at fixed rates.

Got it. And then maybe, Shneur asked about operating leverage. And I think also based on the metrics you're disclosing about leverage to volume increases or decreases. It seems like you have that. But I'm just curious, as you look across the portfolio and your assets that have MVCs with them, are there any assets where you are actually materially below your MVCs and where an increase in volumes may not filter through to the bottom line, at least initially?

Go ahead, Craig.

Yes. It is asset-specific. It's contract-specific. So I think it's probably not simple enough to address through a response in the way that you would find helpful. I would say that we have all that baked into our guidance for 2021 and it's part of our long-term planning. We are optimistic that as producers continue to get their feet under them with strengthening commodity price deck and increasing activity levels, that producers will be outperforming those minimum volume commitments. And we look forward to seeing that upward trajectory on volumes again.

Gabe, regarding that, there is a factor in the calculation that relates to the increase in volumes. If we see a 10% rise, we anticipate the EBITDA will grow by 5% to 6%. However, this increase is somewhat offset by the minimum volume commitments, so we are projecting a 5% to 6% increase instead of a larger one.

And our next question today comes from Derek Walker, Bank of America.

Mike, thank you for your insights today. I have a couple of quick questions. Regarding the ESG side, you mentioned the 350-horsepower electric compression that has been developed over the past two years, along with the retirements of some natural gas compression units. Do you see any further opportunities for conversion to compression? And do you expect more natural gas compression retirements this year?

Craig, you want to take that one?

Yes. I think, Derek, the way we think about the compression is, as we're adding new compression, we're looking for opportunities to electrify as much of that is possible. In some areas, in some basins, and even within certain locales in those basins, the proximity to reliable power sources sets up better for some of that compression than others. And so, it really becomes a function of how available and the proximity to reliable power. For example, in the DJ Basin, given the proximity to urban development, the power availability is very attractive and facilitates opportunities for us to do more on the electric compression side, and we utilize quite a bit of electric compression up in the DJ Basin, which is an important part of how we're running our business up there. Given the environmental regulations that continue to change, we try and stay out in front of those changes by being proactive and deploying that electric compression. In other areas, it becomes a little bit more challenging to find that readily accessible power grid infrastructure. And I think that's, frankly, one of the challenges or opportunities, if you will, that we see moving forward as the power grid continues to grow and expand to facilitate a broader electrification across the U.S. and hopefully, within some of the operating areas that we operate in.

I appreciate that. And maybe just one quick clarification question. Mike, I think you said there's 315 wells in your forecast with 60% of the DJ. How do you see the cadence of those wells throughout the year? I think you mentioned that some of that might be front-end loaded, but do you see that cadence difference between the DJ and the Permian?

Yes. I believe the pace will be relatively consistent throughout the year. Our capital expenditure will be somewhat front-loaded in the first half of the year to prepare for the volumes that will come online. Our producers in both basins have increased their rig activity compared to 2020, which gives us confidence in our ability to see those volumes enter the system over the year. As Michael mentioned earlier, volumes in the first half of this year will still be lower than our expected exit point, but we anticipate a steady increase throughout the year as rig activity remains stable.

Our next question today comes from Jeremy Tonet with JPMorgan.

This is James on for Jeremy. Just one quick one on clarification. The 3.5x leverage target for year-end '22, there's no asset sales embedded in that, right? And I guess, any incremental asset sales will be applied to deleveraging first and foremost. Is that correct?

Yes. So we do not have any assumption of asset sales that is embedded in our ability to get to that target. That is through the efforts of repaying our near-term maturities and then the expected EBITDA profile through 2022.

Got it. As a follow-up, could you discuss the pace of buybacks for the rest of the year, especially considering recent performance? Is there a possibility of a slowdown, or might you consider allocating capital to increase the distribution if the stock continues to perform well at these levels?

Yes. So as mentioned, we'd actually already been a participant in the first quarter as it relates to buybacks, as we gave you an updated figure there that is slightly higher than our year-end number. And so it's obviously an opportunity that we still have to be able to use. This is something, as we've mentioned, that our primary goal is to get at or below 4x by year-end. And then we have multiple tools available to us to maximize the value to our unitholders, that being either a distribution, potential distribution increase or a buyback program. That's something that the Board has engaged on and desires to engage on, on a quarterly basis to assess which of those tools to use at their disposal. That's an authorization, by the way, that is outstanding out through the end of 2021 and was set so that we could meet that leverage target.

And ladies and gentlemen, the next question is a follow-up from Shneur Gershuni.

Just a quick follow-up here. And actually, just with respect to the last question that was asked with respect to the buyback plans. Sort of a two-part question on it. Just the first part, do you expect to be buying in the open market as you execute on it going forward? Or is there potential for you to be buying back from Oxy? I mean, as you've been executing on and technically, your ownership stake goes up mathematically, and they do have an expectation of needing to get below 50% for the consolidation or deconsolidation? Just wondering if you have any thoughts with respect to that.

Yes. We would like to buy back units from any source. So far, we have focused on the open market, but we are also open to the idea of repurchasing some units from Oxy. Our approach is flexible. We have successfully reduced our distribution burden by almost $40 million, after considering the interest from the note exchange, resulting in around $22 million in free cash flow after distributions. We have repurchased just over $300 million or approximately 31.33 million units. We see this as an opportunity to enhance our free cash flow after distributions, and this mindset applies whether we are buying from public unitholders or from Oxy. Therefore, we are interested in both options.

Okay. And as a follow-up, I kind of was confused a little bit. I'm not sure if the prior question is intimating that the stock had went up so much so you shouldn't. And whether you were saying you would or you wouldn't because of the movement of stock because they sort of look at it at the fact that when Oxy first bought its stake and you were installed as CEO, you were trading in the high $20s versus $17 today. So I'm just trying to understand if you were all trying to intimate that $17 is high enough or whether it's still cheap enough to continue buying?

I will always look for ways to improve the value of our unit price. We don't have a specific threshold that we consider necessary for starting or stopping the buyback program. The Board will review the overall target levels quarterly and evaluate the best methods to return cash to unitholders, whether through a growth target or continuing the buyback program. Up to now, we have utilized the buyback program significantly, purchasing nearly $50 million since we announced it at the end of the third quarter.

And ladies and gentlemen, this concludes the question-and-answer session. I'd like to turn the conference back over to the management team for any final remarks.

Thank you very much, everyone, for joining our call today. I appreciate your time. Please be safe.

Thank you, sir. This concludes today's conference call. We thank you all for attending today's presentation. You may now disconnect your lines and have a wonderful day.