Pembina Pipeline Corp Q1 FY2022 Earnings Call

Good day, and welcome to the Pembina Pipeline Corporation 2022 First Quarter 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 first quarter 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 & 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 & Analysis dated May 5, 2022, for the period ended March 31, 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 that 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 $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 first quarter 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 first quarter and a positive outlook for the rest of the year, we have raised our 2022 adjusted EBITDA guidance to $3.45 billion to $3.6 billion. In addition to a strong financial quarter, 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 B.C. 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 B.C. 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 Pembina volumes from a multiphase development of the producers' Northeast B.C. Montney acreage on a take-or-pay basis upon the acreage being developed. Lastly, we have finalized commercial terms of the third leading Montney producer regarding significant long-term Northeast B.C. volume commitments and expect commercial agreements to be signed by mid-2022. Pembina sees the Northeast B.C. 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 that customers 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 B.C. 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 Phase Peace Pipeline expansions. As a result of the Northeast B.C. commitments, secured in ongoing conversation with other customers, Pembina is pleased to be reactivating the previously deferred Phase 8 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 7 at this time. We are also looking forward to the expected placement into service of Phase 7 expansion on June 1, ahead of schedule and approximately $150 million under budget. As well, construction of Phase 9 expansion continues, and we've updated the in-service date of that project to the fourth quarter 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 advantage unit train capabilities, along with its current Prince Rupert Terminal to 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 quarter, 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 has been partnered in Veresen 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 and unlocks value for Pembina, creating 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 $0.0075 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 third quarter 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 first quarter, 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’s carbon capture utilization and 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 in Alliance pipeline recontracting. Recent open seasons, including six open seasons offered to the market during the first quarter 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 good news story as the recontracting success highlights the value of Alliance's reliable and highly competitive access to Midwestern US gas markets and 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 first quarter.

Thanks, Scott. As Scott noted, Pembina recorded a record quarterly adjusted EBITDA of $1.06 billion, representing a 20% increase over the same period in the prior year. The first quarter 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 Aux Sable. 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 inventory built up during the second and third quarters of 2021 were sold during the first quarter of 2022 in a higher price environment. In addition, crude oil marketing realized stronger blending margins due to a 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 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 first quarter of $481 million, representing a 50% increase relative to the same period in the prior year. In addition to the factors impacting adjusted EBITDA, earnings were positively impacted by lower impairments and a higher unrealized gain on commodity-related derivatives for certain gas processing fees tied to AECO prices. First-quarter 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 first quarter were down approximately 3% compared to the same period last year. The 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 $3.45 billion to $3.6 billion from the previous range of $3.35 billion to $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 1 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 $58 million towards the 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 that is 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 quarters 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 accretive 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.

Yeah. Certainly. And we'll take our first question from Jeremy Tonet with JPMorgan.

Hi. Good morning.

Good morning, Jeremy.

I want to begin by discussing the increase in guidance. Instead of asking about the annualized figures for the first quarter compared to the full year, I'm interested in understanding the reasons behind this increase. Is this primarily due to strong performance in the first quarter marketing, or do you see improvements in the core business as well? Additionally, if you consider the boost from the NewCo joint venture, can you provide any insight on the expected uplift from that? What would be the anticipated uplift from NewCo in its first year?

Sure. It's a combination of both. As you know, marketing usually has its strongest quarters in the first and fourth quarters. Now that we're through the first quarter, we have a clearer idea of our best marketing quarter. This understanding is what contributes to the increase on the lower end of our guidance range. On the higher end, it reflects an improved marketing outlook along with increasing volumes across the system. Regarding NewCo, forecasting is always challenging since it depends on the closing date. If we close in the third quarter, it will likely be in the range of $15 million to $20 million.

$15 million to $20 million would be the uplift for the balance of the year or kind of an annualized uplift, just to clarify?

For the balance of the year.

Thank you. I'd like to shift the discussion towards our capital allocation strategy. You've mentioned some factors in your previous remarks, but I'm curious about how things have changed since the last call. Our EBITDA is significantly higher than we anticipated, there's increased growth CapEx with new projects on the horizon, and our share price has also risen. How do you see these elements influencing your thoughts on the timing and outlook for buybacks at this point?

Yeah. If you think about the midpoint of the new guidance range versus the midpoint of the old guidance range, that's $75 million. That's roughly the increase in capital we expect to see in 2022 for the re-sanctioning of Phase VIII. So you can think about the increase in guidance really going towards funding Phase VIII. As it relates to your question around capital allocation. As you saw in our notes yesterday, we continued to buy back shares. I would say that over the next quarter, we are going to spend some time looking at what the plan would be for Q4 and the remainder of the year. As you rightly point out, our share price has gone from 40% to 50%. Our 10-year yields have gone from 3% to 4.5%, 5%. And so paying down debt, both to position ourselves for growth, but also from an economic perspective has become more attractive. So no change to the guidance right now, but it is something we're spending a lot of time thinking about.

Got it. And just a quick last one, do you have any thoughts on the resolution of the Blueberry River First Nation situation and how that impacts your guidance and outlook?

Sure. I'm going to turn it over to my colleague, Janet, to talk about our perspective on the situation.

Yes. Good morning, Jeremy, it's Janet. We've been hearing very positive outcomes coming from the discussions between the government of B.C. and various indigenous communities, including the Blueberry River First Nation. And so 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, in the coming months.

Jeremy, I would just add, given the discussions we're having with producers, the arrangements we've entered into, that all gave us confidence to sanction Phase VIII.

Got it. That's very helpful. I'll leave it there. Thanks.

Thanks, Jeremy.

We will now take our next question from Matt Taylor with Tudor, Pickering, Holt & Company.

Yes, thanks, guys for taking my question. I wanted to go to Cedar LNG. It looks like you're making good progress there. Can you just give us an update on the commercial discussion, 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 guidepost for financing plans and when you reach the plan to reach FID?

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, very favorable characteristics from a cost perspective, from an ESG perspective, from an indigenous community perspective. It's very attractive to the offtake market. And with the pricing that's there today, we've had very, very positive conversations. We're working very hard to progress from these conversations to term sheets, and that will be what's going to take place for the remainder of this year. Financing, I'll turn it over to Cam.

Yes. On the finance side, I mean, I think, obviously, that's a big piece of it. It's an active work stream. We're looking at a lot of different options there. Obviously, we're working with our partners, the Haisla, to find the most accretive solution. I think ultimately, for Pembina, it's quite a manageable bite size. And when you consider the scale of it, the 50% ownership to Pembina and the timetable for the spend, which is really over a four-year timetable. So for Pembina, quite bite-size, and we're working very closely with the Haisla to help them with their financing situation. More to come on that obviously over the next few months here, as we get closer to a potential FID, but definitely seeing some positive signals so far.

Yes. Thanks. FID sometime next year, is that what you're still targeting?

Yes. We're shooting for sometime following Q1.

Awesome. Great. Thanks for that. And then part of your sensitivities that you previously disclosed was a $39 million impact for every $0.50 move in AECO pricing. So I guess I'm just wondering if this is factored into the 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.

Yes, I’ll address that. You're right about the high AECO price putting pressure on the frac spread for the later part of the year. However, we are 50% hedged. So as propane prices increase, we advise caution because we are hedged on the NGL side. Similarly, regarding input costs, we are also 50% hedged on the AECO side. Therefore, although AECO prices have been rising, we have accounted for that in our updated guidance range, which has increased since then, but we remain comfortable with it. On the positive side, our producer community is generating significant earnings, reducing debt rapidly, and is expected to return more to drilling soon. Additionally, we've observed a notable widening of the AECO Chicago basis. Thus, we are benefiting from strong interest in Alliance and positive developments at Aux Sable linked to that differential. There are many factors to consider, but overall, we feel confident about our guidance range.

Thanks for that, Scott. And 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 US benchmark. So 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?

Yes, I'm going to turn that over to Jaret, but maybe before I do, I'll just clarify that it wasn't canceled. We just continue to defer that project and assess longer-term the need for it. So, I think there's a difference between continual deferral and cancellations. But Jaret, do you want to take that one?

Good morning, Matt. As Cam mentioned earlier, we have unit train capabilities, allowing us to deliver propane across North America and various domestic destinations, which provides us and our customers with a wide range of options. Currently, given the strong domestic pricing in Canada and the United States, we believe that our export capacity of approximately 19,000 to 20,000 barrels is adequate. Moving forward, our focus will be on offering the best domestic options while also tapping into international opportunities when possible. As Scott noted, this is not a permanent cancellation; we will continue to assess the situation, and if market conditions change significantly, we may reconsider our plans. Stu, do you have anything to add from the marketing perspective?

No, I think you've covered it very well, Jaret. We continuously evaluate all the markets that are available to us. We're happy with the mix of markets that we have in the portfolio today. We believe the North American markets will remain strong. Our unit train capability allows us to access those markets effectively. As we assess the situation, we feel comfortable with the markets we're able to access and believe it to be the right choice at this time. If that changes in the future, we will consider moving towards more international markets as they become available.

Great. Thanks for taking my questions. Guys, have a great weekend.

Thanks, Matt.

And 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. Yes, I mean we continue to look. Obviously, the market is evolving. The IPL project, the PDH will be coming into service. We've always liked that project. As we sit here today, we look at what markets are available to us moving down a number of value chains. Pembina plays a large role in feedstock provision. We're working with 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 continue to move further along as you described that. None of those are completely off the table for us, and we're trying to evaluate where Pembina best plays. Again, we think we've historically been a great feedstock provider and we'll continue to do so and we'll look to evaluate and we step further along as those markets progress. We like the petchem 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. And 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 path? 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?

Yes, thanks, Scott. Good morning, Linda. There was a lot to cover, so I'll try to summarize. Regarding dedications, the recent ones we've discussed are quite similar. They are structured with take-or-pays once customers start using our services throughout the value chain. Some customers opt to build their own field-based gas processing, while others rely on us, as seen in our dedications with Harrison Midstream and CRP or our Duvernay dedication with Chevron and Keyera. In the case of Conoco, they have decided to use Pembina's value chain, which includes transportation, fractionation, marketing, and terminalling, along with rail services. As we grow, this flexibility allows us to diversify our contractual arrangements to meet our customers' needs. Inflation has always been a consideration in our contracts and agreements, so we typically incorporate that into our arrangements. I believe that addresses your question.

Yeah. Thank you. I'll jump back in the queue.

Thanks, Linda.

We'll now take our next question from Rob Hope with Scotia Bank.

Good morning everyone. A follow-up question, you continue to secure additional volumes from Northeast B.C. and I guess, Northwest Alberta and looking to draw them into the Fort Saskatchewan 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 your prior strategy potentially doing some field track could be pushed off further just given it looks like you continue to want to move volumes down to the port.

Yeah, Rob, I'll take that. And Jaret, please jump in, if you want to have additional comments. But in general, our fractionation facility is getting pretty tight. As we look forward to the future, we're backfilling contracts. And so we have kicked off engineering on RFS I. 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 field fracs, I think our preference is still to centrally locate 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 additional sources like the IPL/PDH coming online, we still think it's the ideal spot to put it. Jaret, anything you want to add to that?

Hi Scott. Regarding the storage, we struggled to find suitable underground salt cavern storage for the field fracs we considered. As a result, any storage would need to be above ground, which would raise costs. We have largely ruled out the field frac opportunity due to limited rail access and insufficient storage, leading to an inefficient operation. While we are still exploring options, it seems logical to transport our products to Edmonton and the port area because of our extensive cavern storage and rail infrastructure, along with access to several markets from the Fort Saskatchewan region. We will continue to concentrate on the port to benefit from economies of scale, which will enhance the netback for our customers.

All right. Thanks for that. And one more, if I may. We are seeing increased competition for moving liquids out of Northeast B.C. and Northwest Alberta, but you continue to do very, very well on the contracting side. Can you just maybe comment on what key benefits customers are saying regarding your offerings versus the competition?

We have been operating in the communities of Western Canada for 68 years, which has established our reputation. Our in-service assets can be quickly expanded through pump stations and other infrastructure. For example, our Phase VIII project will allow for segregated product flow from Gordondale to Edmonton, optimizing our system and reducing costs. Our customers consider both our capital and operating fees, and with a large volume base, we strive to lower operating costs for them. Additionally, our pipeline connects to various fracking operations around Fort Saskatchewan, giving our customers flexibility. While we secure a significant portion of volumes at the Redwater facility, we also offer options for our customers to go elsewhere. In terms of condensate, we have multiple delivery point connections, which makes our overall package attractive to customers.

All right. Thank you. Appreciate the color.

And we'll now take our next question from Robert Catellier with CIBC Capital Markets.

Hey, good morning, everyone. I just had a couple of questions left on the ConocoPhillips agreement. So it sounds like there's enough infrastructure there with Phase VII to IX, so that there's not a lot of capital requirements in the near-term, and there could be some operating leverage. But as they call on additional capital, it sounds like that's going to be supported by take-or-pay, but will Pembina bear the CapEx risk? Is that the way to look at it?

Good morning. I wouldn't consider it just one customer that would necessitate Pembina to invest capital. The success we discussed previously indicates that if all our customers with agreements continue to grow according to their publicly shared plans, we will need to invest more capital to capture those volumes and enhance utilization from the Alberta side of our system. We will be collaborating closely with our customers to evaluate their development plans to ensure we can support that growth trajectory. It's an exciting prospect. Additionally, we must continue assessing the frac capacity since this pertains not only to NGLs but also to condensate, and we anticipate significant NGLs coming in. With incremental gas from LNG Canada owners expected to come into service a few quarters after our Phase VIII capital deployment in the first half of 2024, this will lead to an increase in NGLs. The situation will be dynamic and fluid, but we believe we are well positioned to invest that capital and meet our customers' needs.

Okay. I understand the plan to aggregate supply from multiple customers to enhance the infrastructure. However, I want to ensure that, given the current inflationary environment, Pembina has adequate protection if the infrastructure is needed three or four years down the line. It’s important that the rates remain favorable and shield you from inflation.

Rob. Great question. I was going to say, our tools typically have TTI inflators in them. So to the extent that there is some capital cost free, we should be able to recover that in our tools.

Okay. That's what I thought. Thank you. And then next question here, I just want to confirm something I think I heard in the response earlier, but there is in fact an opportunity to market the liquids associated with the ConocoPhillips Canada agreement?

That's correct.

Okay. Last one for me. You've made some progress over the last couple of quarters here with Alliance contracting. 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 might be contracted to the extent that that's not immediately commercially sensible for?

We have an open season ongoing that actually closes today, Rob, for longer term. And so maybe next quarter, we'll be in a position to update that, but we're in a bit of a commercially sensitive time period right now. So I'd prefer to not answer that question right now other than to say the demand for that pipeline is robust.

Okay. Thanks everyone.

And we'll take our next question from Ben Pham with BMO.

Hi. Thanks. Good morning. I wanted to go back to Prince Rupert and it reevaluated the netbacks and shipping costs have gone up. I mean, you speak of your customers on this. What is your expectation in terms of where the propane netbacks or like what's the most attractive? Is it the PDH side of things producers are going to swap for popping that's perhaps transfer 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 in 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 US deliveries as well. And so that's been a market. The Sarnia market, in particular, it's been a historic good market for us over the long term. We see that continuing. We've seen rises in the pay pricing. We like where we're sitting today, and we like the balance that we have. So we look at all of our markets and the netbacks do move, but you've hinted or stated a couple of things, rising shipping costs and where we're at. So we evaluate the markets. We look at the cost to our facilities and accessing those markets. And at this point in time, I 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. So we look at it on a go-forward basis, but it is dynamic as the pricing does change.

And if you aren't planned to expand, I mean, you are not planning to expand with Prince Rupert in the near term. Is that facility is it like how important is it to the Pembina store? Do you need it?

Currently, we are shipping almost 20,000 barrels a day and accessing international markets, which we believe contributes both diversification and value for our customers and ourselves. In terms of need, we can transport those barrels, as they are loaded into railcars and shipped to the coast. We have the flexibility to move those barrels around North America as needed. We still appreciate the Prince Rupert Terminal and its current size, considering the market dynamics we are facing. I believe it will be a valuable asset for Pembina over the long term, and we are continuously evaluating how to access markets moving forward. We want to avoid overcapitalization and ensure that we expand at the right times to provide our customers with the best netback possible.

Okay. Great. And 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.

And we'll take our next question from Robert Kwan with RBC Capital Markets.

Great. Good morning. If I can come back to Conoco agreement, I know there's been a lot of questions I make sure I'm factoring it. But specifically, are there any take-or-pay components on the base volumes coming out of the area dedication?

Good morning, Robert.

Jaret, you described it as an area of 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 volume that would come out into the deal?

Yes, there would be, Robert.

And would they roughly approximate your '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.

That's great. If I could ask something more philosophical, you have several joint ventures, many of which were inherited, and you are entering into a new one, with you being the operator for most of them. As you aim to grow and diversify your business, while being mindful of the share count, do you find additional joint ventures to be attractive for 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 potential partners as it relates to that area. So specifically in the new ventures area, I would say that would be the area where joint ventures are intriguing to us.

And do you feel just philosophically, you get to a point where there are too many joint ventures, or are you comfortable, especially, just if the vast majority of them are operated and just the way you report proportionate type numbers if that mitigates a lot of that?

Well, philosophically, from my perspective, I think that there are a great way to leverage different skill sets to move forward. In terms of the number of joint ventures, I don't know if we 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. So 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 finish on Mitsue and Nipisi, just regarding the runoff. Are there any opportunities? Do you see the possibility of additional contracts being repurposed or extended into other areas? Also, are there any insights on how these projects have developed? There was significant excitement when they were established; does that connect to seeking longer-term contracts as you progress with other projects or achieving 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 are opportunities for that pipeline, and we're in some active discussions, but that's about all I can say on that right now.

Okay. And just a greater question of how you think about contracting other projects that you go forward? Just given how that's quite...

Well, I mean, if you recall on that, that was a 10-year contract. Of course, we'd always like longer, but it's a constant negotiation with our customers. So to the extent we were able to get longer contracts, I think that's something we would have pursued. I think from the perspective of that pipeline, there's going to be more to say on that in the coming months here.

Okay. That's great. Thanks 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. And how do you think about just the outlook for egress and really across the gamut of stuff? So crude liquids in the basin, natural gas, NGLs and then really in your own system, 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 add that. I mean, if I back up a step and think macroly, obviously, Line 3 expansion coming on was very helpful for the basin, but it sounds like that's filling up if not full already. So 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. So TMX is obviously a pretty important asset for the future of the basin. From a gas perspective, there's still multiple areas that have capacity as it relates specifically to Pembina. As we've been trying to highlight here, Alliance is very full, and we expect to be full for a period of time, getting 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, most of that moved out on unit trains, as you're well aware. We also have a new source coming online with IPL's PDH. But as I talked about earlier in our conference call, we are seeing some tightness in our frac capacity in the fourth. And then as it relates to the conventional pipeline system, there's tightness today. Obviously, Phase 7 comes on in a month here, Phase 9 comes on at the end of this year, and then Phase 8, we just re-sanctioned. So we're debottlenecking the parts of the system that are currently or 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. And then I guess as you start to think about 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. And I guess maybe the most expensive thing that you would do and maybe the biggest benefit would be on the frac side, is sort of a fair characterization?

It is fair. But with our existing footprint and the amount, historically, we've been able to invest in caverns and rail, the investment really is on the facility itself with a lot of the ancillary business already in place. So from our perspective, it's a very attractive expansion opportunity.

So 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.

We will now take our next question from Matthew Weekes with iA Capital Markets.

Good morning. Thank you for taking my question. Just a 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 is fixed, what the maturity profile is like or maybe interest rate swaps that you have on that that protect you against the rising interest rates?

Hey, Matthew, it's Cam. Yeah. So we've done a really programmatic approach clearly for some time to maintain a very high proportion of fixed-rate debt. So as we stand today, if you look at sort of the Pembina corporate debt profile, which is about $10.5 billion, 95% of that is fixed rate today. And the average tenor of that is in excess of 10 years. It's sort of closer to almost 15%. Actually. When you look at the debt that we roll up with the JVs, there's a little bit more floating rate debt there. We have managed to introduce some hedges into that portfolio. So rolling that up in totality of our total proportionate debt were to the tune of just under 90% fixed rate debt. So we've really got a lot of interest rate protection. When we look at sort of the refinancing risk, again, we've really tried to maintain a really stable ladder to our debt portfolio. So this year, we've got one term loan, a bilateral term loan, which comes due and we've got just around $500 million or so of bonds that come due in the second half of the year. And so 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. But really, the upcoming maturities are very manageable and in terms of refinancing. The last piece I'd comment is, obviously, we've got a considerable portion of hybrid capital in our structure between the prefs and the hybrids. And we've got a couple of resets coming towards the tail end of this year. And again, we'll be looking at the various alternatives to handle those. 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. And 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. Obviously, there's a number of products in the market to the tune of sustainability linked loans, sustainability-linked bonds. The loan piece is probably something that is the first step for us something we're spending some time on. And once we've got that tack down, I think we'll start looking at some of those other alternatives on the SLB framework or potentially even a green bond related to a specific project. So certainly something we're looking at. And as these opportunities in scale continue to mature, it's something we'll definitely look at the advantage of.

Okay. 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.

Hi, 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 liking namely from the oil sands? Perhaps you can clarify if there's any potential to work alongside the Pathways group, 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 try to summarize that. We are currently engaged with the government regarding the carbon sequestration process, starting with the industrial heartland. We've been selected to present sequestration opportunities for emissions from this area, and we are collaborating closely with TC Energy to define the project's scope. We're identifying potential partners and customers within the industrial heartland and focusing on our outreach and communications. We're also in ongoing discussions with the government of Alberta and awaiting more details on their procedures. They've introduced evaluation agreements that allow us to negotiate and assess our proposed sites for sequestration, ultimately leading to the necessary permits as we validate those locations. The government has recently concluded a second process where submissions were made for emissions outside the industrial heartland, which we also participated in. We're exploring partnerships and believe there is potential for collaboration within the industry and with various stakeholders, including indigenous communities and new technologies. The recently announced government tax credit has provided us with additional flexibility. However, we have not yet explored the capture side of things; our focus remains on sequestration, particularly around transmission and sequestration efforts. If that addresses everything else, Pat.

It does. Yeah, that's great color. Thank you. And 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 the end game for Alliance as a meaningful connection to LNG offtake longer term, 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.

Yes. I'll take the M&A part, Pat. I think from our perspective, producers are able to do that contractually right now and are doing it. So, I don't think we need to see any sort of acquisition to link those two things together. We're seeing it today happen, and we think it's going to continue to happen, especially as people are securing incremental LNG capacity out of the Gulf Coast and the long-term outlook for LNG. So 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. And then, just a last cleanup question here. I'm 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, there were many factors involved, so we're not going to go into specifics.

No, fair enough. I’ll leave it there. Thanks, guys.

Thanks, Pat.

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.

And once again, that does conclude today's conference. We thank you all for your participation. You may now disconnect.