Thank you, Therese. Good afternoon, and welcome to Plains All American's Third Quarter 2022 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. An overview of today's call is provided on Slide 3. The 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 Chief Financial Officer. Other members of our team will be available for Q&A, including Harry Pefanis, our President; Chris Chandler, Executive Vice President and Chief Operating Officer; Jeremy Goebel, Executive Vice President and Chief Commercial Officer; and Chris Herbold, Senior Vice President, Finance and Chief Accounting Officer. With that, I will now turn the call over to Willie.

Thank you, Roy, and thank you, everyone, for joining us this afternoon. Today, we announced strong third quarter results above our expectations, reflecting continued execution of our long-term goals and initiatives and our strong performance in both our Crude Oil and NGL segments. In summary, third quarter adjusted EBITDA, attributable to PAA, was $623 million. We increased our full year 2022 adjusted EBITDA guidance by $75 million to $2.45 billion, which is $250 million above our initial February guidance. The year-to-year increase is driven by outperformance in both our Crude Oil and NGL segments due to the capture of additional volumes, higher commodity prices, and favorable margin-based opportunities. Additionally, today, we announced and closed an $85 million acquisition of an additional 5% in the Cactus II pipeline, bringing our total ownership to 70%. Importantly, we ended the quarter with a leverage of 3.7x and expect to end the year at 3.8x, both below the midpoint of our targeted leverage range. This supports increasing returns of capital to our equity holders. As such, within today's earnings release, we laid out a multiyear capital allocation and financial framework, which I will discuss shortly. Before that, I wanted to reiterate our views on why we remain constructive on long-term industry fundamentals. Notwithstanding global economic uncertainty and continued volatility in the commodity markets, we continue to expect global energy supply and demand to remain tight. As shown on Slide 4, for the past several years, and for a number of reasons, there's been a lower level of investment in the upstream sector, reducing resource development. At the same time, energy demand continues to grow while historical supply buffers in the form of OPEC+ spare capacity and global inventories are greatly reduced and have been further impacted by recent geopolitical events. Year-to-date, we have seen U.S. strategic petroleum reserve draws of approximately 190 million barrels and commercial inventories remain below historic levels over the same time frame. Global markets remain tight, and the world needs short cycle North American production growth. As summarized on Slide 5, we've made meaningful progress on our long-term goals and initiatives. And as such, 2022 is a positive inflection point for Plains. For the last several years, we have focused on deleveraging by maximizing free cash flow and reducing absolute debt. The success of this effort, when combined with solid operating, commercial, and financial performance, enabled us to achieve our leverage objectives well ahead of our initial expectations and to accelerate returns to equity holders while providing greater clarity on our multiyear capital allocation framework. As described in our press release this afternoon, we provided updates to our capital allocation and financial framework as follows. We currently intend to recommend to the Board a $0.20 per unit annualized increase of our quarterly distribution payable in February 2023. Beyond 2023, as part of our annual budget review process with the Board, we anticipate targeting annualized distribution increases of approximately $0.15 per unit each year until reaching a targeted common unit distribution coverage ratio of approximately 160%. We anticipate leverage migrating below the low end of our targeted range of 3.75x to 4.25x in 2023, and consistent with our objective in achieving and maintaining our mid-BBB and equivalent credit ratings. Additionally, opportunistic unit repurchases will remain a component of our capital allocation framework, which will be a dynamic assessment of business outlook, market environment, and capital allocation options. As we look forward, we remain focused on driving shareholder value and improving the resilience of our earnings by leveraging our existing crude oil and NGL infrastructure. This includes capital-efficient brownfield expansions and debottlenecking opportunities underpinned by contractual commitments, potential bolt-on acquisitions such as the Advantage JV and the acquisition of additional interest in Cactus II, and the optimization and alignment of existing assets with emerging energy opportunities. In Canada, we recently completed a win-win noncash transaction to gain full ownership of our existing Empress facilities in exchange for a long-term processing capacity lease at the facility, allowing us to further optimize and operate the assets more efficiently over time. Additionally, we continue to evaluate capital-efficient debottlenecking and expansion projects around our four Saskatchewan facilities and hope to be able to share additional details over the next coming quarters. With that, I will turn the call over to Al.

Thanks, Willie. We reported third quarter adjusted EBITDA of $623 million, which includes the benefit of increased volumes across our systems primarily within the Permian, higher commodity prices as well as Canadian margin-based opportunities. Slide 17 and 18 in today's appendix contain quarter-over-quarter and year-over-year segment adjusted EBITDA walks, which provide more detail on our third quarter performance. A summary of our progress on our goals, key financial and operating metrics and 2022 guidance is located on Slides 6 through 9. We've increased our full year 2022 adjusted EBITDA guidance by $75 million to roughly $2.45 billion primarily driven by our strong third quarter performance. Slide 6 shows our key 2022 financial metrics and reflects strong distribution coverage of 265% and free cash flow after distributions of $670 million, which provides ample capacity supporting our multiyear capital allocation framework. I would note that we have left our asset sales target at $200 million, but as a result of current volatility in capital markets, the remaining $140 million that have been closed could shift into the first half of 2023. Additionally, going forward, Cactus II will be consolidated into PAA's future financial statements. Similar to the Permian JV, volumes will be reported on a consolidated basis and earnings on a proportional basis. Before providing more detail on today's capital allocation announcement, I wanted to share a few directional comments on 2023 with formal guidance to come early next year. We continue to expect growth in our Crude Oil business primarily driven by our Permian operating leverage and improving margins on short-term contracted long-haul opportunities. For our NGL segment, we currently anticipate lower C3+ spec sales volumes due to third-party facility turnaround and absence of 2022 weather benefits. Furthermore, current forward markets indicate lower year-over-year frac spreads. The combination of these could lower 2023 NGL segment adjusted EBITDA by roughly $100 million versus 2022 guidance. In regard to capital allocation, our proposed long-term capital allocation framework and financial strategy are summarized on Slides 10 through 13. We are focused on generating meaningful multiyear free cash flow and improving shareholder returns by increasing returns of capital to equity holders, making disciplined accretive investments, and ensuring balance sheet flexibility. With respect to increasing returns of capital to our equity holders in a long-term, sustainable manner, as shown on Slide 11 and detailed in our earnings press release, we intend to recommend to our Board an annualized increase of $0.20 per common unit for our quarterly distribution to be paid in February, which is one quarter earlier than we would normally implement a change to our quarterly distribution. Beyond 2023, we will continue to evaluate our capital allocation program, financial positioning, investment opportunities, and business outlook with our Board of Directors as part of our annual budgeting process. Subject to that process, we currently anticipate targeting annualized distribution increases of $0.15 per unit each year until reaching a targeted common unit distribution coverage ratio of approximately 160%. Upon reaching our target coverage, subsequent distribution increases will be driven by future DCF growth and evaluated as part of our annual budgeting process. Opportunistic equity repurchases will remain a component of our long-term capital allocation program. Since the inception of the program, we have repurchased $300 million of our $500 million authorization or approximately 4% of our common units outstanding. With respect to capital investments going forward as summarized on Slide 12, we will continue our disciplined approach, focusing on high-return expansion and bottlenecking opportunities that leverage our existing crude oil and NGL infrastructure. Longer term, we continue to expect to self-fund annual routine investment capital through our excess cash flow and coverage. Regarding our balance sheet, as described on Slide 13, we have achieved our leverage goals and anticipate migrating leverage below the low end of our target range of 3.75x to 4.25x in 2023. We will take a prudent long-term approach focusing on increasing cash return to equity holders while maintaining and improving financial flexibility, consistent with our objective of achieving and maintaining a mid-BBB equivalent rating. Before I turn the call back to Willie, I wanted to provide a brief update on potential changes to the pricing of our Series A and Series B preferred equity securities. The Series A security issued in 2016 currently has a yield of 8% and contains a one-time option for holders to reprice the security based on the 10-year U.S. treasury rate plus 5.85%. The holders will have the opportunity to reprice the security during the 30-day period beginning in late January 2023. If the right is exercised, we would anticipate the yield increasing to approximately 10% based on current treasury rates. After repricing, we will obtain a call right at 110% par. Series B security issued in 2017 has a fixed yield of 6.125% for the first five years, shifting to floating on November 15, 2022, at a new rate of three-month LIBOR plus 4.11%. Upon the shift to floating, the security becomes callable at 100% par. If both were to reprice at current market conditions, total annual preferred dividends would increase by approximately $55 million a year to approximately $255 million per year. Even with the potential increase, we still have ample financial flexibility to continue lowering leverage and increasing returns of capital to common equity holders in a manner consistent with what we have described on today's call. With that, I will turn the call back to Willie.

Thanks, Al. Today's results reflect another solid quarter of performance and execution. Although we're monitoring current macro and geopolitical events, we believe long-term fundamentals remain constructive and that our business will continue to perform well in the current and longer-term environment. We've made steady progress reducing leverage and creating additional financial flexibility, which has positioned us to provide additional clarity on our multiyear capital allocation framework. We will continue to take a long-term disciplined approach to our business and the execution of our capital allocation priorities. We appreciate your continued interest and support, and we look forward to providing further updates along with our formal 2023 guidance on our earnings call in February. A summary of the key takeaways from today's call is provided on Slide 14. With that, I'll turn the call over to Roy to lead us through Q&A.

Thanks, Willie. Therese, we’re now ready to open the call for questions.

Our first question is from Michael Blum from Wells Fargo.

Maybe we can start with the distribution growth announcement here. It seems like you really tilted the scales towards distribution growth over buybacks. So I'm wondering if you could just talk through the thought process there.

Sure, Michael. Thanks for the question. We have. And the reason for that is, as we think about our capital allocation process, it's a dynamic matrix that we look at with a number of factors, and the goal is to really help improve the value of the company and the ability to generate additional cash flow, which we can distribute back to unitholders. And as we think about that, we feel the distribution is the most efficient way to provide returns back to unitholders versus buybacks. This is the reason and the progress that we've made so far that we've articulated this multiyear strategy.

Got it. Also, I just wanted to ask about Permian growth. I would love to get your latest thoughts on where things are trending, both for this year and into 2023. I'm sure you saw some of the comments from some of the majors on perhaps a slight slowdown. So I want to kind of get the lay of the land.

Well, Michael, I'll give you some comments. We are going to wait until February 2023 to provide detailed guidance. But where it stands right now, it's really in line with what we've expected. Year-end to year-end growth in 2022 is going to be roughly 650,000 barrels a day. We projected roughly a 10% increase in rigs, and we expect to be running about 150 to 160 rigs next year, which we will validate as we communicate with the producers over the next several months. I will highlight that with this growth, if you take a look at the market capture of our volumes, we have been very successful in capturing volumes into our gathering joint venture, which ultimately feeds the rest of the business.

Our next question will come from Keith Stanley with Wolfe Research.

I guess, sticking with the distribution, can you explain a little more how you came to the 160% minimum coverage threshold using DCF for future dividend growth? I also wanted to ask about the press going to variable rates, which is a pretty expensive source of capital. So how did you balance what's a very robust dividend growth plan against alternative uses like trying to pay down that preferred equity?

Yes, Keith. Let me take that, and I'll let Al talk about the press. For the 160% coverage, what we're driving for there is, as you know, we're funding CapEx from cash flow. And as we put this multiyear trajectory out on the increase, the 160% target is really a governor to ensure that we've got adequate coverage and cash flow to cover our routine CapEx expectations, our annual program, as well as some extra dry powder to continue taking our leverage down and be prepared for any challenges. So the 160% is to ensure that we're conservative and can fund our future CapEx.

Yes, I'll take a shot at the press. If it were repriced today, it would be about 10%. We view that right now on a 50-50 basis and how the equity component of that is less than our cost of capital today. We trade at a DCF yield of probably 18%. Ten-year money today is probably 7%, and a 50-50 split would be 13.5%. So while it's more expensive, it's still not more expensive when you compare it to our cost of capital. Since we are new into just having hit and achieved our leverage objective, we do not want to use a leveraging transaction to retire that cost in the near term. Our objective, as you heard in our comments, is to continue to move leverage down. So at some point, we may have the capacity to deal with that. But today, we don't believe it would be prudent to pursue that. It's manageable relative to what the current capital markets are offering, and we certainly don't want to use common equity to address it at this moment. However, all options could be on the table one or two years down the line. The important point is we see call options coming our way, which gives us some control over our future.

Got it. If I could just clarify a second question on your expectation to be below the low end of the leverage range in '23, and you gave some positives and negatives for next year. Is that assuming that you continue to repay debt with some of your free cash flow through 2023?

Yes. Our intent, again, if you think of what we are mentioning with the distribution and being capital disciplined on investments, we will still have very strong cash flow after distributions. Our intent will be to continue to reduce debt.

Maybe just to quickly follow up on some of the capital allocation questions. You have $2.2 billion in convertible preferred shares that can convert next year, but you also have long-term debt of $1.1 billion that could be refinanced in '23. So, as you approach the year, what are your priorities given the equity credit for the preferred shares? Is your priority to refinance that debt? Can you remind us of your liquidity, especially cash plus the revolver and your ability to use that to manage potentially a reduction in rates, say a year from now?

Brian, this is Al. As of the end of September, we had $3.3 billion of liquidity, which included $600 million of cash on the balance sheet. The cash is earning more than the first note that matures early next year, or we would have taken it out before the end of the year. While it would have been better to take it out at par just yesterday, we will retire it next year. Our intent would be to retire the $1.1 billion next year and not access the market, and that will be part of our deleveraging strategy. We would fully expect the preferred shares to remain outstanding. While rates are increasing, and obviously, we don't know where the Federal Reserve will stop, the floating rate could become an issue. But we do not intend to retire those next year.

Great. And maybe just a simple operational question. It seems like PADD II movements were a little noisy, particularly with some refinery movements. Can you talk about those intra-basin volumes during the quarter and if that's a trend that could continue into 2023 or if you think it's more of a singular event for the quarter?

Brian, this is Jeremy. The PADD II movements have low inventories at Cushing, and you haven't seen growth in the Rockies. Also, some facilities have gone offline in Canada, which has led to higher movements upstream due to the favorable crack spreads you're seeing specifically on the diesel side. We would expect that to continue as long as refining runs and demand remain strong. The intra-basin movements are a function of production growth in the Permian Basin. As gathering volumes grow, intra-basin volumes will grow correspondingly, and we expect that to continue as well.

And Brian, just reinforcing a point that we always like to mention. When you think about our system, there's a lot of flexibility and access to multiple markets. So I'll just remind you that barrels could be going to the coast, but if the markets are such that they want to go to Cushing, we have the capability to accommodate that. So that's one advantage of our flexibility.

It's Jeremy. I just want to dive in real quick here, a little more on the guidance. I think crude oil was $18.90 in August, and it was $19.55 now. I'm just wondering if you could provide a bit more color on what changed between August and now to drive that uptick.

Yes. The majority of it is due to the third quarter performance and some of the margin opportunities we've seen primarily in Canada, which were likely the bulk of the changes. We've also seen some temporary spot movements on our assets, but the margin opportunities were the majority.

Got it. And then pivoting over to Cactus. Just wondering if you could provide some color with regards to acquisition multiples or the expected accretion. Just trying to see how that fits in with other opportunities.

Jeremy, let me take this one. That was a win-win deal. It was beneficial for all parties involved. The way we view this is that West was interested in selling. It was a negotiated deal. Now, both Enbridge and us can strengthen our relationship. If you analyze our assets, we are stronger on the gathering side, while Enbridge is stronger on the downstream side. So it integrates well. Our expectation is that the joint venture will be able to extract additional synergies and volumes moving forward. I'll leave it at that without going into further multiples.

I just wanted to make sure I understand what's driving the crude pipeline EBITDA this year. On Slide 17, you have a useful bridge of the crude segment versus the last quarter, and you call out both increased volumes and also MVC payments. Does that mean that shippers are effectively paying you MVCs on pipelines that don't go to the Gulf Coast in the Permian, but then you're over your MVC level and getting spot rates on the pipelines that go to the Gulf Coast? And is that like a sustainable setup?

Jean, this is Jeremy. Yes, we are receiving some MVCs, but we're also replacing them with some incentive tariffs. We expect that to change as the shippers start to shift to their MVC levels, which we expect to happen shortly. So I would consider that a more temporary setup as spreads change. In Cushing, that's not solely based on MVC. There are components that are, and from a recontracting perspective, we continue to sign more on a term basis across both Cushing's corridor and the route to Corpus. So there's plenty of demand for capacity at increasing levels.

Got it. That makes sense. I was also wondering if there's been any update on the Fort Sask expansion. Should we be assuming any CapEx for that in 2023?

Yes. We're still developing the project, Jean. We don't have anything specific to report at this point. I expect that hopefully by our February call, we will have more information to share on that front.

Just wanted to look at the distribution in light of your commodity and volumetric exposure. You clearly benefit this year from the frac spread in Canada and your gathering rates have some volumetric exposure as well. Are you looking to term up some of the long-haul pipelines to maintain that fixed increase every year? How are you looking at that exposure?

Absolutely, we're evaluating ways to firm up additional volumes. I made a comment earlier about reducing the volatility and securing fixed volumes. So we're continuously working on that every single day. Do you have a specific area you would like me to elaborate on?

Yes. My question was really how you're looking at all the commodity exposure when you evaluated the fixed distribution increase. Are you comfortable with a certain run rate with the Canadian assets or just volumetric growth in the Permian?

I understand your question. When we look at higher prices, it definitely benefits us primarily in PLA, primarily in frac spreads. If you consider where we started the year, we had a more modest expectation of the crude oil environment, roughly $75. For the year, we're probably going to average close to $95. A portion of that is related to oil prices. However, moving forward, I believe we will capture some of that, and that has all been factored into our consideration for our distribution coverage moving forward.

Got it. And then my second question is regards to Cactus I and II in your Corpus Christi exposure. We've had record exports out of the Gulf Coast for two consecutive quarters. I wonder how sustainable you think that growth is into Corpus Christi in light of the exports. The second part of that would be how should we think about the MVC impact of the second round of minimum volume commitments from Wink-to-Webster?

Sure. The Corpus Christi expansion benefits from the continued deepening of the channels, which will benefit all docks. There's considerable capacity for exports. While the pipelines are filling up, the rates are increasing for the marginal capacity, which benefits the owners of the pipeline and docks. The infrastructure has the best logistics and the highest price, resulting in double the export activity compared to any other port. There are uses for exports across the Gulf Coast, but Corpus Christi will continue to receive a significant portion of those. So I believe that answers your first question. The second one regarding minimum volume commitments is consistent with what we stated in February. They are expected to ramp up in February of next year, and production growth this year has absorbed those MVCs. We would expect the same going forward. So growth aligns with our expectations, though there may be bumps due to natural gas takeaway or other factors. However, our long-term perspective is that we will continue to be at capacity to the coast with our pipelines next year, and any margin healing over time will require those MVCs to be absorbed by production growth. Are you still with us, Neel?

Yes, I am.

Fundamentally, our viewpoint is that global demand is going to persist for crude oil. When you consider the sources of exports, we think that they will largely come from North America. Therefore, we view this as a constructive environment for exports in the U.S.

I just wanted to go back to a comment you made earlier on year-over-year crude growth. Can you clarify if you were specifically discussing volumes or EBITDA or both?

I apologize. The numbers I was giving you were volumes from year-end to year-end, specifically from 2022 to 2023, of roughly 650,000 barrels a day. Just to clarify, regarding our expectations in 2023, the horizontal rig count in the Permian is assumed to be 350 to 360 rigs. Currently, we are running about 330.

Okay. And I thought you mentioned growth in the crude segment for '23, and I was curious if that was explicitly about volumes or earnings.

No, we didn't give any guidance on overall crude volumes. Jeremy, do you have any comments regarding that?

Yes. What you may have heard was that we would expect year-over-year growth. Our gathering system naturally benefits from production growth in the field. The comment was made to indicate that we forecast similar growth next year in gathering from this year, which will have some incremental growth due to increased volumes and margins from long-haul business, as well as a step-up in MVCs from the Wink-to-Webster project.

Got it. Do you think the growth you expect will outweigh any conservatism regarding the pricing deck that you would assume from pipeline loss allowance uplift or similar factors?

Michael, our intent was to provide directional insight regarding the impact of frac spreads since they have been significant. The aim was not to provide guidance for next year. We'll keep everyone updated in February regarding guidance for the Crude Oil and NGL business.

Additionally, we wanted to give you a heads up that there are planned outages that you might not be aware of. We wanted to inform you that this will have an impact on the NGL business.

So regarding the NGL segment, could you give us a sense of how much of your NGL exposure for 2023 is hedged at this time?

Sunil, we're not going to share that at this time. We'll disclose more information in February.

If I look at the metrics you laid out on Slide 6 with regard to the 2022 guidance update, it appears that adjusted EBITDA is increasing by $75 million. However, the implied DCF seems flat compared to your August guidance. What accounts for the difference that keeps the DCF flat?

Yes, this is Al. I'll address that. One reason is Canadian taxes; two, some timing differences around distributions and earnings on unconsolidated entities, as well as our non-controlling interest distributions to those entities. And lastly, we probably should have rounded down. Last quarter, we've been trying to keep those numbers kind of rounded. So it's a compilation of several factors, but it's a good question.

But your free cash flow is still increasing, so does that mean you recoup some of these factors when you consider free cash flow?

Correct.

Great. Thanks, Therese. Thanks, everyone, for joining us and for your questions and your interest in our company. We look forward to providing updates. Have a nice evening.

Good day. You may now disconnect. Have a good evening.