Good day and thank you for standing by. Welcome to the PAA and PAGP Fourth Quarter Full Year 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. I would now like to hand the conference over to your speaker today, Mr. Roy Lamoreaux. Mr. Lamoreaux, the floor is yours. Thank you, Chris. Good afternoon, and welcome to Plains All American’s fourth quarter and full year 2021 earnings call. Today’s slide presentation is posted on the Investor Relations website under the News and Events section at plains.com, where an audio replay will also be available following today’s call. Important disclosures regarding forward-looking statements and non-GAAP financial measures are provided on Slide 2. A condensed consolidating balance sheet for PAGP and other reference materials are located in the appendix. Today’s call will be hosted by Willie Chiang, Chairman and CEO; and Al Swanson, Executive Vice President and CFO. Other members of our team will be available for the Q&A session, including Harry Pefanis, our President; Chris Chandler, our Executive Vice President and Chief Operating Officer; Jeremy Goebel, Executive Vice President and Chief Commercial Officer; and Chris Herbold, Senior Vice President of Finance and Chief Accounting Officer. With that, I’ll now turn the call over to Willie.

Thank you, Roy, and good afternoon, everyone. I want to thank you for joining us today. It’s remarkable how a year can change perspectives. Year-over-year, global crude oil demand is up over 5%, nearing pre-COVID levels, and global oil prices have risen by over 50%, with WTI and Brent trading at $90 a barrel. The Permian Basin, essential to our financial success, exceeded our 2021 expectations, finishing the year at approximately 5 million barrels a day, with crude oil production growth of approximately 540,000 barrels a day compared to year-end 2020. We anticipate the basin to add around 600,000 barrels a day annually for the next several years, and our asset base built over decades is poised to capture future growth with significant operating leverage and modest capital requirements. Additionally, we have a substantial NGL position in Canada, with asset optimization and emerging energy opportunities across our footprint. All of this places us in a strong position to continue improving our financial flexibility, reinforcing our confidence in the long-term outlook for our business. This afternoon, we reported fourth quarter and full year 2021 results that exceeded our expectations. Furthermore, we provided 2022 full year guidance, incorporating Plains' share of the Permian joint venture. We have revised our reporting segments to create two business segments, one for each of our crude and NGL businesses. This aligns more consistently with how we view and operate our business. Our 2022 adjusted EBITDA guidance attributable to Plains is $2.2 billion, indicating about $200 million of growth when accounting for unique items benefiting 2021. Al will discuss further details during his presentation. As illustrated on Slide 4, 2021 was a year of solid execution for us in a competitive environment. We executed well and achieved our goals set out in February to maximize free cash flow, complete our multiyear capital program, optimize our portfolio, and advance our sustainability efforts. We generated approximately $1.65 billion of free cash flow after distributions, exceeding our February forecast by about $600 million, primarily driven by asset sales that outperformed our target by $125 million, continued capital discipline with reduced capital expenditures of about $230 million versus initial guidance, and further operational and commercial optimization. We repaid $1 billion of debt, built $450 million of cash on our balance sheet, and repurchased $175 million of our common equity, culminating in $228 million of cumulative repurchases since November 2020. We also completed our multiyear capital program, with the Capline Reversal and Wink-to-Webster projects now in service. Moreover, we are actively integrating our Permian assets with the Oryx system and are confident that the joint venture will yield at least $50 million in consolidated run rate synergies in 2022. Additionally, we made significant progress in our sustainability initiatives, establishing a new Health, Safety, Environmental, and Sustainability Board Committee for enhanced oversight and perspectives. Regarding our emissions profile, we have increased disclosure around our Scope 1 and Scope 2 emissions, reflecting ongoing reductions over the past three years, with absolute emissions at the lower end of our peer group. We expect to maintain this improvement trajectory through our emerging energy team, which is focused on capital-efficient opportunities to optimize our existing assets and reduce emissions. Operational excellence is a primary focus in our sustainability efforts, and we strive to maintain high standards. We’ve made substantial progress in our key health, safety, and environmental metrics over the past five years, achieving a reduction in federally reportable releases and total recordable injury rate by approximately 40% and 50%, respectively. Although we missed our 20% reduction targets in 2021, we did see a 25% decrease in the severity of incidents and lost time days down more than 90%. I'm confident in our ability to continue improving moving forward. Regarding capital allocation, our objectives and initiatives remain focused on maximizing free cash flow and allocating it through a balanced approach, continuing to prioritize debt reduction in the near term while enhancing cash returns to our equity holders over time. Based on our progress thus far and our forecasts for meaningful cash flow generation over the coming years, we plan to recommend to our Board an increase in our annualized distribution of $0.15 per common unit. This recommendation, based on our guidance, will maintain the capacity for ongoing discretionary repurchase activity. Our anticipated 2022 coverage ratio, considering the distribution rate we plan to recommend to our Board, is approximately 250%, providing room for responsibly returning additional capital to equity holders over time. Al will share further insight on our financial strategy and capital allocation priorities later in the call. Now I'd like to share thoughts on industry fundamentals, as shown on Slide 5. Global crude oil demand is nearing pre-COVID levels, with EIA and other third parties forecasting demand growth of approximately 3 million to 4 million barrels a day in 2022, and continued growth for the foreseeable future. We anticipate that this demand growth, coupled with a multiyear backdrop of reduced upstream investment and OPEC discipline, will exacerbate several market concerns currently being encountered, including tight global markets and ongoing commodity price volatility. Consequently, over the longer term, we expect American energy supply to play a pivotal role in meeting global demand growth, with the Permian poised to drive a significant share of U.S. production growth. Against this macro backdrop, we foresee generating substantial cash flow over multiple years supported by our integrated business model, spanning producing regions to essential markets and export hubs. Our asset footprint is quite flexible with operating leverage, particularly in the Permian, alongside modest capital investment needs for several years to come. With that, I’ll turn the call over to Al.

Thanks, Willie. To begin my segment of the call, I will discuss our new crude oil and NGL reporting segments as well as the treatment of non-controlling interests within our financial reporting. Our new segments reflect how we manage our integrated crude oil and NGL systems, aggregating supply from producers, delivering to end market demand, and all intermediate steps. We believe that these new segments will provide better visibility and transparency into the main drivers of our overall business while reducing intersegment activity. Additional information regarding the new segments will be disclosed in our 2021 10-K filing. For reference, we have included segment-specific materials in the appendix of today’s presentation, which include historical, financial, and operating data by quarter. As a reminder, our NGL segment typically generates seasonally stronger results during the winter months. Concerning our Red River and Permian Basin JVs—which are both consolidated in our financials—we are reporting adjusted EBITDA attributable to PAA, which excludes EBITDA related to non-controlling interests as our segment measure for both historical and forward-looking assessments. The adjusted EBITDA attributed to the non-controlling interest in our Red River JV is $17 million for 2021. Thus, our full-year 2021 adjusted EBITDA guidance of $2.175 billion provided in November corresponds to an adjusted EBITDA attributable to PAA of $2.158 billion, which compares to our 2021 actual results of $2.196 billion. Now focusing on the quarter, an overview of our fourth quarter results is illustrated on Slide 6. Fourth quarter segment adjusted EBITDA reached $564 million, driven by stronger-than-expected performance of our Canadian crude and NGL businesses as well as better volume throughput across our Permian pipeline systems. A summary of our full year 2021 results and 2022 financial and operating guidance has been included in Slides 7 and 8. We’ve adjusted our guidance approach by providing annual guidance only, projecting our expected year-end leverage ratio and including this information within our quarterly earnings slides. For 2022, we expect to generate full year adjusted EBITDA of $2.2 billion, $2.1 billion of cash flow from operations, and $1.4 billion of free cash flow. We also expect to end the year with a leverage ratio of roughly 4.25x, which has been further explained on the slides. It’s worth noting that our cash flow from operations and free cash flow guidance incorporate reasonable assumptions for short-term working capital needs and do not consider material unforeseen impacts. We anticipate approximately $100 million of asset sales in 2022, which includes $50 million deferred from 2021 that closed in January. Please allow me to put our 2022 adjusted EBITDA guidance in perspective relative to the 2021 results, illustrated by the EBITDA walk on Slide 9. The 2021 results included unique items totaling around $200 million cumulatively. These items comprised net margin activities, including crude oil contango profits from positions established in 2020, partially countered by enhanced NGL margins. Additionally, 2021 featured seven months of earnings from our gas storage assets and one-time items related to Winter Storm Uri. We expect the unique items from last year to be largely offset by approximately $200 million of growth, encompassing benefits from Permian volume growth expectations, Permian JV synergies, and recent project completions. Moreover, we anticipate that 2022 will benefit from resumed activities at our Fort Sask facility and tariff escalations, which we foresee as a modest uplift after factoring in inflationary effects. Moving forward, Slides 10 and 11 provide overviews of our financial strategy, capital allocation priorities, and our current financial profile. Our focus continues to be on maximizing free cash flow and allocating it through a balanced strategy that emphasizes debt reduction in the near-term while increasing cash returns to our equity holders over time. Due to our progress to date and prioritizing debt reduction, Moody’s upgraded Plains to investment grade in November. As demonstrated on Slide 11, we have established a new leverage ratio that closely aligns with that of rating agencies, targeting a range of 3.75x to 4.25x. Our leverage currently exceeds the high end of this range, reinforcing our commitment to further debt reduction. We believe that the new ratio and our projected year-end 2022 leverage, as part of the guidance process, will provide greater clarity regarding our capital allocation decisions. Slide 12 summarizes our capital program. Having completed our multiyear build-out, we remain focused and disciplined with must-do, no-regrets capital projects. Net to Plains, we expect 2022 investment capital to be around $275 million and maintenance capital at approximately $210 million, which includes a $35 million NGL facility turnaround. Going forward, we anticipate an annual run rate for investment capital of $250 million to $350 million and maintenance capital to be less than $200 million, including about $50 million related to non-controlling interests. Slides 13 and 14 showcase our sources and uses of cash for 2021, our current guidance for 2022, and our directional expectations for capital allocation in 2023 and beyond. Including asset sales in 2021, we generated about $1.65 billion in free cash flow post-distributions, with almost 90% allocated to debt reduction and the remaining $175 million to common equity repurchases. The debt reduction allocation encompasses $450 million in cash on the balance sheet at year-end, mainly to be applied towards the early retirement of $750 million of senior notes due on March 1, 2022. In 2022, we expect to settle into a more normalized cash flow profile driven by business performance and capital discipline rather than relying on asset sales. We forecast free cash flow after current distributions at around $700 million, allocating about 75% to debt reduction and the remaining 25% supporting the planned distribution increase as well as discretionary repurchase activity. As we aim for the upper limit of our leverage range by year-end 2022, we possess a favorable position in 2023 and beyond to further increase the proportion of free cash flow allocated to equity holders while diminishing the percentage allocated to debt reduction. With that, I will turn the floor back to Willie.

Thank you, Al. Well, 2021 was a strong year for our business, delivering significant free cash flow, which enabled us to reduce absolute debt levels and return capital to our equity holders. Looking ahead, we are well-positioned to drive multiyear free cash flow generation and unitholder returns. There are four primary levers to boost our cash flow, as illustrated on Slide 14: first, the operating leverage of our core Permian business, bolstered by improving global fundamentals; second, our integrated NGL operations and opportunities associated with those assets; third, the continued optimization of our existing assets, including renewable opportunities; and lastly, our improving financial profile. Overall, we feel positive about our positioning, and we are very optimistic about the future. As highlighted throughout the call, 2021 was marked by strong execution. Additionally, I would like to acknowledge our entire Plains team for their dedication, perseverance, and patience throughout what was a challenging year in 2021; I want to thank them for their continuing contributions to the partnership. A summary of our goals for 2022 and key takeaways from today’s call are provided on Slides 15 and 16. Now I’ll turn the call over to Roy to guide us into the Q&A session.

As we enter the Q&A session, please limit yourself to one question and one follow-up question, returning to the queue for additional follow-ups. This will enable us to address more questions from participants within our available time this afternoon. Additionally, our investor relations team will be available throughout the week to address further questions. Chris, we’re now ready to take questions.

Thank you. Our first question comes from Keith Stanley of Wolfe Research. Your line is open.

Hi. Thank you. Maybe I could start with the dividend and the 20% increase. From here, I’m assuming you’re considering an annual assessment of the dividend. Once balance sheet objectives are fully achieved and not just at the top end, how do you envision the payout ratio as a percentage of free cash flow? It’s still a bit low compared to peers. Is there any guidepost you would use to size the ultimate dividend once you hit your balance sheet targets?

Yes. Thanks, Keith. To start, we’ve maintained an annual dividend policy review ongoing for several years. This is not a deviation from that approach, and we’ll continue that going forward. My view on our allocation is that we're likely seeing a small shift. We mentioned free cash flow after distribution and outlined a capital allocation wedge that devotes 75% to debt this year, targeting 25% for unitholders through distribution increases and discretionary purchases. Moving forward, free cash flow is expected to remain robust for a number of years. As debt decreases in 2023, the allocation will shift to favor unitholders. Ultimately, we’ll start allocating based on a certain percentage of free cash flow from operations as a metric going forward. Al, would you like to add to that? Does that clarify things, Keith?

That helps. Thank you. Separate question. Referring to the waterfall on Slide 9. In the Permian bucket, you have several positive drivers indicated. However, I noticed some commentary on volume growth in the system; it's actually on Slide 8. It mentions 350,000 barrels a day of core year-over-year volume growth as some of the volumes shift to Wink-to-Webster. Are your margins on your existing long-haul pipeline decreasing at all in 2022? Or is it merely a matter of volume shifting over to Wink-to-Webster while you remain at MVC levels, so there's no significant hit to EBITDA, if that makes sense?

Well, Keith, I have two observations on that: first, we noted that there is a significant shift with the new pipeline coming online. Wink-to-Webster clearly takes volumes that previously used to flow through our assets and contributes to what I would categorize as durable volumes capable of ramping up. So that represents a change from 2021 to 2022. As for the competitive environment, the way I characterize it is we are in a very competitive landscape, resulting from the reset of production due to COVID—long-haul lines have been left with excess capacity. This trend has continued over the past few years and is expected to persist until production starts balancing with capacity.

Okay. But I thought you were already operating at MVC levels in 2021 on those long-haul pipes. Should we then expect the shift to Wink-to-Webster to present an obstacle for the company in 2022? Or is it primarily a matter of volume?

So a good example would be the basin pipeline, which does not have MVCs. In 2021, we were able to capture volumes moving to Cushing, and looking into 2022, we expect more of those volumes to shift to Wink-to-Webster. Jeremy, would you care to add anything to this discussion?

Keith, this is Jeremy Goebel. A few points. One, you are correct that we’re currently at MVC levels. However, it's not only Plains' assets affected; some of the MVCs to Houston may not be filled either, influenced by the fixed demand for Houston. This can be impacted asymmetrically. There are cyclical components that play into demand dynamics. We monitor this interplay—when inventories diminish at Cushing, you will observe pullbacks from the basin system. Thus, demand will ebb and flow as demonstrated throughout the quarters last year. As the Permian Basin fills, Midland is expected to weaken, making demand more stable but subject to cyclicality throughout the year. We see that Mid-Continent demand will be largely contingent on refining runs in that area. With regards to Gulf pipelines, they're largely shielded by MVCs, but the spot capacity will mirror market conditions. While there might be some opportunistic ventures that may fade away, a portion will still exist. The Wink-to-Webster pipeline will see T&D levels at Cactus II and Cactus I which will be in place. The marginal spot capacity as Midland and MEH come in will show different tariffs, such as incentive tariffs. This will be a potential headwind, along with a minor impact on volume. Yet, by and large, we will contend for barrels across the system and continue our long-held efforts to fill them.

That’s helpful. Thank you.

Thank you. Our next question comes from Michael Blum of Wells Fargo. Your line is open.

Thanks. Good evening, everyone. For my first question, could you address how much operating leverage exists in the Permian as volumes ramp—let's say, that 600,000 to 1 million barrels a day that you're predicting? How does that annual growth translate into EBITDA growth for PAA?

Jeremy?

Thanks for the question, Michael. It’s somewhat more intricate than it appears. Think of the next 600,000 barrels primarily in the next 18 to 24 months on a long-haul basis, since that will fill MVCs and ramp new lines like Wink-to-Webster. There's leverage on the gathering system, which is dedicated barrels at existing tariffs. This presents a single touch barrel plus everything we can perform on marketing with quality segregations and pump overs within that business structure. There’s a throughput component, followed by a tariff component. Beyond that point, you begin to see significant leverage from increasing spreads to the Gulf Coast for external markets. So it's not a linear progression; it will show a certain impact this year and next, which we anticipate to be amidst competitive market conditions, but it will ramp up significantly over time due to volume, tariffs, and multiple touch barrels.

That's helpful. Thank you. My second question pertains to the NGL segment. I wanted to ascertain if the earnings derived from this segment come primarily from the Canadian assets. Regarding guidance, what’s driving the year-over-year improvement in the NGL segment? I believe the EBITDA is up by roughly 33% according to the guidance?

Yes, Michael, you are right. It mainly pertains to Canada. We also own some terminals and facilities in the Lower 48, but fundamentally, Canada is the primary focus. To understand the change between last year and this, the predominant factor is the frac spread environment. The decision to re-segment should improve transparency as we discuss our operations; we think it is beneficial. Thus, the primary driver here is the difference in the frac spread environment from last year to this year.

Thank you. I appreciate it.

Thank you. Next, we have Jean Ann Salisbury of Bernstein. Your line is open.

Hi. Do you see the potential looming lack of Permian gas takeaway as a threat for Plains’ growth post-2023, especially if E&Ps prefer not to flare this time?

I can assure you, Jean Ann, that producers will avoid flaring. Hence, there will be mounting pressure on gas takeaway. Although we don't operate long-haul gas lines in the Permian, other conversations imply that your timeframe of around two or three years—2024-ish—will suggest the necessity for solutions. Discussions about new builds and possible repurposing lines have taken place. However, as we've noted before, this is a complex issue due to various parties and existing contracts. Monitoring this situation remains crucial as we proceed.

Okay.

Just a follow-up on that. From a long-haul standpoint, multiple players hold firm capacity. Their growth is essentially protected. Therefore, as production arises chiefly from those sources, the undedicated components will face greater restrictions. When assessing customer growth at this time versus past alignments with larger customers, we account for those barrels in our growth expectations. We're carefully managing those issues and actively paying attention to them, particularly the constraints on gas takeaway and some supply chain concerns. Discussions on regulatory matters concerning water are also being followed. So, while we monitor these considerations, we are cautiously optimistic that the industry will reach feasible solutions.

Great. Thank you. Moreover, you previously mentioned this, but I'd like to confirm your stance: Plains is less likely to convert a crude pipe to gas compared to some other pipelines in the basin?

Jean Ann, this is Jeremy. Due to the specifications required, including thicker wall thickness and larger diameter pipelines, our existing infrastructure makes it technically challenging for us to convert any crude pipelines to gas.

Okay. Great. That’s all for me. Thanks.

Hi. Good afternoon.

Hi, Jeremy.

I wanted to dive deeper into the guidance concerning EBITDA. Reviewing the fourth quarter, I acknowledge that there’s some seasonality involved. However, should I annualize the Q4 2021 figure, it exceeds the 2022 guidance. Therefore, I’m curious—does the 2022 guide account for the S&L side, or does re-segmenting influence it? Or does the volume fill from Wink-to-Webster offset all the Permian growth? Help me clarify why the 2022 guidance is lower than the fourth quarter.

Yes, Jeremy, there is an array of volumes set to shift from 4Q as we previously mentioned, primarily onto the Wink-to-Webster line. Therefore, drawing a direct comparison with the Q4 run rate isn’t entirely accurate. Jeremy, would you like to add?

Indeed, Jeremy, from a modeling standpoint, regarding seasonality within the NGL segment, the appendix shows the NGL business generating $140 million of EBITDA. By subtracting that and annualizing crude based on existing forecasts—about a $425 million quarterly run rate—our projected crude run rate is close to $455 million this year. Notably, various timing related to sales and MVCs have influenced this outlook. However, by and large, the crude segment is projected to grow to a run rate of around $140 million or $130 million year-over-year, with the NGL business likely stabilizing around more normalized quarters.

It's crucial indeed to factor in the NGL seasonality as it exerts significant influence.

Understood. Thank you for that clarity. Regarding capital allocation, you provided comprehensive insights today. I just want to explore further. The projected CapEx for 2022 seems somewhat elevated compared to a typical run rate. I assume this correlates with synergies with Oryx or initial projects in that vein. Is that the main catalyst, and should we anticipate a reduction in future years? As for buybacks versus dividends, we were anticipating a more significant tilt towards buybacks due to Plains trading at one of the lowest valuations in the sector. As we progress, how do you envision the buybacks relative to dividend growth?

Al, would you like to address this?

Yes, certainly. As we balance returning capital to our equity holders, it's fundamentally a blend of distributions and repurchase activities. Given our MLP structure, we regard distributions as the primary method for capital return. We aim to balance both efficiently. The capital is generally aligned: we're estimating around $330 million of consolidated investment capital, while the expected net figure lands around $275 million. The consolidated figure rises due to the additional joint venture's influence. This year's maintenance capital requires additional investment owing to one turnaround project; hence, we expect it to range higher than previously anticipated. Going forward, we will increasingly detail CapEx on either a gross or consolidated basis.

Moreover, everything Al stated is accurate. I want to underline that we are projecting significant future free cash flow. The takeaway from the suggested $0.15 annualized distribution is indicative of our confidence in our future cash flow trajectory. To reiterate Al's point, we see distribution increases and share repurchases as complementary, and our recent data supports our capacity to execute both. We have ample coverage, and the purposeful recommendation aims to maintain flexibility for repurchases at appropriate opportunities.

Got it. I’ll leave it there. Thank you.

Thank you, Jeremy.

Thank you. Next, we have Tristan Richardson of Truist Securities. Your line is open.

Good evening, team. I appreciate the insights into the new segments. I know it’s not a flawless metric, but you used to assess and communicate guidance via an EBITDA per transport barrel metric. Observing the 2022 crude segment volume guidance against the crude segment EBITDA suggests a per-barrel EBITDA that seems lower than what had previously been discussed. Should we simply view this through the lens of net EBITDA relative to PAA compared to gross volumes? Additionally, are you also factoring in marketing activity within that EBITDA figure?

Yes, this is Al. I’ll explain. When we consolidated all crude businesses into one segment, we didn’t believe it advisable to choose a single volume metric for calculating per unit valuations given the intrinsic differences and variables. The previous approach was not without flaws; we often adjusted our volume selections based on drivers’ conditions. Today, what’s represented in our volumes includes pipelines, the commercial capacity we leverage, and the lease purchase activity. Since not all barrels equate to equivalent cash flow, we opted not to present a numerical calculation. To that end, historically, pipelines might be more significant drivers, with purchased lease volumes potentially leading to duplicities. Hence, we chose not to carry out the calculation.

Thank you for that clarification. You noted priorities for CapEx and maintenance capital focused on optimization, as well as one-time projects. Could you provide examples of opportunities that may fall under that optimization strategy?

Of course, Tristan, this is Chris Chandler. We are evaluating several optimization opportunities. Some of the more advanced projects are related to our Canadian assets, particularly our fractionating facilities. These expanded capabilities enable additional throughput, enhancing NGL production and/or offering fee-based services. Moreover, in terms of environmental, social, and governance (ESG) considerations, we’re convinced that energy efficiency is conducive to both business success and lower emissions. We are identifying chances to curtail energy use and enhance efficiency at several of our larger facilities, and we plan to pursue those with favorable return profiles.

Tristan, one other point I want to add is that in our NGL division, we possess extensive and sizable complexes, encompassing straddle plants and fractionation facilities. Over the last few years, we've focused on optimizing the ownership structure within these facilities, as they are frequently segmented among multiple stakeholders. We have swapped our Milk River asset for proportional interests that would allow us to enhance these operations into a more unified system, which provides numerous optimization opportunities. This is an excellent example of our approach.

Thank you, Willie and Chris. I appreciate the insights.

Thanks, Tristan.

Hi, guys. Thank you for taking my question. Earlier, you mentioned approximately $50 million in synergies for Oryx, expected in 2022, potentially increasing to $100 million over time. Where should we specifically anticipate these synergies to manifest in terms of line items?

To clarify, we stated $50 million in 2022, growing to $100 million in future years; these figures are based on the 8/8ths accounting standard. Jeremy, would you like to elaborate on the specifics of where these synergies may arise?

Certainly, Becca. The synergies can be expected across multiple fronts. Approximately half is likely to come from reduced capital expenditures that we would have required while operating as standalone entities. For example, we had (prior to the merge) capital allocated to enhancing volumetric throughput. By integrating to the Oryx system, we are given the potential to connect dedications more effectively, improving pipeline utilization. The remaining operational synergies will stem from optimized capital management, which we project will positively affect EBITDA, thereby improving free cash flow.

Thank you. Additionally, I’d like to follow up on Michael Blum's previous question concerning the NGL segment guidance. You indicated that the frac spread environment was a significant factor—can you elaborate on what specifically has changed in that space?

Jeremy, care to explain that?

Certainly! To contextualize the frac spread metrics, consider buying AECO gas and marketing it on a Mont Belvieu-type basis for NGL at around plus or minus a nickel. The cost reimbursement for ethane to basic structure often plays into these numbers. With liquids prices soaring relative to natural gas levels, we’ve seen a material uplift in frac spread values. Hedge contracts established in prior years influence market dynamics—this shift led to the frac spread moving from the 50s to over $0.70 at present. Thus, a margin of around $0.15 in frac spread across our entire program largely drives this change. Additionally, increased demand due to colder weather in the Northeast has also fueled elevated volumes through our straddle plants. Altogether, it’s a combination of volume and margin components but revolves primarily around the commodity pricing in that sector.

Great. Thank you.

Hey, guys. Thanks for taking my question. I have a couple. First, looking at the fourth quarter volumes in the Permian, around 5.2 to 5.3 million barrels a day—does your guidance for 2022 imply you expect production levels to remain flat compared to the fourth quarter actuals? Is that how I should think about it?

This is Jeremy Goebel. Yes, and to clarify, part of this is due to a decline in longer-haul volumes, but it’s somewhat nuanced. Volumes transitioning over to Wink-to-Webster correspond to about 16% of overall volumes, while legacy systems might maintain between 88% to 100%. Therefore, gross volumes are rising, even if net volumes are falling, as we also expect increased growth within the gathering systems. That aligns with our projections for 2022 and potentially parts of 2023 as row reservations hint at sustained growth in our forecasts but suggest that those numbers might amplify moving forward.

Got it. The last question I have concerns timelines on Wink-to-Webster and Capline—how long should we estimate each to reach normalized EBITDA run rates? Are there staggered timelines for when contracts go into effect, and when can we anticipate these tolling agreements to impact fully?

For Wink-to-Webster, expect a substantial portion of volume commencing in February, leading to gradual increases over the next two years. We anticipate being at full capacity in approximately two years, contingent on market demands, inherently aligning existing contracts. For Capline, we initiated with existing MVC levels while actively marketing available capacity—roughly 100,000 barrels daily—without preceding capital and are presently in discussions with shippers. We’ll surely update you on these developments when appropriate.

Understood. Thank you, team.

Thank you. Our next question comes from Chase Mulvehill of Bank of America. Your line is open.

Hey, thanks for fitting me in here. I have a couple of questions. While some of this has been discussed, I want to dig a bit deeper. Can you discuss what Permian oil production levels would need to be realized before we see a noticeable increase in volumes heading to Corpus—Cactus’s area? Secondly, regarding what levels of Permian oil production would be conducive to picking up in Cushing volumes?

I’ll start this, and then Jeremy can provide his insights. When evaluating our system, we often receive queries regarding why certain barrels don’t flow in specific directions. What I want to stress is our system's inherent flexibility, which allows barrels to be directed in accordance with market demands, presenting a beneficial aspect. Although we may redirect volumes from one system to another based on market capacity, this flexibility remains a strength. Jeremy, do you have further thoughts on this?

To clarify, this year's production growth is anticipated to meet the incremental MVCs on Wink-to-Webster, but might not necessarily exceed them. Consequently, future production increases may fill the Wink-to-Webster pipeline while also addressing current production shortages. This dynamic should keep the market competitive over the next 18 to 24 months amid existing production forecasts. The shift after that point will allow MVCs to prompt rates, determining pricing on market conditions, ultimately leading to additional competitiveness towards Cushing.

So if I connect the dots from what you mentioned and your earlier comments, with 600,000 barrels of exit-to-exit growth and similar estimates next year in the Permian, do I infer correctly that with about 1.2 million barrels of Permian oil production growth, we might see significant operating leverage across the long-haul pipes? Is that fair?

At this junction, that is accurate. And yet, the constraints that impact those numbers have room to fluctuate. It's not a static equation, as you mentioned; it changes based on other pipeline MVCs rolling off. Hence, the dynamics can evolve.

Great, that's all I had. Thanks.

Thank you, Chase.

Thank you. Our last question comes from Brian Reynolds of UBS. Your line is open.

Hi, good evening, everyone. I’d like to follow up on capital allocation for a moment. You previously discussed balancing repurchases with dividend increases. Noticing your commitment to a 25% share of free cash flow going towards returns to capital—this indicates a rough 50-50 split between distributions and buybacks. Is that a constructive way to think about buybacks this year, around that $90 million mark? Looking beyond 2022, could we see an increase in free cash flow directed more towards distributions or buybacks?

Yes. Brian, your calculations are mostly correct. Reflecting on Slide 13, our projections for free cash flow after distributions prior to any increase this year indicate that our allocation toward equity holders is balanced between the two amounts. Recall the figure you stated concerning the 25% allocation to equity holders; it encapsulates both distributions and buybacks. As we refine our focus on driving free cash flows, we're prepared to pivot and shift allocation to favor shareholders, especially as debt levels decrease.

That’s quite helpful. Finally, concerning the Permian guidance options previously discussed—should we view 2022 as sequentially focusing on filling Wink-to-Webster MVCs while possibly yielding greater uplift in 2023?

Yes, it is prudent to think about that transition. While next year’s production will balance the MVCs on Wink-to-Webster and leveraging existing capacity, we aim to uncover incremental barrels, but we won't overextend services, as current production forecasts signal robust competitive positioning for the time being. The conditions will pivot as we fill the existing MVCs and establish market rates, which heightens overall competitiveness.

Excellent insights. I appreciate the discussion.

Thank you, everyone. I believe we have time for one more question from an analyst before concluding.

Thank you. Our last question comes from Timm Schneider of Citi. Your line is open.

Hey, thank you. If I calculate the $150 million in full well connects for 2022, how should we interpret the cycle time for that CapEx? Specifically, will some of that exhibit itself in EBITDA in 2022 or is this outlook for longer-term gains?

Jeremy?

Consider that a continuous cycle. The gross figure aligns around $150 million, while it’s $100 million net to Plains. The returns from that equate to declines in wells and exhibit continuous cash flow operations. Hence, the periodic returns could be expected on a regular basis. During each period, you can anticipate projects phased in at intervals of four to six months. It’s not merely an extensive project that requires upfront capital.

Understood. Shifting gears, you previously mentioned capital synergies of $50 million anticipated from Oryx, incrementally growing to $100 million. What’s the projected EBITDA contribution from Plains of Oryx in 2022?

That's an 8/8ths figure. If you account for 65% of the total, please note that this encompasses half attributed to capital reductions, with the other half corresponding to EBITDA-enhancing initiatives. Thus, the total EBITDA contribution net to Plains rests at 65% of the planned $50 million while accounting for general operational enhancements.

Thanks for clarifying that. Also, regarding the anticipated 600,000 barrels a day increase—is this an exit-to-exit figure?

It is indeed an exit-to-exit measurement for this year and roughly consistent.

Thank you, Timm.

Thank you everyone for your participation today. This concludes the conference call. You may now disconnect and have a wonderful day.