Hello and thank you for standing by. Welcome to the PAA and PAGP Third Quarter Earnings Call. Please be advised that today's conference is being recorded. I’d like to hand the conference over to your speaker, Roy Lamoreaux, Vice President, Investor Relations, Communications and Government Relations.

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 is located in the appendix. Today’s call will be hosted by Willie Chiang, Chairman, and I; 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 of 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 number of years and for a number of reasons, there has 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 plus 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 at or 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 '23, 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 3.75 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 4 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. Slides 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 approximately $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 in 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 per 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 3.75 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% of par. Series B security issued in 2017 has a fixed yield of 6.125% for the first 5 years, shifting to floating on November 15, 2022, at a new rate of 3-month LIBOR plus 4.11%. Upon the shift to floating, the security becomes callable at 100% of 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 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 the 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. 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 kind of 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 pretty dynamic matrix that we look at with a number of things. The goal is to really help improve the value of the company and the ability to be able to have additional cash flow which we can distribute back to unitholders. And as we think about that, we think the distribution is the most efficient way to do that in terms of getting returns back to unitholders versus buybacks. And it's really for that 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 to give detailed guidance. But where it stands right now, it's really in lockstep with what we've expected. Year-end to year-end growth in '22 is going to be roughly 650,000 barrels a day. We promised roughly a 10% increase in rigs, are running about 150 to 160 rigs next year, and that's what we'll have to validate as we go through the next number of months and talking to the producers. But I will highlight that with that growth, if you take a look at the market capture of our volumes, we’ve been very successful in being able to capture volumes into our gathering joint venture, which ultimately feeds the rest of the business.

I guess, sticking with the distribution, how can you explain a little more how you came to the 160% minimum coverage threshold using DCF for future dividend growth? And I also wanted to ask. You talked 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. On 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 kind of a governor to make sure that we've got adequate coverage and cash flow to be able to cover our routine CapEx expectations, our annual program, as well as a little bit of extra dry powder to be able to further take our leverage down and be prepared for anything that might present itself. So the 160% is really to make sure that we’re conservative and can fund our CapEx in the future going forward. Al, do you want to take the press?

Yes, I'll take a shot at the press. If it was repriced today, it would be about 10%. We view that right now on a 50-50 basis and how the equity component of that, it's less than our cost of capital today. We trade at, what, a DCF yield of probably 18%. 10-year money today is probably 7%; 50-50 would be 13.5%. So while it's more expensive, it's still not more expensive when you look at the components of it relative to our cost of capital. We're too new into just having hit and got to our leverage objective to use deleveraging or - leveraging, excuse me, i.e., go use debt to take that out in the near term. Clearly, our objective that 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 that would be prudent to use the leveraging traction to try to reduce that cost. It's actually pretty manageable relative to what the current capital markets are providing, and we surely don't want to use common equity to try to take it out at this point. But all of that could be on the table a year or 2 down the road. The important thing is we do see call options coming our way with this. So we do control our destiny a little bit when we get into a position to be able to deal with it.

Got it. The, 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 puts and takes on next year. Is that assuming that you repay - that you continue to repay debt with some of your free cash flow through 2023?

Yes. Our goal is to maintain strong cash flow after distributions while being disciplined with our investments. We aim to continue reducing debt and believe we'll see cash flow growth in the future. Ultimately, we plan to keep paying down debt to enhance our flexibility. We are not looking to establish a new range at this point; our intention is to move below the current range and operate there for a period before reevaluating.

Maybe just to quickly follow up on some of the capital allocation questions. You've got $2.2 billion in press that can convert next year but you also have the $1.1 million in long-term debt that could be refinanced in '23. So I guess I'm just curious as you enter the year, what are your priorities just given the equity credit for the press? Is it your priority to refinance that debt? And I guess kind of as a follow-up question. Can you just remind us of your liquidity, particularly the cash plus the revolver and your ability to use that to manage potentially a reduction in rates call it 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. It became where we could take it out at par here just yesterday. But we'll take it out next year. Our intent would be to take and retire the $1.1 billion next year and not access the market, and that will be part of our deleveraging. We would fully expect the press to remain out. Again, while the rates are going up and obviously, we don't know where the Fed will stop, so the one that floats may become an issue. But we would not intend to be looking at retiring those next year.

Great. And maybe just a simple operational question. It seems like PADD 2 movements were a little noisy, particularly with some refinery movements. Just kind of curious if you can talk about those intra-basin volumes during the quarter and if that’s something that could continue into 2023. Or if you think that’s more of a singular event for the quarter.

Brian, this is Jeremy. The PADD 2 movements, low inventories at Cushing and you haven't seen a ton of growth in the Rockies and you've even seen some facilities offline in Canada, which yields higher movements upstream with the crack spreads you're seeing specifically on the diesel side. So we would expect that to continue as long as refining runs and refining demand remains strong. So that would expect to continue, the intra-basin movements are a function of production growth in the Permian Basin. And you can almost look at it as the gathering volumes grow, and the intra-basin volumes grow accordingly; you would expect that to continue as well.

And Brian, just reinforcing a point that we always like to talk about. When you think about our system, there's 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 do that. So that's kind of the benefit of flexibility.

It’s Jeremy. I just want to dive in real quick here a little bit more on the guidance. I think for 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 third quarter performance and some of the margin opportunities we've seen primarily up in Canada were likely the bulk of it. We also have seen some just kind of temporary spot movements on our assets, but the margin opportunities were the majority of it.

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

Jeremy, let me take this one. That was a win-win deal. It was a good deal for everybody. The way we look at this is West was interested in selling. It was a negotiated deal. It allows now both Enbridge and us to strengthen our relationship. And I think the way it's set up is if you think about our assets, we're stronger on the gathering side. And if you think about Enbridge, they're stronger on the downstream side. So it really fits as far as integration. Our expectation is that the joint venture will be able to extract some more synergies and additional volumes as we go forward. I’ll probably leave it at that and not get into the multiple discussion.

I just wanted to make sure I understand what's driving the crude pipeline EBITDA this year. On Slide 17, you have a helpful bridge of the crude segment versus last quarter and kind of call out both increased volumes and then also MVC payments. I just want to - does that mean that people are effectively paying you MVCs on pipelines that don’t go to BMS Gulf Coast in the Permian but then you’re over your MVC level and getting spot rates on the pipelines that are going 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 placing with some incentive tariffs. We expect that to go away as this year first start to shift to their MVC levels, which we fully expect that to happen shortly. So I'd say that has been temporal as the spreads have been in, but as spreads widen, you would expect that to be different. So Cushing, that's not on MVC. There are some components that are in from a recontracting standpoint, we continue to add more on a term basis across both the Cushing's corridor as well as the corridor to Corpus. So there's plenty of demand for capacity to the coast at increasing levels.

Got it. That makes sense. And then I was just 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 discuss. I would suggest that hopefully in February, during our February call, we'll have a bit more information on that, and we'll share it at that time.

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

We're absolutely looking at how do you firm up additional volumes. I made a comment earlier about taking some of the volatility out and getting kind of fixed volumes. So we're working on that every single day. But I don't know if I get a specific question in areas there?

Yes. I think I was just asking kind of how are you looking at all kind of 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 got your question. Maybe if you take a look at Slide 9, if I understand your question, when we think about the higher prices, it definitely benefits us primarily in PLA, in frac spreads. And if you look at where we started the year at, we had a more modest expectations of crude oil environment, roughly $75. And for the year, we're probably going to average close to $95. So there's a piece of that is related to oil price. But we think as we go forward, we're going to be able to capture some of that and that's all been factored in as we think about our distribution coverage going forward.

Got it. And then my second question is in regards to Cactus I and II in your Corpus Christi exposure. We've had record exports out of the Gulf Coast for 2 quarters in a row, and Corpus Christi disproportionately benefited. So I was wondering how sustainable you think that growth is going to Corpus Christi in light of the exports. And then 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. In Corpus Christi, we have completed the expansion of the depth of the channels, which will benefit all of the docks. There is ample capacity for export. The pipelines are nearly full, but the rates for the additional capacity are increasing, which benefits pipeline and dock owners. There is significant potential for expansion. Currently, it has the best logistics and the highest prices, which is why exports from there are double that of any other port. While there are exports across the Gulf Coast, we expect Corpus Christi to continue receiving a substantial share. I believe that addresses your first question. The second question was regarding minimum volume commitments.

On Wink-to-Webster.

Oh, on Wink-to-Webster. The impact is consistent with what we said in February. They ramped in February of next year, and production growth this year has absorbed those MVCs from this year. And next year, we would expect the same thing. So growth is on pace with where we thought there might be some bumps due to the natural gas takeaway or others. But longer term, we fully expect that to take place. The larger impact from there is felt in Houston, as you have Wink-to-Webster shippers moving their lease book back to Midland. So it doesn’t necessarily import the barrels that are for export because that’s all priced into the forward differential and it will all be priced into our guidance. So we fully expect to be full to the coast on our pipelines next year. But for the margins to heal over time, you’ll need some of those MVCs to be absorbed by production growth.

Does that answer your question?

It did.

Fundamentally, our view is global demand is going to continue for crude oil. And if you think about the export and the sources that we think is coming from North America. So we think it's a pretty 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. Just first, can you elaborate if you were specifically talking about volumes or EBITDA or both?

I'm sorry. The numbers I was giving you were volumes from year-end to year-end, '22 to '23, of roughly 650,000 barrels a day. And just to make sure I communicate effectively, when we talked about checking 2023, the rig count, the horizontal rig count in the Permian, our assumption was roughly 350 to 360 rigs. We're running about 330 right now.

Okay. And I think you - I might have missed it, but maybe I thought you made a comment about growing the Crude segment in ‘23. And I was curious if that was explicitly about volumes or earnings.

No, I didn't provide any guidance on overall Crude volumes. Jeremy, do you have anything to add?

Yes. I think his comment in the script, I think it was from Al, actually, was that we would expect year-over-year growth. And so remember, our gathering system benefits from production growth in the field. So I think it was just a comment to say the same type of growth we saw this year, we would expect to see that on the gathering side with some incremental growth due to increased volumes and increased margins on the long-haul business as well as the step-up in MVCs on the Wink-to-Webster project. I think that was the comment.

Okay. And then I guess, do you think - as my follow-on, do you think that the growth that you would expect would outweigh any like conservatism on the price deck that you would assume from any pipeline loss allowance uplift or things like that?

Michael, this is Jeremy. We were just trying to get some directional indication of the impact of frac spreads since it's been so significant. The intent was not to provide guidance for next year. We'll update everybody on guidance for the Crude Oil, the NGL business in February.

The other piece that we wanted to give you heads up on is there's some planned outages that you probably wouldn't have insight into. So we wanted to give a heads up that there will be an impact on that as well. So on the NGL business.

Got it. And then on the NGL business, is the downtime related to the smaller expansion that you had mentioned last quarter? And if so, what’s the timing look like for when that is complete or resolved?

Yes. I'm not going to give you specifics on it only because it's a third-party supplier; it's a third-party straddle plant that impacts our Fort Sask business, so I'll hold off on that.

And it is independent of the project that you referenced.

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

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

All right. Then if I look at the metrics that you laid out on Slide 6 with regard to the 2022 guidance update. So it seems like the adjusted EBITDA is moving up by $75 million. However, the guide to DCF has gone flat versus your August guidance. So I was just curious what’s the difference that keeps the DCF flat.

Yes. This is Al. I'll take a shot at it. One, Canadian taxes; two, some of the timing around distributions and earnings on being different on unconsolidated entities as well as on our noncontrolling interest distributions to noncontrolling interest. And then the last one is just we probably should have rounded down. Last quarter, we've been trying to keep those numbers kind of round. So no one thing, a number of different things. Good question.

But your free cash flow is still going up, so you kind of recoup some of all these factors when you look at the free cash flow?

Correct.

And at this time, I'd like to turn it back over to the company for the closing remarks.

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

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