Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q2 2023 Results Conference Call. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star 0 for the operator. This call is being recorded on Friday, August 4, 2023. I would now like to turn the conference over to Cameron Goldade. Please go ahead. Thank you, Jenny. Good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the second quarter of 2023. On the call today, we also have Scott Burrows, President and Chief Executive Officer, along with members of Pembina's senior officer team, including Jaret Sprott, Janet Loduca, Stu Taylor, and Chris Scheerman. I would 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 MD&A, dated August 3rd, 2023, for the period ended June 30th, 2023, 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. For the second quarter, Pembina reported earnings of CAD 363 million and Adjusted EBITDA of CAD 823 million. While we face challenges in tandem with the broader industry, Pembina's business remains strong. Quarterly results reflect Pembina's resilience. In the second quarter, we continued to observe growth in volumes and higher tolls on certain systems and a solid contribution from our crude oil marketing business. These positive factors were offset, most notably, by the impact of the wildfires in Alberta and British Columbia on Pembina's and its customers' operations, the impact of third-party outages, and reduced operating pressure on the Northern Pipeline System until mid-May. Second quarter results also reflect the typical seasonality in Pembina's NGL marketing business and lower NGL prices. We're hopeful that the worst of the wildfire season is behind us. We are extremely grateful for all of our employees, contractors, and customers in the affected areas were kept safe. Further, we did not have to incur any material fire-related damage to our assets. I would again like to thank our staff and emergency response teams, customers and industry partners, as well as all emergency personnel for their diligent responses to the wildfires. Notwithstanding the short-term impacts of the wildfires and the Northern Pipeline System outage on Pembina and the broader industry, the outlook for the Western Canadian Sedimentary Basin remains promising. Pembina's operations have returned to normal. Through the first month of the third quarter, volumes have been strong, reflecting levels from earlier in the year prior to the Northern Pipeline System outage and the wildfires. We expect continued volume growth throughout the second half of 2023, including in the conventional pipeline business, where full-year volumes are expected to be 4% higher than the prior year. Volume growth is expected to continue through the rest of the decade based on certain industry-wide developments, including, most notably, additional egress through various West Coast LNG projects and the Trans Mountain pipeline expansion, production growth in the Montney/Duvernay and Clearwater, and the expansion of Alberta's petrochemical industry. In our existing asset base, integrated value chain, contractual agreements, and deep customer relationships, we are poised to capture new volumes and benefit from increasing asset utilization and growth projects. On the project front, we are progressing our Phase VIII Peace Pipeline expansion and our RFS IV expansion at the Redwater Complex. The Phase VIII project continues to trend on time and under budget, furthering Pembina's track record of strong project execution. In addition to Phase VIII and Redwater four, Pembina is actively progressing over $300 million of smaller projects, including over $200 million in other pipeline projects. These include the reactivation of the Nipisi pipeline, which is expected in the third quarter of 2023, and a Northeast BC infrastructure expansion. The Northeast BC expansion includes terminal upgrades, additional storage, and new midpoint pump station. These are expected to be completed in the second half of 2024 and will support approximately 40,000 barrels per day of incremental capacity on the Northeast BC pipeline system. This capacity is needed to fulfill customer demand, given an expectation for growth from the Northeast BC Montney and Pembina's previously announced long-term midstream service agreements with 3 premier Northeast BC Montney producers for the transportation and fractionation of liquids. On our Cedar LNG project, we continue to make great progress. Subsequent to the quarter on July 6, Cedar LNG received its LNG facility permit from the BC Energy Regulator. This is another major regulatory milestone that follows the receipt of the environmental assessment certificate from the BC Environmental Assessment Office, a positive decision statement from the Federal Minister of Environment and Climate Change, and a pipeline permit for the Cedar LNG pipeline connection to the Coastal GasLink pipeline. Collectively, these reflect the key permitting milestones for Cedar LNG. Cedar LNG signed incremental, non-binding MOUs with investment-grade counterparties for long-term liquid fraction services and are now fully subscribed in relation to the project's total capacity. Work towards the signing of definitive agreements is ongoing. Cedar LNG elected to progress a second feed process for the floating LNG vessel in late 2022, and it's been waiting for that work to progress to the same stage as the original feed. In conjunction with detailed commercial discussions and ongoing negotiations between LNG Canada and Coastal GasLink, this has resulted in the anticipated final investment decision being revised to the fourth quarter of 2023. During the quarter, Pembina released its 2022 sustainability report, which provides updates on the advances made in the ESG focus areas of governance, energy transition and climate, employee well-being and culture, health and safety, responsible asset management, and indigenous and community engagement. The 2022 sustainability report captures the continued progress on Pembina's ESG targets, including greenhouse gas emissions, intensity reductions, and equity, diversity, and inclusion. With respect to GHGs, Pembina remains on track to meet its 30 by 30 emission intensity reduction target. In relation to Pembina's diversity targets, women now represent 45% of the independent members of our board and 35% of our executive team, exceeding the goals we set. We are proud of the progress we have made to date on Pembina's sustainability initiatives and look forward to continuing the journey. The latest report is available on our website. I will now turn things over to Cam to discuss in more detail the financial highlights of the second quarter of 2023. Thanks, Scott. As Scott noted, Pembina reported second quarter Adjusted EBITDA of $823 million, which represents a $26 million or a 3% decrease over the same period of the prior year. The combined impact of second quarter Adjusted EBITDA and reduced operating pressure on the Northern Pipeline System and wildfires was approximately $47 million. Finally, second quarter results also include various other revenue deferrals and costs with a net impact of $21 million to Adjusted EBITDA. In pipelines, additional factors impacting the quarter primarily included higher revenues on the Peace System and Cochin Pipeline due to higher tolls and lower revenues from Alliance Pipeline, as the second quarter of 2022 included the sale of linepack inventory, combined with seasonal contracts being replaced by firm contracts at lower regulated rates, and finally, lower interruptible volumes driven by the narrower AECO to Chicago natural price-- natural gas price differential. In facilities, additional factors impacting the quarter included the PGI transaction and strong performance from the former Energy Transfer Canada plants and the Dawson assets, as well as lower realized gains on commodity-related derivatives associated with a commodity derivative contract. In marketing and new ventures, second quarter results reflect lower crude oil margins resulting from lower prices across the crude oil complex and lower NGL margins as a result of lower propane and lower prices. Realized gains on commodity-related derivatives for the quarter compared to losses during the second quarter of 2022, a lower contribution from Aux Sable as a result of lower NGL prices. Finally, in the corporate segment, second quarter results reflect higher shared service revenue and higher general and administrative expense and other expense, which included lower long-term incentive costs. Earnings in the second quarter were $363 million, representing a $55 million or 8% decrease over the same period in the prior year. In addition to the factors impacting Adjusted EBITDA, earnings were impacted by lower depreciation, lower unrealized gain on commodity-related derivatives, and lower net finance costs. Total volumes of 3.187 million BOE per day for the second quarter represent a decrease of approximately 5% over the same period in the prior year. Volume decreases were attributable to both the pipelines and the facilities divisions, including, most notably, the net impact of the reduced operating pressure on the Northern Pipeline System, lower volumes at the Younger facility and the Redwater Complex due to the reduced operating pressure on the Northern System, the impact of the wildfires, the disposition of the Empress I and Empress VI assets at our Empress facility, higher volumes at the former ETC plant and the Dawson assets, and higher volumes on AEGS. Adjusting for the impact of the Empress I and Empress VI disposition, the reduced operating pressure on the Northern Pipeline System and the wildfires, volumes in the quarter would have grown by approximately 5% over the second quarter of 2022. Based on results through the first half and the outlook for the remainder of the year, Pembina has narrowed its 2023 Adjusted EBITDA guidance range to CAD 3.55 billion-CAD 3.75 billion from the previous range of CAD 3.5 billion-CAD 3.8 billion. The revised range reflects the current outlook for commodity prices and an expectation of significantly stronger volumes in the second half of the year. Based on our 2023 guidance, cash flow from operating activities is expected to exceed dividends and capital expenditures. To date, Pembina has repurchased CAD 15 million of common shares and reduced proportionally consolidated debt by approximately CAD 600 million. We will continue to evaluate the merits of debt repayment relative to additional share repurchases for the remainder of the year. At June 30, 2023, based on the trailing 12 months, the ratio of proportionally consolidated debt to Adjusted EBITDA was 3.5 times. Pembina expects to exit the year with a ratio of 3.4-3.6 times, reflective of our strong balance sheet and supporting our strong BBB credit rating. I'll now turn things back to Scott. Thanks, Cam. In closing, I'd like to reinforce that Pembina's business continues to perform very well. Pembina's outlook for meaningful medium-term volume growth in the WCSB remains unaltered. We are poised to benefit through increased utilization across our asset base and through new growth projects. We continue to diligently execute our strategy within our financial guardrails while returning capital to shareholders and positioning ourselves to fund future growth. Thank you for joining us this morning and for your continued support. Jenny, please go ahead and open up the line for questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touchtone phone. You will hear a three-tone prompt acknowledging your request. Questions will be taken in the order received. Should you wish to cancel your request, please press star followed by the two. Your first question is from Jeremy Tonet, from J.P. Morgan. Please ask your question. Hi, good morning. Morning, Jeremy. Just want to dive into the fundamentals a little bit more, if we could. Curious what you're seeing as far as producer-customer conversations and expectations for, for drilling activity here as it relates to your footprint, given recent developments and also competitive pressures. Just wondering if you could give us updated thoughts as far as what type of volume growth trajectory you could see over the near or medium term? Yeah, Jeremy, I'll, I'll start, I'll let Jaret jump in if he wants to add some incremental color. I think, you know, I think based on our comments in the prepared remarks, you would've seen that we're pretty optimistic about volume growth across the basin. We're still expecting roughly 4% growth on the conventional pipeline system. You know, I do think it's very customer specific though, when you go through many Q2 reports, you would've seen increased activity, you know, not only throughout this year, but also into the upcoming years. Obviously, there's been some pretty decent-sized projects sanctioned in Northeast BC. Many of those we have under contract today. We do have visibility beyond 2024 into 2025 and into 2026. We remain optimistic around volume growth within the basin, as well as our ability to capture that on our systems. Yeah, I'll just add to that, Jeremy. Pre-wildfires, you know, really what we were hearing from customers was gas egress was becoming their, their largest constraint here in Western Canada. Since then, we, we saw at the, at the worst of the worst, pardon me, about two Bcf of gas come offline. That's now, you know, just under 1 Bcf, so about just over 1 Bcf has come back. We are seeing in kind of like the short term, some of our customers are taking advantage. If they had gas behind pipe, taking advantage of that, that incremental, I'll call it, IT space on, on third-party gas egress pipelines. That's, that's positive for us and for some of our customers. Then I think in the very short term, what we've seen is June, July, and August have had, very high demand for pumping services here in Western Canada, which is obviously, a great sign that that production, you know, as expected, will be coming on over the next, you know, two to three months as our customers tie those wells in. It's-- as Scott said, it's looking positive. Got it. That's very helpful there. Just want to shift gears towards Cedar LNG, moving the FID back according to 4Q. Just wondering if you could peel back the onion a little bit more on the drivers and the shift of the, of the timing there. How much is factors under your control versus not under your control for the timing shift and confidence level at this point in getting to the finish line? Hey, Jeremy, it's Stu. you know, we remain very confident, with the schedule that we proposed here to, you know, look to FID Cedar in the fourth quarter of 2023. The largest, you know, reason for our move, as stated, is, you know, we elected to kick off an alternate feed. you know, that was done with the intent to, obviously, to create some competitive pressure to do the, you know, from a capital cost perspective, you know, to do the best industry practice, to have some competing bids and some pressure on the EPC firms. That work is ongoing. you know, we are pushing to get both of the EPC firms bids before we kick off a repricing here. That work is continuing as we expected. It's a bit later than, you know, we had originally anticipated, and that's resulted in us pushing that back. There continues to be other, other ongoing negotiations that, that are out there, but the larger reason is our choice to elect with the second feed and to get those timed to come in simultaneously for us to review. Got it. That's very helpful there. Thanks. Just the last one real quick here. We've seen some major moves among midstream competitors, both in Canada as well as potential consolidation in the U.S., and just wondering if you could provide us any updated thoughts, I guess, on, you know, Pembina's views as far as any, you know, strategic outlook here, you know, spinning, consolidating, tuck-ins, or anything else, would be helpful to get updated thoughts on. Hey, Jeremy. I mean, it's Cam here. I mean, I, I think, you know, as we've always said, you know, we, we, we look at opportunities to enhance the, the, the asset base and the portfolio. Really, you know, as we released kind of the, the, the refreshed or the, or the re-reviewed strategy earlier this year from the results of the work we did last year, you know, that really anchors how we look at any investment, whether it's organic, external, any, any other sort of strategic investments. You know, I think obviously we're pretty excited about some of the organic investments that we've got. You know, you mentioned Cedar. There's, there's a number of other things that we're working on. Of course, I mean, we're gonna look at, look at other opportunities as, as they're available. You know, frankly, the, the list of opportunities that are available at the moment, I think are, are pretty narrow, you know, which, which would actually be additive to our business. You know, I, I think we'll, we'll sort of look at things as they come up and, and continue to be disciplined as we always have. Nothing has, has really changed on that. Got it. Would it be fair to say an interest in TMX is probably the main thing under consideration and not really much else out there, given the, the narrow list as, as you described? Well, it's certainly the biggest. I, I would say that obviously we've been public about our partnership with WIPG and, and continue to be very proud as-- of being, selected as, as their operating partner. I think as we've said in the past, I mean, you know, as, as far as we know that the asset is not for sale at the moment, you know, we'll, we'll continue to-. ... to, to do work and, and obviously stick to our guardrails. If and when that becomes available, we'll, we'll evaluate it. You know, so far, so far, no action. Got it. That's very helpful. Thank you. Thank you. Your next question is from Rob Hope from Scotiabank. Please ask your question. Good morning, everyone. two follow-up questions. Maybe first, on the conventional volume outlook, you, you did note that it was going to increase 4% this year. Volumes on the conventional system have been down in the first half. When we take a look at achieving that 4% growth in 2023, is that pro forma the wildfire impacts? Could we see a makeup of lost volumes in the back half of the year? Or is this really just given the amount of growth that you're seeing in the system right now that will carry over into 2024? Hey, Rob, it's Jaret. No, you basically nailed it. You know, although we were, you know, slightly under in the first half of the year, due to the reasons that you noted, we do see that strong growth in the second half, just like you mentioned. Yeah, Rob, it's Cam. I'll just add in that obviously, you know, the second half always has the typical profile to it. When we're talking volumes, we're talking revenue volumes. As you look at our disclosure, we've got more, slightly more volumes or recognized volumes deferred for Q2 than we did last year. A little bit of a revenue tailwind there in Q2. As Jaret said, we're also seeing strong, strong outlook on the physical side as well to supplement that. All right. Appreciate that, especially the color in revenue versus actual volumes. As a follow-up on the Chinook Pathways partnership and the opportunity there, you know, when this was set up, it was a 50/50 JV between yourself and the WIPG, but the environment has really changed. How do you think about the size of the potential opportunity there, as well as the potential financing opportunities? You know, specifically, you know, is 50% still the bogey or something much smaller in that 20%-25% more likely with the potential that you could use some hybrids and some asset sales to finance it? Yeah, thanks for the follow-up, Rob. You know, it's, it's a really good point. As, as you mentioned, you know, when, when that partnership was structured, you know, we were less than 0.5 of the current size of the investment that it is today. I, I do think we, we think about things here from a portfolio perspective and, and what size of, of certain asset types we want in our portfolio. That's not only commodity or commercial, it's, it's, it's, it's the customer portfolio, it's, it's the market, the access. It's, it's all these points that we think about from a portfolio perspective of our asset base. When we do think about that, that asset in light of a larger potential growth investment size, we, we do think about keeping things largely similar from, from them as net investments. When, when you talk about sort of a smaller than 50% investment, I would say that's, that's where our heads are at as, as we think about this asset under the current circumstances. To pin it down to an exact number, tougher. Yeah, I think that sort of 20%-30% range is, is probably where you get to the same sort of asset investment size for Pembina, probably the, the, the right scope on it. You know, in terms of finance, I think what we've said is obviously a commitment to the financial guardrails and our strong BBB rating. There's a lot that goes behind that, but obviously, you know, we recognize that, you know, over history, a strong balance sheet has been a strategic advantage. And when it's not, it's obviously a big distraction and a hindrance. We're absolutely focused on maintaining that strong balance sheet, but also recognizing that as part of that, you know, there's potentially some creativity required for an asset such as this. You know, we're exploring different avenues for financing, to obviously keep the investment and our business within the financial guardrails, but also deliver a strong value accretive investment. If, if, if that isn't available, obviously, then, you know, we'll, we'll continue to be disciplined as we have in the past, and as we've got lots of other opportunities. Thank you. Thank you. Your next question is from Linda Ezergailis from TD Securities. Please ask your question. Thank you. just looking at Cedar LNG, recognizing that you've been working on this for a while, how might we think of your creativity potentially around financing that and ensuring it stays within the guardrails? Would you see project financing, and what might be the cadence of spend, and might that cause you to high-grade any other potential investments you see? Hey, Linda, it's Cam again. Yeah, thank you. You know, one of the things we really love about Cedar, obviously, in addition to the, you know, the strategic aspect of it, I mean, we've always really thought that LNG was a fantastic strategic, strategic fit for our company. The really nice thing about Cedar is, is obviously the scale of it. Obviously, at 3 million tons and an associated capital cost, you know, it obviously fits very nicely for a company the scale of Pembina. When we look at it, you know, when you think about the nature of those commercial agreements, long-term agreements backed by investment-grade counterparties, obviously, that's a highly financiable asset. You know, we are exploring project finance for that, with, you know, with a commensurate leverage structure. ... you know, when you, when you, when you look at that, relative to Pembina's free cash flow generation of, you know, you know, last year it was, you know, getting rid of the, the one-time impacts around CAD 1 billion of cash flow after dividends. If you, if you stretch that forward, you know, we're in a very strong funding position going forward. The, the spend for Cedar, you know, on the current time frame, really wouldn't accelerate until the 2025, 2026 time frame. But we see it very readily financeable within our, our existing liquidity sources, existing cash flow. It, it, that, that timing works really well with the case of the other projects we've got going on. Obviously, you know, Phase VIII comes online next year. Redwater 4 comes online in the first half of 2026, it fits really nicely with the rest of our portfolio from a spend perspective. Thank you. Just as a follow-up, looking at accessing Tidewater, maybe with LPG and NGLs, what are you seeing in terms of customer preferences for the optionality to either rail down to the U.S. or bring to the West Coast? Any sort of West Coast pathway, do you see that continuing to go through the Edmonton, Fort Saskatchewan area, or do you see the merits of, of going direct to the West Coast? If you can just comment on flows of NGLs prospectively a- and your outlook for that, that would be helpful? Sure, Linda. It's Chris. I think that, you know, customers continue to value a bit of a portfolio. They don't wanna see everything pointed at the West Coast. You know, that being said, right now, ARBS are extremely strong. If you look at Conway FPI differentials and Edmonton FPI differentials, there's a really positive case for going west. We do think in the long term, those Far East markets are gonna be very attractive, so there is room for more off the West Coast. We continue to hear from our producer base that they wanna see flexibility, they wanna see us access the best markets at the best times and not get stuck with a sort of one-trick pony, if you will. I think, when you talk about coming to Fort Saskatchewan, we continue to believe there's a real advantage to aggregate into Fort Saskatchewan. We've got tremendous rail capability out of the area. Like I said, it, it leaves that optionality open to go to the best markets at the best times, and, and we continue to see support for that. Thank you. Thank you. Your next question is from Robert Catellier from CIBC. Please ask your question. Hi, you've answered most of my questions. I wanted to follow up on Cedar LNG specifically with respect to what needs to be accomplished between LNG Canada and Coastal GasLink for their negotiations before you can reach FID. I assume that relates to the final tolls. Aside from that, can you just comment on the executability of that 8.5 kilometer pipeline from the Coastal GasLink to the Cedar site, and how you're planning to manage cost risk on that aspect of the project? Yeah, Robert, Stu. Yeah, I mean, LNG Canada and Coastal GasLink can, you know, have been, you know, negotiating and finalizing their arrangements for a continued period of time, obviously, with the announced Coastal GasLink cost increase. There's also, you know, as they move forward, how that relationship is going to be managed and developed. It's ongoing. We continue to work well with LNG and with Coastal GasLink. We are waiting in some cases for them to complete some of these negotiations, but there's been good progress made. It is something that we need to finalize for our connection agreements and for our transportation agreements on Coastal GasLink. We continue to work with both parties in a positive way. As far as the execution of the pipeline, it is, you know, we're coming from the end of the Coastal GasLink connection from the header. As you described it, 8.5, 9 kilometers of pipe. We're looking at pipeline routing. We've, we've, we've obviously right away identified. We've drilled our, our, our test holes to identify the terrain and then the, and the materials that we would actually be going through. We remain confident of Pembina's ability to execute that pipeline in, in a cost-effective manner. We have someone in and working on this project that has done mountainous pipeline in, you know, install, and so we've priced it accordingly and have a plan to execute in within that pricing. Okay, thank you. Thank you. Your next question is from Ben Pham from BMO. Please ask your question. Hi, thanks. Good morning. I just wanted to check the quantification of the wildfires and, I guess, less the extent piece. Can you walk through? Is that just in terms of the process, is that just simply taking your the volumes that have declined and you're using a margin that's been earned on that segment in the past? That's, that's right, Ben. That was based on our outlook. That was based on our outlook and, and where we were sort of pre-fires. I mean, obviously, we've, you know, we've got, we've, we've got profiles from customers, and we've got, we've got the outlook there. Basically, it was, it was our outlook for, for what that would have been, based on, on a regular operating condition. You can also recall that, you know, there was a, a, a little bit of IT on some of the systems, but most of that, most of those volumes were flowing, right at sort of take-or-pay levels. You know, it, it, it's, there's not a lot of variability actually in it. Okay, got it. Then maybe, Cedar, I want to do that last question. Is, I know you mentioned some of the tolls being finalized. Is Sanction at all linked directly to in-service on Coastal? Is there a link between the two? Sorry, Ben, I missed. Can you repeat your question? Yeah, I was just thinking with, with Coastal. Coastal GasLink expected in service late this year, you can tee up a sanction on Cedar, but if it, if it gets pushed to next year, is that, is that linked to your sanction decision, or there's, there's enough leeway on, on, on timing that even if it's delayed by a year, it doesn't, doesn't really impact the sanctioning decision? Yeah, our timing will not be impacted by, you know, Coastal GasLinks in-service date. Our first gas isn't until, you know, 2027 type, you know, for commissioning purposes. We have, we have plenty of leeway for them to complete their project, of which they're, you know, they're making progress on and driving forward. Yeah, we have, we have lots of slack built into that system. Okay, got you. Maybe just, just the last one, a couple of questions on M&A and TMX. I'm more curious, as you think about M&A now, you have TMX, which is a 25-year contract, so premium assets, then you got a couple other assets out there in North America that might have a shorter dated contract with potentially lower multiple. Like, what do you think the best opportunity is for you then? I mean, you can take TMX, high-grade your cash flows, but then is there maybe an arbitrage for some of these shorter dated contracts that the market's not placing a good premium on in the market today? Yeah, Ben, I, I think the way we've talked about it is, is in terms of, the, the strengthening of the guardrails with TMX from a fee-for-service perspective and a fee-for-service payout ratio, really will allow us more so to look at other opportunities that potentially have some minor commodity exposure, versus, versus shorter-term contracts. That's not something that, that we've currently put into the mix, but obviously, with our, with our position, in the NGL market, we like that business. you know, we think that we have some competitive advantages, and we're really good at NGLs. So to the extent that there's opportunities that come with some incremental exposure, we can capture those once we strengthen our guardrails through the TMX acquisition, if successful. Hmm. Okay. All right. Thank you. All right. Thank you. Your next question is from Andrew Kuske, from Credit Suisse. Please ask your question. Thanks. Good morning. Maybe just addressing your various low-carbon businesses. Alberta Carbon Grid, the Low Carbon Complex, and low-carbon ammonia. Maybe bookend these, like, how big do you think these businesses could be as part of the balance sheet or the investment opportunity on the big end, and then on the low end, you know, what's sort of the toe in the water part of the business? Yeah. If we think about those investments, you know, as kind of aggregate buckets, you know, if you're putting me on the spot, I'd say somewhere between $2.5 billion-$4 billion of incremental capital that we see line of sight to potentially deploying across those asset bases. That's over the next decade to 2030. That's not immediately, but our near-term focus really is on the Alberta Carbon Grid and on blue ammonia, which would then tie into our Low Carbon Complex and really accelerate the profile of that asset base. We're pretty excited about it. Obviously, the ammonia is early days. We just announced our, our partnership this quarter, and we're really, we're really just in the pre-FEED stage, but we do see a, a pretty, pretty decent opportunity there. As, as we continue to attract, capital towards Low Carbon Complex, we think there'll be a snowball effect, and we can attract incremental projects to that site. I, I appreciate that color, and maybe with that snowball effect, how do you see this entire business line working within your permanent store concept? Is it really like another, you know, part of the slide? You've got the three already. Is this a fourth, or does this, this business group sort of intersect all of the three that you've got now? Yes, Stu, again, I think you've hit on it. We, we know there's an opportunity of, for, you know, the fourth, a platform for growth and opportunities presented. At the same time, it interconnects with our existing asset base. You know, there's opportunity to provide feedstock, there's opportunity to, to, you know, our operating expertise in the area, our facility expertise, and build. It does, it does integrate very, very well and does have an, you know, opportunities for future growth in, in that space as well. Maybe just an extension on that, Stu. Do you see this sort of conceptually like a multiplier that you had off of Redwater, where it gave a lot of growth across different business lines? Is that the same conceptual thing for the low-carbon business? ... Yeah, it, it has that potential. You know, we're, we will continue to follow Pembina's guardrails. I think, you know, we always look at it as a, a tolling model and not to be in the commodity space, so it's got a fit for us there. Redwater and, you know, that, you know, working with our marketing team and, and our expertise in the LPG space allowed us to probably go a bit further and offer more expansion and back into the business. Here, we're probably, you know, a bit more limited to a tolling and, and OSBL services arrangement, you know, looking at the markets and getting marketing help from others more in that international space. Okay. Thank you. Appreciate the color. Thank you. Your next question is from Robert Kwan from RBC Capital. Please ask your question. Good morning. Whether it's, you know, Cedar, potentially other sizable investments, can you just refresh the types of returns that you're seeking, or if you wanna look at it from a build multiple perspective, that works? Then just as it relates to leverage, the leverage guardrail, and specifically the top end, is that top end firm, or would you be willing to exceed it for a period of time? Maybe just confirming that you're committed to continuing to look at that guardrail on a proportionate consolidated basis. Hey, Rob. I, I would say that, you know, the, the types of returns that we're seeing-- I mean, obviously, you know, in, in, in the past, you know, through the, the latter half of the last decade, I mean, I think our, our experience was build multiples in the range of, you know, sort of 6x-8x overall. Obviously, you know, the brownfield ones towards the lower end of that range, and sometimes, even below that. The, the greenfield ones in, in most cases, towards the upper end of the range. Of course, as I mentioned before, our portfolio is important to, to sort of keep that blended multiple in the right range, and hopefully, keep it to the lower end. I would say that, you know, in, in our, in our current outlook with our existing projects, you know, we're, we're not far off that. We're in the same range. We're probably still sort of in that 7 to 9 times multiple ranges. Obviously, the, the 9 times multiple ranges are reflective of those opportunities where there's very low risk embedded in them, long-term contracts, you know, high-grade counterparties. Some of the, the opportunities at the lower end of that spectrum are, the brownfield opportunities, the integration opportunities. It's kind of the, the typical stuff that we, we know and, and do quite well. I would say that for us, you know, that's been part of the strategy, and, and with the asset base that we have and, and sort of the connectivity between them, we continue to see opportunities around that and in that range. As it relates to, as it relates to leverage and our, our thoughts on that, you know, I would say that, you know, we've obviously got a commitment out there to a strong BBB rating, as we've long talked about, and, and the financial guardrails. You know, which, which, frankly, is a, you know, is really ultimately anchored in a, in a rating agency methodology and the way they look at it. We, you know, we sort of take the, the simplistic view of saying, you know, leverage is leverage, and there's an appropriate amount of leverage, you know, for an asset wherever it sits, and that's obviously why we talk about personally consolidated leverage. You know, we've, we've had a guardrail there or a, a range of sort of 3.5-4.25. You know, I would say that as the industry has evolved and, and, and, you know, the industry environment has obviously changed, you know, the, the, the high end of that range is, is probably something we would shy away from, you know, at the moment. w, we, we pretty consistently hear from the market, and as we said earlier, that strong balance sheet and, and strong leverage is an advantage. So even, you know, kind of getting above that 4 times is probably going to start to give us heartburn. But yeah, I would say we do continue to look at that on a, on a proportionately consolidated basis, and, and obviously, sticking to that leverage commitment is, is something that's been part of our success, and, and don't see any reason to change that. Got it. As it relates to just the short-term leverage, small changes quarter, kind of 3.4-3.6, and I think previously you were 3.3-3.6. It's not a big deal, but just is that EBITDA changing, or is this maybe a bit of an indication of a bias towards share buyback, just given the current share price versus debt repayment? No, I, I just think it was narrowed. It was basically based off of our guidance range, and obviously with the narrowing of the guidance range, just due to rounding the 3.6, obviously didn't move, but just due to rounding, the 3.3 went to 3.4 as we lowered the top end of that guidance range. It's really the narrowing of the EBITDA range versus anything else, Robert. Got it. Okay. Just last, just coming back to that, the question or your answer on the timing of the FID for Cedar versus Coastal GasLink. I get the timing of, of when your project will be online, and, and you could have a CGL delay, but wouldn't you want to see Coastal GasLink completely, you know, mechanically complete, just given what's gone on? The other is, is there still is some toll finalization based on the cost on CGL, so how do you protect yourself on where that final toll goes, you know, before you commit to the, the FID? Yeah, Robert, we're again, those negotiations are ongoing. Again, the work between CGL and LNG Canada, they're looking at that. The negotiation of the existing base pipeline is complete. We know what our toll is. The next phase is the expansion to add the compression. ... that is required, and so that's, that's ongoing, and that- those negotiations are, are underway. We're hoping those will be completed here in the next little while. We expect to have that done in our, our transportation agreements, we would have in hand as we make FID. Got it. You need to see, though, that happen before the FID? Yeah, we need to be able to tell our offtake customers who will ultimately be the, the holders of the capacity on CGL, what's the, what's the transportation agreement gonna look like? Okay. You're tied to the tariff, but you're, you're comfortable on mechanical completion? Yeah, mechanical completion of the Phase 1, and then we need a compression addition to get our capacity for the Cedar. Okay ... Cedar service. Okay. Thank you very much. Thank you. Once again, that is star one should you wish to ask a question. Your next question is from Patrick Kenny from National Bank Financial. Please ask your question. Good morning. It's been about a year since you closed the PGI transaction. Wondering if you can comment on how integration has gone relative to your initial expectations? Also, you know, as a vehicle created to unlock growth, thinking about long-term landscape surrounding the org or M&A opportunities around PGI's footprint? Pa, I think you, you cut out, but I think that we got the gist of the question, which was around integration and organic and other opportunities at, at the asset base. You know, I think from a, from an integration perspective, it's gone as planned, maybe slightly below budget. Obviously, you know, a lot of, a lot of time and effort in the field to get the plants into permanent systems, but the, the opportunity growth continues to expand there, and I'll maybe turn it over to Jaret. I mean, we're pretty pleased with, with both the volume growth we've seen at those assets, but as well as now that we've had, as you said, our hands on the wheel for a year, we're really starting to see not only opportunities at that asset base, but opportunities and synergies across the gas plant. Maybe I'll turn it over to Jaret.. Yeah, thanks. Thanks, Pat. Good morning. Maybe I'll just break it down into a couple of buckets. 1 is the Pembina processing assets, they're performing as we would have expected. Obviously, we had pretty good line of sight into that. The Dawson assets, which we, we acquired an incremental working interest in, specifically the CRP, Cutbank Ridge Partnership. In that area, what we're seeing there is that that is exceeding our expectations, even through the Veresen Midstream lens. The performance of those wells that the partnership are drilling, and they're public, that's public information, is outstanding. The development and the activity going into the startup of Coastal GasLink, we're seeing that ramp up and, you know, maybe a little bit more gas than we had expected, which is great. Obviously, that's a processing tolling model, that's kind of the one bucket. The incremental ETC portion that we acquired 60% of, that is exceeding our, our, our model expectations. We're just seeing a lot of, of gas getting drilled into our, our white space, which is great. I think now that the team, you know, it's been roughly a year here coming up on August 15th, there is a lot of optimization opportunities. Just we're not able to speak to those specifically right now, but as we move through sanctioning gates, we'll disclose those. On the, I think I mentioned last quarter on the call that there's a significant amount of expansion opportunities through the PGI platform, across the 3 different businesses that we combined. Not only for gas processing and liquid handling, but also on the GHG reductions. Obviously, our processing business contributes a significant amount of our GHGs, and, and the team has a lot of opportunities there to work with our customers to lower their carbon tax while deploying capital and lowering Pembina's emissions. That's kind of how I'd sum it up. Positive. Okay. Okay, perfect. Thank you. Then, wanted to check in as well with respect to your exposure to Alberta power prices. I know the 100-megawatt Garden Plain PPA kicks in here right away, but I guess pro forma of that contract, can you remind us what your net exposure to the grid would be, you know, relative to total power consumption? Also, if you're looking to sign additional renewable offtake agreements, beyond that, just as part of your plan to reduce Scope 2 emissions, and if so, how you might be thinking about, you know, achieving your goals in light of Alberta's announcement to take a pause on approving any further renewable developments in the province? Thanks. Yeah, Pat, I, I mean, I'm not gonna get into, to specifics with our usage, but you would've, you would've seen, obviously, over the last two years, we would've signed two different renewable power agreements, to, to really capture a significant portion of our net exposure to, to the power prices. In addition to that, we obviously commissioned our cogen at Empress, and in addition, looking at a few different cogen opportunities across our, our asset base. We also have small solar going in at Empress as well. So we, we are actively managing our exposure to, to the, the Pembina fully owned exposure to the power grid. In addition to that, you know, a, a large portion of our OpEx is flowing through, but we're working really hard to reduce power where necessary and, and optimize the use to that, because obviously we want as little of OpEx as possible for our customers. We're really focused on optimizing power use across the asset base, because the, the volatility we've seen in the power prices is obviously a, a significant line item for, for Pembina and our customers. We're doing everything in our power to look at reducing, reducing that usage. Just circling back, as it relates to our net exposure, we're mostly protected on that through some of the PPAs we've signed and some of the other initiatives we've been undertaking. Just on top of that, you know, Scott mentioned, you know, obviously we're working to utilize less consumption, which obviously supports lower OpEx for our customers, but lower Scope 2 emissions. Chris's team, Chris Scheeren, has an energy management team and also a lot of work internally on peak power price avoidance. With our, obviously, our Peace System, Pat, you know, we have a lot of storage at various places. We don't have to be continuously pumping when price is, you know, CAD 900 a megawatt. Being very proactive on when do we need to be storing and when should we be pumping, and that's all run out of our Sherwood Park Control Center. That's been a huge win for our customers as well. Okay. That, that's really good color, guys. Appreciate that. Sorry, just one follow-up question on the Alberta Carbon Grid, if I could. We've seen a bit of a slowdown on the, the capture side of the equation, you know, with respect to some government support coming to fruition. Wondering if that's translating into any slowdown on your end in the development process of ACG? I guess, if there's just any update on timing related to a potential FID or, or in-service date, that would be great. Yeah, Pat, maybe just to just reemphasize where we're at. We have we've been busy. We have an appraisal permit from the government of Alberta that has allowed us to be out. We've bought seismic and reprocessed, since we've shot additional seismic over our proposed sequestration site. That work has been completed. We are in the process of getting ready to drill our evaluation well. That will be drilled here in the second half of 2023. You know, essentially, that work upon completion and some evaluation of the results will allow us to prove up that we have a sequestration site. We've had preliminary conversations with off-takers, Sorry, not off-takers, of, of use of the, the sequestration. There remains interest. You know, it's competitive. It, it's, it's a little bit still out there. Our work has largely been focused on proving up our site and initial conversations. Once we get that and move into 2024, we'll ramp up the, the commercial conversations upon, you know, proof that we actually have something that we can use and sell. We haven't changed our FID date or any of that timing at this point. Okay, that's great. Thanks, everybody. Have a great long weekend. You as well. There are no further questions at this time. Please proceed. Thanks, everyone. Really appreciate you calling in on a Friday before a long weekend. Obviously, as we, as we said in our, in our prepared remarks, a challenging quarter, but we remain optimistic through the back half of this year. Everybody, have a great long weekend, stay safe, and have a good rest of your summer. Thank you.