You are currently on hold for today's conference call at this time. We're assembling today's audience and plan to be underway shortly. If you would like to ask a question during today's presentation, please press star one on your telephone keypad. We appreciate your patience, and please remain on the line. Good day, and welcome to the Pembina Pipeline Corporation 2022 Q1 Results Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Mr. Cameron Goldade. Please go ahead, sir. Thank you, Anna. Good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the Q1 of 2022. On the call with me today are Scott Burrows, President and Chief Executive Officer, Jaret Sprott, Senior Vice President and Chief Operating Officer, Janet Loduca, Senior Vice President, External Affairs and Chief Legal and Sustainability Officer, Stu Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer, and Eva Bishop, Senior Vice President, Corporate Services. I'd like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina's current expectations, estimates, judgments, and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures. To learn more about these forward-looking statements and non-GAAP measures, please see the company's management's discussion and analysis dated May 5th, 2022, for the period ended March 31st, 2022, as well as the press release Pembina issued yesterday, which are available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Scott to make some opening remarks. Thanks, Cam. We announced yesterday with the release of our quarterly results. 2022 is off to an excellent start. A strong contribution from our marketing business, growing volumes on many key systems, and the benefit of new assets placed into service over the past year allowed us to deliver record quarterly Adjusted EBITDA of CAD 1 billion, which is a significant achievement for the company. Physical volumes on Pembina's conventional pipeline systems, which serve as a good proxy for Pembina's broader business, grew by nearly 5% in the Q1 of 2022 compared to the same period in 2021. That trend has continued into April, with physical volumes reaching an all-time monthly high. As Cam will detail in a moment with a strong Q1 and a positive outlook for the rest of the year, we have raised our 2022 Adjusted EBITDA guidance to CAD 3.45 billion-CAD 3.6 billion. In addition to a strong financial Q1, we were excited yesterday to announce two additional important developments. The first was a 20-year midstream services agreement for the transportation and fractionation of liquids from ConocoPhillips Canada's Montney development in Northeast BC. Under the arrangement, which was preceded by the previously announced exclusivity agreement and subject to certain exclusions, ConocoPhillips Canada has dedicated liquids production from the majority of its acreage within its liquids-rich Northeast BC region of the Montney resource play. ConocoPhillips Canada is a premier producer in the area and we are thrilled with this arrangement. The new agreement complements the previously announced agreement with a second Montney producer, which commits to Pembina volumes from a multi-phase development of the producer's Northeast BC Montney acreage on a take-or-pay basis upon the acreage being developed. Lastly, we have finalized commercial terms with a third leading Montney producer regarding significant long-term Northeast BC volume commitments and expect commercial agreements to be signed by mid-2022. Pembina sees the Northeast BC Montney as a strategically important area and a key driver of growth in the basin, and we are poised to benefit from new development. In an increasingly competitive environment, we continue to demonstrate the customer's value, the certainty and dependability of our infrastructure, our strong track record of safety and reliability, competitive fees, and integrated service offerings. As a result of these long-term commitments and the agreements that have been executed or are anticipated to be executed later this year, Pembina expects to have secured the transportation rights to a significant portion of forecasted future growth in the Northeast BC Montney, which collectively will support improved utilization of existing assets as well as capital-efficient expansion projects into the future. The second important announcement yesterday was to provide updates on our phased Peace Pipeline expansions. As a result of the Northeast BC commitments secured in ongoing conversations with other customers, Pembina is pleased to be reactivating the previously deferred phase VIII project, which will enable segregated pipeline service /for ethane plus and propane plus NGL mix from the central Montney area at Gordondale, Alberta into the Edmonton area for market delivery. Based on the significant long-term commitments from leading producers as I discussed, we have clear visibility to the demand for incremental capacity in this region, and as a result, we are confident in the decision to reactivate phase VIII at this time. We are also looking forward to the expected placement into service of the phase VII expansion on June first, ahead of schedule and approximately CAD 150 million under budget. As well, construction of phase IX expansion continues. We've updated the in-service date of that project to the Q4 of 2022. We also announced yesterday that Pembina will not proceed with the previously deferred expansion of the Prince Rupert Terminal at this time. Pembina's advantaged unit train capabilities, along with its current Prince Rupert Terminal, provide customers a diversified portfolio of markets. Given the outlook for strong domestic propane prices and new propane demand sources under development within the WCSB, Pembina believes it can provide customers with a high-value offering that meets their egress needs in the near to medium term. Pembina will continue to evaluate and enhance its portfolio of propane sales options and will consider future expansion opportunities as market conditions evolve. During the Q1, we also announced that Pembina and KKR will combine their respective Western Canadian natural gas processing assets into a single new joint venture entity, which we are currently calling NewCo. Pembina and KKR have been partners in various midstream for over four years. We work well together and share a mutual desire to invest capital and generate attractive returns. The formation of this new joint venture is a natural extension of our relationship, unlocks value for Pembina, and creates another growth platform. We are extremely pleased to be creating this exciting new company with KKR to drive real synergies and deliver a wider suite of commercial opportunities. We also were pleased to announce our intention to increase Pembina's common share dividend by three Q1s of a CAD 0.01 Per share per month, or 3.6% upon closing of this transaction. We continue to work through the regulatory approval process associated with this transaction, and we are now planning for the transaction to close in the Q3 of 2022. On the ESG front, Pembina is delighted to be partnering with TC Energy to jointly develop a world-scale carbon transportation and sequestration system known as the Alberta Carbon Grid. This project, over time, could grow to sequester up to 20 million tons of CO₂ per year and will allow Pembina to play a vital role in helping Alberta-based industries effectively manage emissions. During the Q1, we were pleased when the Government of Alberta announced the Alberta Carbon Grid has been successfully chosen to move to the next stage of the province carbon capture utilization storage process in the Industrial Heartland. This stage includes exploring how to safely develop carbon storage hubs north and northeast of Edmonton. We look forward to progressing this important project over the next few years. Finally, we continue to have success on Alliance Pipeline recontracting. Recent open seasons, including six open seasons offered to the market during the Q1 of 2022, have resulted in Alliance being contracted over 90% for the current gas year and 75% for the next gas year. Over the past year, Alliance has become a real good news story as the recontracting success highlights the value of Alliance's reliable and highly competitive access to Midwestern U.S. gas markets as a conduit to the Gulf Coast and its robust liquefied natural gas market. I will now pass the call over to Cam to discuss in more detail the financial highlights of the Q1. Thanks, Scott. As Scott noted, Pembina reported a record quarterly Adjusted EBITDA of CAD 1.006 billion, representing a 20% increase over the same period in the prior year. The Q1 was positively impacted by stronger marketing results due to higher margins on NGL and crude oil sales and lower realized losses on commodity-related derivatives, combined with higher contributions from Oxbow. Improvements in commodity market prices, including NGL, crude oil, and condensate, contributed to the significant increase in results for the marketing business. Contributions were made by NGL Marketing, where higher margins resulted when seasonal inventories built up during the Q2 and Q3 of 2021 were sold during the Q1 of 2022 in a higher price environment. In addition, crude oil marketing realized stronger blending margins due to rapidly rising crude oil price environment. Adjusted EBITDA also benefited from higher volumes in combination with higher tolls on the Peace Pipeline system, largely due to inflation. Higher recoverable costs on the Horizon Pipeline related to an extensive slope mitigation project. Contributions from the Prince Rupert Terminal coming into service in March 2021, and a higher contribution from Veresen Midstream, which was due to the Hythe development project entering service in March 2021, as well as higher volumes at the Dawson assets. These positive factors were partially offset by lower contracted volumes on the Nipisi and Mitsue pipeline systems due to the expiration of contracts, a lower contribution from Ruby Pipeline, and higher general and administrative costs due to the higher long-term incentives driven by a larger increase in Pembina's share price compared to the prior period and Pembina's performance relative to peers. Pembina recorded earnings in the Q1 of CAD 481 million, representing a 50% increase relative to the same period in the prior year. In addition to the factors impacting Adjusted EBITDA, earnings was positively impacted by lower impairments and a higher unrealized gain on commodity-related derivatives for certain gas processing fees tied to AECO prices. Q1 earnings were negatively impacted by higher income tax expense and a lower share of profit from Ruby Pipeline. Total revenue volumes of 3.4 million BOE per day in the Q1 were down approximately 3% compared to the same period last year. Decrease was the result of lower volumes in both the pipelines and facilities divisions due to contract expirations and third-party outages, offset by higher volumes on certain systems and new assets placed into service. With our release yesterday, Pembina raised its 2022 Adjusted EBITDA guidance range to CAD 3.45 billion-CAD 3.6 billion from the previous range of CAD 3.35 billion-CAD 3.55 billion. Relative to Pembina's initial guidance, the revised outlook for 2022 primarily reflects stronger marketing results as a result of higher expected NGL and crude oil prices, partially offset by higher realized hedging losses. In addition, the revised outlook excludes Adjusted EBITDA from Ruby Pipeline from April 1st through the remainder of 2022, pending resolution of the Chapter 11 process. Current guidance does not include the impact of the Newco transaction. Cash flow from operating activities is expected to exceed dividends and the capital investment program in 2022. As previously disclosed, Pembina expects to allocate a portion of the excess towards common share repurchases with the balance available for incremental capital investment, debt repayment, or additional distribution to shareholders. Including the shares repurchased in December of 2021, Pembina has now completed CAD 58 million towards its 2022 target. Based on strong financial results in 2021 and the outlook for 2022, Pembina is strengthening its financial profile by paying down debt. Forecasted debt levels by the end of 2022 are expected to position the company favorably relative to its stated leverage targets necessary to preserve its strong BBB credit rating. I'll now turn things back over to Scott for closing remarks. Thanks, Cam. Overall, our message to you today is that we are very pleased with the start to the year and the potential it has created to deliver strong results in 2022. We remain very confident about the prospects for the business and the optimism we have conveyed over the past few Q1s regarding the future of the Western Canadian Sedimentary Basin remains intact and growing. The positive discussions we've been having with customers over the past year are now translating into contracting success and long-term commitments for future volumes. This will support higher utilization of Pembina's existing asset base, as well as the creative and capital-efficient new growth projects with significant benefits expected for Pembina and our stakeholders. Before we wrap things up, I want to remind you that Pembina will be holding its annual general meeting of common shareholders today at 2:00 P.M. Mountain Time, 4:00 P.M. Eastern Time. Once again, this year, it will be a virtual-only meeting conducted via live audio webcast. Participants are recommended to register for the virtual webcast at least 10 minutes before the presentation start time. For further information on Pembina's virtual AGM, please visit the shareholder information page under the Investor Center tab at www.pembina.com. In closing, we would like to once again thank all of our stakeholders for their support. Operator, please open up the line for questions. Yes, sir. Thank you. If you would like to ask a question, please signal by pressing star one on your telephone keypad. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Once again, that is star one if you would like to ask a question, and we'll pause for just a moment to allow everyone an opportunity to signal. We'll take our first question from Jeremy Tonet with JP Morgan. Hi, good morning. Morning, Jeremy. Just wanted to start off on the guidance increase here, and I'll refrain from asking annualizing the Q1 versus the whole year guide. Really just wanted to see the raise that was baked in here. Is this just outperformance in 1Q marketing, or do you see kind of improvement for the base business too? If you were to factor in the uplift from Newco JV, is there any way to kind of give us some color what type of uplift that would be? What would be the first-year uplift from Newco JV? Sure. Jeremy, it's a combination of both. You know, as you recall, marketing tends to have its biggest Q1s in Q1 and Q4. So, by getting through Q1, you know, we have a good sense of where our typical best Q1 for marketing is. That's really what's driving the increase on the lower end of the guidance range. Then on the higher end, it's both a combination of increased marketing outlook as well as growing volumes throughout the system. As it relates to NewCo, it's always difficult to forecast 'cause it depends on when that closing date is. You know, if we close some time in Q3, it's probably something in the neighborhood of CAD 15 million-CAD 20 million. 15-20 would be the uplift for the balance of the year or kind of an annualized uplift? Just to clarify. No, for the balance of the year. Got it. Thank you. Kind of, you know, shifting gears a bit towards capital allocation strategy. You touched on a bit in the remarks there. Just wondering, you know, we've had factors change since the last time, last call, and you've talked about it. EBITDA is much higher than expected. There's some more growth CapEx, new projects coming back, and also a higher share price. Just wondering how these factors come together in your mind with regards to the cadence or outlook for buybacks and how you think about that at this juncture. Yeah. If you think about the midpoint of the new guidance range versus the midpoint of the old guidance range, you know, that's CAD 75 million. That's roughly the increase in capital we expect to see in 2022 for the re-sanctioning of phase VIII. You can think about the increase in guidance really going towards funding phase VIII. As it relates to your question around capital allocation, you know, as you saw in our notes yesterday, we continue to buy back shares. I would say that, you know, over the next Q1, we are gonna spend some time looking at, you know, what the plan would be for Q4 and the remainder of the year. As you rightly point out, our share price has gone from CAD 40-CAD 50. Our 10-year yields have gone from 3% to, you know, 4.5%. You know, paying down debt, both to position ourselves for growth, but also from an economic perspective, has become more attractive. You know, no change to the guidance right now, but it is something we're spending a lot of time thinking about. Got it. Just a quick last one, if I could. Any thoughts you have on resolution to the Blueberry River First Nations situation and/or thoughts on that in general and how that impacts your guidance and outlook? Sure. I'm gonna turn it over to my colleague, Janet, to talk about, you know, our perspective on the situation. Yeah, good morning, Jeremy. It's Janet. You know, we've been hearing very positive outcomes coming from the discussions between the government of BC and various indigenous communities, including the Blueberry River First Nations. We do expect to have that resolved. It's difficult to anticipate the timing, but we're certainly watching it closely and we'll be looking forward to some resolution, I would say, you know, in the coming months. Jeremy, I would just add, given the discussions we're having with producers, the arrangements we've entered into, you know, that all gave us confidence to sanction phase VIII. Got it. That's very helpful. I'll leave it there. Thanks. Thanks, Jeremy. We'll now take our next question from Matt Taylor with Tudor, Pickering, Holt & Co. Yeah, thanks, guys, for taking my questions here. I wanted to go to Cedar LNG. Looks like you're making good progress there. Can you just give us an update on the commercial discussions, both in terms of new customers given what's going on with global pricing and then obviously existing relationships, and then just giving us the guideposts for financing plans and when you plan to reach FID? Yeah, I'll jump in and start. It's Stu. I'll talk about our commercial conversations. The project itself, we're very busy on the engineering side and on the regulatory consultation side and filing of applications. With respect to commercial, we've been out talking to a number of potential customers, offtakers regarding the Cedar LNG project. The response has been very positive. We're making good progress. The fact that Cedar LNG has a lot of very favorable characteristics from a cost perspective, from an ESG perspective, from an Indigenous community perspective, it's very attractive to the offtake market. You know, with the pricing that's there today, we've had very positive conversations. We're working very hard to progress from these conversations to term sheets, and that'll be, you know, what's gonna take place for the remainder of this year. With financing, I'll turn it over to Cam. Yeah. On the finance side, I mean, I think obviously that's a big piece of it. You know, it's an active work stream. We're looking at a lot of different options there. Obviously, you know, we're working with our partners at Haisla to find the most accretive solution. I think, you know, ultimately for Pembina, it's quite a manageable bite size. When you consider the scale of it, you know, the 50% ownership to Pembina and the timetable for the spend, which is, you know, really over a four-year timetable. For Pembina, quite bite-size, and we're working very closely with Haisla to help them with their financing situation. You know, more to come on that obviously over the next few months here as we get closer to a potential FID. Definitely seeing some positive signals so far. Yeah, thanks for that. FID sometime next year, is that what you're still targeting? Yeah. We're shooting for sometime following Q1. Awesome. Great. Thanks for that. Then part of your sensitivities that you previously disclosed was CAD 39 million impact for every move, every CAD 0.50 Move in AECO pricing. I guess I'm just wondering if this was factored into your updated guidance, and then if you could just sort of run through some commentary on the puts and takes of the higher AECO pricing, although it might be a bit of a negative on the marketing side, but what you're seeing in other parts of your business that may offset. Yeah, Jeremy, I'll take that. I mean, or sorry, Matt. You know, definitely, you're correct in terms of the high AECO price is putting pressure on the back half of the year frac spread. That being said, we are 50% hedged. You know, on the way up, when propane prices are rising, we always caution people to not get too far ahead of themselves 'cause we are 50% hedged on the NGL side. You know, likewise, on the input cost, we're 50% hedged on the AECO side. So to the extent AECO's been running, we are 50% hedged. We did factor that into our updated guidance range. You know, it has risen since that time, but we're still very comfortable with that range. On the flip side, you know, it's got the indirect benefit of obviously our producer community is making a significant amount of money, and rapidly paying down debt, you know, and hopefully returning more to the drill bit here to come. On a direct basis, we've seen the AECO to Chicago basis widen pretty significantly. We're benefiting both from strong interest in Alliance, as well as upside at Aux Sable with some contracts and other things that are tied to that differential. Lots of puts and takes across the board, but it all gives us our comfort in terms of our guidance range. Yeah, thanks for that, Scott. Then one more, if I may, just to finish this off. Can you just give us some more color on why you canceled the LPG expansion? Because from the seats that we're in, global pricing seems elevated. You've got Alberta with the discount moving back, say, historically wide compared to U.S. benchmarks. Is this more of a decision related to scope, and infrastructure required, or can you give us an update on your strategy going forward and how you're thinking about propane? Yeah. I'm gonna turn that over to Jaret, but maybe before I do, I'll just clarify that it wasn't canceled. We just continued to defer that project and assess, you know, longer term the need for it. I think there's a difference between continual deferral and cancellation. Jaret, do you wanna take that one? Good morning, Matt. Yeah. Like, as Cam said in the opening remarks there, we obviously have unit train capabilities, and we can deliver our propane across North America and domestically to many different destinations, providing our customers and ourselves a wide range of diversification. At this time, you know, looking at the very strong domestic pricing here in Canada and the United States, you know, we feel that, you know, the roughly 19,000-20,000 barrels of export capacity that we have in our portfolio is sufficient. Just moving forward with providing our customers the best options domestically and with that slice of pie going internationally, that's our best outcome here for the short term. Like Scott said, it's not, you know, binned, and it's not canceled. It's just, you know, we're just gonna continue to evaluate. If market conditions change drastically, you know, we potentially could re-sanction. Anything to add, Stu, from the marketing side? No, I think you've covered it very well, Jaret. You know, we continuously evaluate all the markets that are available to us. We're very, as Jaret said, we're happy with the mix of markets that we have in the portfolio today. We believe the North American markets will remain quite strong. Our unit train capability, as described, allows us to access those markets very well. We think, as we sit here today and look at things that we're comfortable with the markets we can access and believe it to be the right choice at this time. As stated, if that changes in the future, we will move and make the change to look at more international markets as they come available. Great. Thanks for taking my questions here, guys. Have a great weekend. Thanks, Matt. We'll take our next question from Linda Ezergailis with TD Securities. Thank you. Just expanding on markets. What are your latest thoughts on doing more with the molecule, moving down the value chain, potentially getting involved in, petrochemical type investments, including, PDH? Is that off the table based on your comments, or can you just provide us with an update on how you're thinking about that? Linda, it's Stu again. Yeah, I mean, we continue to look. Obviously, the market is evolving. You know, the IPL project of PDH will be coming into service. You know, we've always liked that project. As we sit here today, we look at what markets are available to us, moving down, you know, a number of value chains. Pembina plays A large role in feedstock provider. We're working with, you know, potential petrochemical projects that are in the press and being described. We think we have a major role to play in providing and continuing to provide feedstock on a go-forward basis. We look at what opportunities to you know, to move further along as you describe that. None of those are completely, you know, off the table for us, and we're trying to evaluate where Pembina best plays. Again, we think we've, you know, we're historically been a great feedstock provider, and we'll continue to do so, and we'll look to evaluate, do we step further along, as those markets progress. We like the pet chem space. We like being the provider of feedstock, and we'll look at what opportunities present themselves on a go-forward basis in the future. Thank you. Maybe just another question around all the conversations you're having, given your incumbency in the region. Your discussions with producers, are you seeing acreage commitments becoming the standard? What are the other attributes of your commercial agreements that you're negotiating? How are they shifting, if at all? Are producers still preferring a full pass? Are you looking to ensure that any sort of inflationary cost pressures are passed through to customers? Are they resisting that? Any color you can provide on those discussions would be helpful. Jaret, would you like to take that one? Yeah. Thanks, Scott. Good morning, Linda. There was a lot there, so I'll try to break it down into the area of dedications, the ones that we have been talking about most recently, they're very similar. They do come with take-or-pay, you know, once the customers start engaging and calling on services through the value chain. You know, a little bit differently, some of our customers choose to build their own gas field-based gas processing and some leave that up to us, like the area of dedications with Veresen Midstream and CRP or also our Duvernay dedication with Chevron and KUFPEC. In the ConocoPhillips scenario, they've chosen to utilize Pembina's value chain through transportation, fractionation and marketing, and obviously the terminaling and rail. You know, as we continue to grow, it allows us to diversify our contractual arrangements to meet our customers' needs. I think inflation, that's always been a part of, you know, our contracts with our customers and our agreements with our customers. Those typically are in our agreements, and I think that answers your question. Yes. Thank you. I'll jump back in the queue. Thanks, Linda. We'll now take our next question from Rob Hope with Scotiabank. Morning, everyone. A follow-up question. You continue to, you know, secure additional volumes from Northeast BC and I guess Northwest Alberta, you know, and looking to draw them into the Fort Saskatchewan Edmonton region. How are you thinking about your frac capacity and when you could need some additional assets in that region? And then I guess as a follow-up, does this kind of also imply that, you know, your prior strategy potentially doing some field frac could be pushed off further just given, you know, it looks like you continue to wanna move volumes down to the Fort? Yeah. Rob, I'll take that. Jaret, please jump in if you wanna have additional comments. In general, our fractionation facility is getting pretty tight. You know, as we look forward to the future, we're backfilling contracts. You know, we have kicked off engineering on RFS IV. We've talked about that in the past, and that continues to be an option and something that we continue to assess. It's probably a little too early to talk about timing on that, but we are working on it in the background given the tightness that we see in the frac. In terms of greenfield fracs, you know, I think our preference is still to be centrally located in Redwater, just with the scale we have there, with the land, with the unit train capability, with our ability to make low methanol propane as well as, you know, additional sources like the IPL PDH coming online. We still think it's the ideal spot to put it. Jaret, anything you wanna add to that? Yeah. Well said, Scott. Further to that, you know, the storage, the field fracs that we had looked at, you know, we just couldn't extensively find adequate underground salt cavern storage. Obviously, it would all have to be above ground, so increasing your cost structure. You know, I think we've pretty much eliminated the opportunity of field frac due to manifest rail and lack of storage. It just provides for an inefficient operation. Continuing to look, although intuitively, you know, you're sending your product a long way into the Edmonton, into the Fort area, it does make sense due to our vast feed cavern storage, our spec cavern storage, our rail infrastructure, you know, access to numerous markets out of the Fort Saskatchewan area. We'll continue to focus, going into the Fort due to economies of scale, which will increase the netback for our customers. All right. Thanks for that. One more, if I may. You know, we are seeing kind of increased competition for moving liquids out of Northeast BC and Northwest Alberta, but you continue to, you know, do very, very well on the contracting side. Can you just maybe comment on kind of what key benefits customers are saying regarding your offerings versus the competition? Yeah. Number one, obviously, we're in service, you know, our pipeline, our organization has been around for 68 years in and about the communities in Western Canada. We're well-known to the communities and we have assets that are in service. Obviously, assets that are in service can be expanded fairly quickly through pump stations and/or laterals and/or some, you know, like our phase VIII now will have segregated product flow all the way from Gordondale into Edmonton. That really optimizes your system. It takes batching, you know, those types of things out of the system, which ultimately lowers your cost structure. You know, not only do our customers look at our capital fee, but they also look at our operating fee. When you have a very large volume base over the asset, we can, you know, we work very hard every day to drive down the operating costs for our customers. I think that is part of it. Obviously, our connection into our pipeline system has a connection into all of the fracs in and around the Fort Saskatchewan area, not only ours, but also our competitors. Our customers like that optionality. We do win a lot of the volumes into the Redwater facility, but we do provide that optionality for our customers to go to other places. On the condensate side, we have multiple connections into condensate delivery points. I think it's the whole package that the customers really like. All right. Thank you. Appreciate the color. We'll now take our next question from Robert Catellier with CIBC Capital Markets. Good morning, everyone. I just had a couple of questions left on the ConocoPhillips agreement. It sounds like there's enough infrastructure there with phases VII to IX so that there's not a lot of capital requirements in the near term, and there could be some operating leverage. As they call on additional capital, it sounds like that's gonna be supported by take-or-pay. Will Pembina bear the CapEx risk? Is that the way to look at it? Good morning. Think of it as I wouldn't think of it as one sole customer that would require Pembina to deploy capital. I think the success that I just, you know, we just previously talked about in the previous question, we will one day, in the event that all of our customers that have agreements with us continue to grow as per their publicly disclosed plans, we will have to deploy more capital to continue to capture those volumes and increase the utilization, you know, let's call it from the Alberta side of our system. You know, we will be working very closely with our customers, looking at their development plans to make sure we can accommodate that growth profile. It's really exciting. You know, obviously, I think there's a couple of questions ago. We do have to continue to evaluate the frac capacity as well because this isn't only NGL focused. This is, pardon me, condensate focused. There's gonna be significant NGLs coming here. With the, you know, there will be incremental gas from LNG Canada owners. That asset will be coming into service, let's call it a few Q1s after our phase VIII capital deployment in the first half of 2024, and that will drive more NGLs to come. It will be dynamic and fluid, but we think we're well-positioned to deploy that capital and meet the customer's demands. Okay, fair enough on the aggregating supply from multiple customers to drive the infrastructure. I just wanna make sure that, given the inflationary environment we're in, there's some protection to Pembina if, you know, the infrastructure is gonna require three or four years down the road that you haven't locked yourself into a rate that doesn't protect you from inflation. Rob Great question. Our tolls have- Go ahead. I was gonna say our tolls typically have CPI inflators in them. To the extent that there is some capital cost creep, we should be able to recover that in our tolls. Okay. That's what I thought. Thank you. Then next question here, I just want to confirm something I think I heard in a response earlier. There is in fact an opportunity to market the liquids associated with the ConocoPhillips Canada agreement? Sorry, can you repeat the question? Yeah. I just wanted to confirm that you do have an opportunity to market the liquids associated with the Conoco agreement. That's correct. Last one from me. You've made some progress in the last couple of Q1s here with Alliance Pipeline. You've given us pretty good visibility for the next couple of years, but I'm wondering if you can provide some color beyond 2023 in terms of how much you need might be contracted to the extent that that's not immediately commercially sensitive for you. We have an open season ongoing that actually closes today, Rob, for longer term. You know, maybe next Q1 we'll be in a position to update that, but we're in a bit of a commercially sensitive time period right now. I'd prefer to not answer that question right now, other than to say the demand for that pipeline is robust. Okay. Thanks, everyone. We'll take our next question from Ben Pham with BMO. Hi. Thanks, Maria. I wanna go back to Prince Rupert. As you've reevaluated the netbacks and shipping costs have gone up, and you, as you speak with your customers on this, what is your expectation in terms of where the propane netbacks are? Like, what's the most attractive? Is it the PDH side of things, producers are more gonna swap for part of the propane that's perhaps driving some of this decision on Prince Rupert? Ben, it's Stu. I mean, we're looking at all of our markets. Right now, the PDH facility is coming into service, that's not up and running as of yet. We've really enjoyed shipping and our capability to get product out into the Sarnia market this past winter. We've had great success there. We've seen rising prices in some of our U.S. deliveries as well. You know, that's been a market. The Sarnia market, in particular, you know, it's been a historic good market for us over the long term. We see that continuing. We've seen rises in the FEI pricing. We like where we're sitting today, and we like the balance that we have. You know, we look at all of our markets and the netbacks do move. You've hinted or stated a couple things, you know, rising shipping costs and, you know, where we're at. You know, we evaluate the markets, we look at the cost to our facilities and accessing those markets. At this point in time, believe we're best served to continue to ship as we are capable of today and look to feed the markets that are available to us in North America, including opening up markets such as that PDH. We look at it on a go-forward basis, but it is dynamic as the pricing does change. If you aren't planning to expand, I mean, you are not planning to expand with Prince Rupert in the near term. Is that facility like how important is it to the Pembina story? I mean, do you need it? Well, I mean, it's currently, you know, we're shipping almost 20,000 barrels a day. We're accessing international markets. We believe it provides diversification and value to our customers and to ourselves. When you say as far as need, we can move those barrels. Those barrels are loaded into rail cars, shipped to the coast. We have the opportunity to move those barrels around North America as we see fit. You know, we still really like the Prince Rupert Terminal. We like it at the size it is today, given the market dynamics that we see in front of us right now. You know, it's something that I think our producers and over the long haul will be a valuable asset to the Pembina story. You know, we continue to look at how we can access markets on a go-forward basis. We don't wanna overcapitalize. We wanna make sure that we're expanding at the right times such that we ensure that our customers receive the best netback that they can get. Okay, great. My last one is: Any update in terms of timing on the CFO side of things? I'll take that one. No immediate timing. I mean, we're actively in the process and would hope to conclude that in Q3, Q4 this year. Okay, that's great. Thanks, everybody. We'll take our next question from Robert Kwan with RBC Capital Markets. Great. Good morning. If I can come back to the Conoco agreement, I know there's been a lot of questions. I wanna make sure I'm capturing it. Specifically, are there any take-or-pay components on the base volumes coming out of the area dedication? Good morning, Robert. Jaret, are you? Oh, yep. Sorry, the question was, I'm just having a hard time hearing right now. Bad connection. Yeah. Are Go ahead. Jaret, it was described. You described it as an area dedication, so I'm just wondering, are there any take-or-pay components, whether on an annual basis or over a multi-year basis as part of the base volumes that would come out under the deal? Yes, there would be, Robert. Would they roughly approximate your, quote-unquote, typical kind of take-or-pay structure of roughly 75%, or would it be something less? No, they would be in line with our typical contracting strategy. Okay, that's great. If I can just ask something a little more philosophical then. You have a number of joint ventures, although a bunch of them were inherited, but you are entering into a new one, and most of these you are the operator. Just as you grow, you know, wanna grow and diversify your business, while being mindful of the share count, do you see additional joint ventures as something being attractive to the company? I think so, Robert, especially as we move into new energies and energy transition and a lot of the stuff Stu and his team are working on. You know, there are certain areas where we bring a lot to the table, but we don't necessarily have the same experience as some of our, you know, potential partners, as it relates to that area. Specifically in the new ventures area, I would say that would be the area where joint ventures are intriguing to us. Do you feel just philosophically, you get to a point where there are too many joint ventures or you comfortable, especially just if the vast majority of them are non-operated, and just the way you report proportionate type numbers, if that mitigates a lot of that? Well, philosophically, from my perspective, you know, I think that they're a great way to leverage different skill sets and move forward. In terms of number of joint ventures, I don't know if we've sat down and said there's a hard and fast number of joint ventures. I mean, I think from our perspective, what we've tried to do and always do is give investors clarity into what it looks like on a proportionally consolidated basis, both from an EBITDA but as well as a leverage perspective to try to demystify it, for our investors. I think as long as our investor relations disclosure gets investors what they need, then I'm not too worried about the number of joint ventures we have. Got it. If I can just finish on Nipisi and Mitsue, just with the runoff, are there any kind of opportunities do you see to, for additional contracts repurposed, extend into some other plays? Maybe just taking a step back too, are there any takeaways, just as you think how these projects played out? There was a lot of fanfare when they were built, whether that just relates to seeking longer term contracts for as you go forward with other projects or higher cash on cash returns during the contracted period. I would say that in that particular area, given the growth we're seeing in the Clearwater and the surrounding plays, we think there is opportunities for those pipelines, and we're in some active discussions, but that's about all I can say on that right now. Okay. Just the greater question of how you think about contracting other projects as you go forward, just given how this played out. Well, I mean, if you recall on that was a 10-year contract. Of course, we'd always like longer, but it's a constant negotiation with our customers. You know, to the extent we were able to get longer contracts, I think that's something we would have pursued. You know, I think from the perspective of that pipeline, you know, there's gonna be more to say on that in the coming months here. Okay. That's great. Thank you very much. We'll take our next question from Andrew Kuske with Credit Suisse. Thanks. Good morning. Maybe a big picture question that covers a bunch of different things. How do you think about just the outlook for egress and really across a gamut of stuff? Crude liquids in the basin, natural gas, NGLs, and then really in your own system, you know, do you have points of congestion in certain pockets? There's other areas where you may be facing competition, and then where do you have excess capacity? I'll try to answer that. I mean, if I back up a step and think macroly, you know, obviously Line 3 expansion coming on was very helpful for the basin, but it sounds like that's, you know, filling up, if not full already. I think we're all waiting patiently for TMX to come into service to really unlock and add that incremental egress out of the basin and not just solely rely on rail as a swing factor as it relates to crude egress. TMX is obviously a pretty important asset for the future of the basin. From a gas perspective, you know, there's still multiple areas that have capacity. As it relates specifically to Pembina, you know, as we've been trying to highlight here, Alliance is very full and we expect to be, you know, full for a period of time, to the point where we're starting to think about what an expansion on that pipeline might look like, as well. As it relates to NGLs, you know, most of that moves out on unit trains, as you're well aware. We also have a new source coming online with IPL's PDH. As I talked about earlier in our conference call, we are seeing some tightness in our frac capacity in the Fort. As it relates to the conventional pipeline system, there's tightness today. Obviously phase VII comes on in a month here. Phase IX comes on at the end of this year, and then phase VIII we just re-sanctioned. We're de-bottlenecking the parts of the system that are currently or are forecasted to be constrained. Once those expansions come on, we will have some capacity, and after that, some low-cost pump station capacity to continue to grow with our customers. That's very helpful. I guess as you start to think about, you know, developing producer intentions to increase activity, that plays into your footprint really from the existing expansions that you've outlined and then just some of the low cost stuff coming down the pipeline. I guess maybe the most expensive thing that you would do and maybe biggest benefit would be on the frac side. Is that sort of a fair characterization? It is fair. You know, with our existing footprint and the amount historically we've been able to invest in caverns and rail, you know, the investment really is on the facility itself with a lot of the ancillary business already in place. You know, from our perspective, it's a very attractive expansion opportunity. Let's just assume the frac goes ahead. You would expect the same multiplier effect across the franchise or maybe even a better multiplier effect across the franchise given your positioning? Correct. Okay. That's great. Thank you. Take our next question from Matthew Weekes with iA Capital Markets. Good morning. Thank you for taking my question. Just looking at the rising rate environment we're in, I was wondering if you could just comment on the debt and sensitivity to interest rates in terms of maybe how much of the debt's fixed, what the maturity profile is like or maybe interest rate swaps that you have on that that protect you against rising interest rates. Hey, Matthew, it's Cam. Yeah. We've done a really programmatic approach, you know, clearly for some time to maintain a very high proportion of fixed rate debt. As we stand today, if you look at sort of the Pembina corporate debt profile, which is about CAD 10.5 billion, 95% of that is fixed rate today, and the average tenor of that is in excess of 10 years. You know, it's sort of closer to almost 15, actually. When you look at the debt that we roll up with the JVs, you know, there's a little bit more floating rate debt there. We have managed to introduce some hedges into that portfolio. Rolling that up in totality of, you know, our total proportionate debt, you know, we're to the tune of just under 90% fixed rate debt. We've really got a lot of interest rate protection. When we look at, you know, sort of the refinancing risk, again, we've really tried to maintain a really stable ladder to our debt portfolio. You know, this year we've got one term loan, a bilateral term loan, which comes due, and we've got, you know, just around about CAD 500 million or so of bonds that come due in the second half of the year. You know, we'll be looking at that. Obviously, as Scott mentioned, in his capital allocation comments, I mean, we're obviously generating considerable free cash flow right now. That always remains an option and looking at that. Really, you know, the upcoming maturities are very manageable and in terms of refinancing. The last piece I'd comment is obviously, you know, we've got a considerable portion of hybrid capital in our structure, you know, between the prefs and the hybrids, and we've got a couple of resets coming towards the tail end of this year. Again, we'll be looking at the various alternatives to handle those. You know, they obviously reset. They can be redeemed, and so we'll be looking at the optimal approach there as we get a bit closer to the timeline for that. Okay, thank you. Just a follow-up question on the debt and thinking about energy transition opportunities going forward and how projects like this could take up sort of a greater amount of spending going forward. Do you see any opportunities for any sort of green financing access? It's definitely something we're spending some time on. You know, obviously there's a number of products, you know, in the market, you know, to the tune of sustainability-linked loans, sustainability-linked bonds. You know, the loan piece is probably something that is the first step for us, something we're spending some time on. Once we've got that tacked down, you know, I think we'll start looking at some of those other alternatives, on the SLB framework or, you know, potentially even a green bond related to a specific project. So certainly something we're looking at. As these opportunities at scale continue to mature, it's something we'll definitely look to take advantage of. Okay. Thank you. I appreciate the answer on that. I'll turn it back. Have a great weekend. We'll now take another question from Patrick Kenny with National Bank Financial. Hey, good morning, everybody. Just on the Alberta Carbon Grid, as you move through the design stage of the project, any update on the need to bring in other partners to help firm up your supply sources? Just thinking namely from the oil sands. Perhaps you can clarify if there's any potential to work alongside the Pathways Alliance, you know, to link ACG into the Cold Lake region. Just thinking, given the 37.5% ITC, not sure if that gives you a little bit more financial flexibility to perhaps overbuild the scope of the project or maybe even participate in some of the capture investment opportunities with your customers. Pat, it's Stu. I'll capture some of that or try to. You know, we're in the process as we speak with the government. You know, the first part of the carbon sequestration process was the Industrial Heartland. We were one of the parties selected to come forward with sequestration opportunities for emissions from the Industrial Heartland. We're working hard with our partner, TC Energy, building out the scope of what that project will entail. You know, we're looking at the emitters within the Industrial Heartland who will ultimately become our partners, our customers, sorry. And we're working on our scope, working on the customer outreach and communications. We continue to work with the Government of Alberta and are awaiting some more clarity on their process as we go forward. As described, they'll come out with evaluation agreements, which you will negotiate, evaluate your proposed acreage for sequestration capability, and then ultimately move to a sequestration permit as you prove up the sites. The government just recently closed a second process. People did submit a submission for outside of the Industrial Heartland emissions, outside of the Industrial Heartland, what other areas? You know, we participated in that as well. We continue to look and look at partners and customers and believe there is room for working together as an industry and with other players in this space. We have had conversations with the other players and announced projects such as Pathways. You know, those are ongoing. People are progressing their own project at this point in time, but I do believe that there is opportunity to partner in the future with others, a variety of others, existing producers, emitters, indigenous communities and, you know, new technologies that could be used in this space. The government tax credit that's been announced does give a bit more freedom. We've not, at this point, looked at the capture side of the equation. We've stuck to the sequestration as far as our scope. We've got a lot to do looking at, you know, the transmission and sequestration side. We haven't progressed too far into that capture side. I think if that answers everything else, Pat. It does. Yeah, that's great color. Thank you. Maybe switching over to Alliance, and given the heightened demand here for securing egress into the Midwest, as you mentioned, as a conduit into the Gulf, perhaps you could just help us frame, you know, the end game for Alliance, as a meaningful connection to LNG offtake longer term. You know, what needs to come together here, I guess, from a BD or perhaps an M&A perspective downstream of Chicago to, again, bring that longer term vision towards reality? Yeah. I'll take the M&A part, Pat. I think, you know, from our perspective, producers are able to do that contractually right now and are doing it. You know, I don't think we need to see any sort of acquisition to link those two things together. You know, we're seeing it today happen, and we think it's gonna continue to happen, especially as people are securing incremental LNG capacity out of the Gulf Coast and the long-term outlook for LNG. I think we're able to provide that conduit into the Midwest and ultimately Gulf Coast LNG without having to own incremental assets. Okay. That's helpful. Just a last cleanup question here. Not sure if you can comment or quantify what the offsetting impact of removing the EBITDA contributions from Ruby had on your revised EBITDA guidance range for the year. Yeah, Pat, we're not gonna. There were so many gives and takes as it went into it. We're not gonna get into specifics. No, fair enough. I'll leave it there. Thanks, guys. Thanks, Pat. It appears there are no further telephone questions. I'd like to turn the conference back over to Mr. Burrows for any additional or closing remarks. Well, thanks everybody. We appreciate you dialing in and listening to our story. We're really pleased with our results and hope to see you virtually at our AGM this afternoon. If not, have a great weekend. Once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.