Pembina Pipeline Corp Q2 FY2022 Earnings Call

Good day, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation 2022 Second Quarter Results Conference Call. Today's conference is being recorded. At this time, I'd like to turn the conference over to Cameron Goldade, Pembina Interim Chief Financial Officer. Please go ahead.

Thank you, Keith, and good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the second quarter of 2022. On the call today, we have 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; and Stu Taylor, Senior Vice President, Marketing and New Ventures and Corporate Development Officer. 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 Management's Discussion & Analysis, dated August 4, 2022, for the period ended June 30, 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. As detailed with our release yesterday, Pembina delivered another strong quarter with adjusted EBITDA of $849 million, which was a record for a second quarter. While we typically see a sequential lower contribution in the second quarter from Pembina's NGL marketing business, our results benefited from continued growth in volumes across many of Pembina's systems, higher NGL margins, and a strong contribution from the crude oil marketing business. As Cam will detail in a moment, with strong year-to-date results and a positive outlook for the rest of the year, we have raised our 2022 adjusted EBITDA guidance to $3.575 billion to $3.675 billion. Throughout the second quarter, we continued to progress our portfolio of growth projects, notably by bringing Phase 7 Peace pipeline expansion into service in June, ahead of schedule and $150 million under budget by reactivating the Phase 8 expansion. Likewise, construction on the Phase 9 expansion is ongoing, and we continue to look forward to bringing that project into service later this year. These expansions deliver a multitude of benefits, including full product segregation across the Peace system and creating additional egress capacity to enhance Pembina's customer service offering and accommodate future growth. We've also advanced the in-service date for our Empress cogeneration facility to Q3 of this year, one quarter earlier than previously expected. The cogeneration facility will reduce overall operating costs and contribute to annual greenhouse gas reductions at the Empress NGL extraction facility through the utilization of cogeneration waste heat and the low emission power generated. Together with our partners, we continue to advance two significant proposed developments, the Alberta Carbon Grid and Cedar LNG, both of which are exciting and transformative projects. On the Alberta Carbon Grid, Pembina and TC Energy progressed work on several fronts, including continued discussions with the Government of Alberta, surface and subsurface engineering and planning, and engagement with customers and stakeholders. On Cedar LNG, our project with the Haisla First Nation, front-end engineering design and commercialization work streams are both underway. Through ongoing commercial discussions, we have observed considerable interest in getting WCSB natural gas to international markets while at the same time diversifying to new supply sources. In addition to another strong financial quarter and continued progress on our major projects, several other positive developments occurred during the second quarter. First, all regulatory approvals have been received in respect of the joint venture transaction with KKR, and we are working to satisfy the remaining conditions to close, which is expected in August. These efforts include the sale of a 50% interest in the KAPS pipeline, which is consistent with our intentions when we announced the transaction and was part of the agreement with the Competition Bureau. Second, Pembina has executed the previously referenced long-term agreements with the third leading Northeast B.C. Montney producer. These agreements include the commitment of significant volumes from another multi-phase Northeast B.C. Montney development and allow terminalling to call for future firm transportation and fractionation services on a take-or-pay basis as the acreage is developed. Our agreement with Tourmaline, together with the previously announced service agreements with ConocoPhillips Canada and another unnamed customer, provides three leading Montney producers with certainty of transportation egress from this key area for their future development and access to the remainder of Pembina's integrated value chain, including fractionation and marketing services. As we have been saying for a while, Pembina has a very positive outlook for Northeast B.C. development and with existing infrastructure and our integrated service offering, we feel poised to benefit. As a result of long-term commitments under these agreements, we have announced recently, as well as through our ownership in Veresen Midstream, we expect to secure the transportation, fractionation, and marketing rights with a significant portion of forecasted future growth in the Northeast B.C. Montney. Capturing these incremental volumes will collectively support improved utilization of our existing assets as well as capital-efficient expansion projects into the future. As a specific example, Pembina is currently engineering and evaluating up to an incremental 55,000 barrels per day of propane plus fractionation capacity at Pembina's Redwater Complex. The Redwater complex allows for a capital-efficient expansion due to existing cavern storage, ownership of significant contiguous land holdings, and industry-leading rail and pipeline connectivity. Significant existing infrastructure provides Pembina the flexibility to resize the incremental fractionation capacity to meet recently announced customer commitments as well as incremental demand in a derisked, timely, and cost-effective manner. Third, the contracting of Alliance Pipeline continues to progress very well. During the second quarter of 2022, Alliance offered three open seasons to the market. The largest of the open seasons resulted in approximately 270 million cubic feet per day of incremental long-term firm service with a volume-weighted average term of 15 years commencing in November 2022. The other two open seasons were for short-term service. Recent open seasons have resulted in Alliance being contracted over 90% for the current and next gas year through November 2023. Finally, Pembina continues to advance the execution of its ESG strategy. In July, we established a $1 billion sustainability-linked revolving credit facility, aligning Pembina's finance strategy with its ESG priorities. The facility contains pricing adjustments that reduce our increased borrowing costs based on Pembina's performance relative to a greenhouse gas emissions intensity reduction performance target. Establishing this facility further highlights Pembina's ESG commitment and ongoing efforts to integrate ESG into our business and financing strategy. Additionally, we entered into a power purchase agreement for 105 megawatts of renewable energy and associated renewable attributes with a wholly owned subsidiary of Capstone Infrastructure Corporation. We view power purchase agreements as an efficient tool to support the development of renewable energy infrastructure, lower emissions, and support the transition to a lower carbon energy system. The PPA with Capstone also benefits Pembina by securing cost-competitive renewable energy and fixing the price for a portion of the power Pembina consumes. Further to Pembina's ESG strategy, Pembina continues to demonstrate its commitment to equity, diversity, and inclusion in the workplace. Over the past year, Pembina has made tremendous progress towards its goal, including expanding representation in executive leadership roles at both the Vice President and Senior Vice President levels and also on the board. The company is well positioned to deliver on its targets, and broader EDI initiatives are enabling Pembina to create a safe and inclusive workplace and attract and retain a broad and diverse talent pool at all levels of the organization. Given industry tailwinds, I am looking forward to continued strength and momentum into the back half of this year and beyond. I will now pass the call over to Cam to discuss in more detail the financial highlights for the second quarter.

Thanks, Scott. As Scott noted, Pembina reported quarterly adjusted EBITDA of $849 million, representing a $71 million or 9% increase over the same period in the prior year. Relative to the same period last year, second quarter results benefited from stronger marketing results due to higher margins on crude oil and NGL sales, a combination of higher volumes on the Peace Pipeline system and higher tolls largely due to inflation, as well as higher contributions from Aux Sable and Alliance. These positive factors were partially offset by a lower contribution from Ruby, due to Ruby Pipeline filing for bankruptcy protection on March 31, 2022, higher realized losses on commodity-related derivatives, lower contracted volumes on the Nipisi and Mitsue pipeline systems due to the expiration of contracts, and higher general and administrative costs, primarily due to higher long-term incentive costs driven by Pembina's relative share price performance. Pembina recorded earnings in the second quarter of $418 million, representing a $164 million or 65% increase relative to the same period in the prior year. In addition to the factors impacting adjusted EBITDA, earnings in the second quarter were positively impacted by lower other expenses and impairments and a higher unrealized gain on commodity-related derivatives. Second quarter earnings were negatively impacted by higher income tax expenses and higher net finance costs due to foreign exchange losses compared to gains in the second quarter of 2021. Total volumes of 3.34 million barrels of oil equivalent per day in the second quarter were down approximately 4% compared to the prior period of last year. A 6% decrease in pipeline volumes was largely driven by a Ruby Pipeline filing for bankruptcy protection and lower contracted volumes on the Nipisi and Mitsue pipeline systems due to contract expirations, combined with lower volumes on the Alberta Ethane Gathering system due to third-party outages. These factors were partially offset by higher volumes on the Peace Pipeline system, Vantage Pipeline, Drayton Valley Pipeline, and Cochin Pipeline. A 1% decrease in facility volumes was largely due to lower volumes at the Saturn complex as a result of scheduled maintenance, partially offset by higher contracted volumes at the Cutbank Complex. It is worth noting that excluding the volume impact of contract expirations on the Nipisi and Mitsue pipeline systems, as well as the Ruby pipeline entering bankruptcy protection, second quarter volumes would have increased approximately 1% over the same period in the prior year. As Scott noted, based on the strong year-to-date results and the outlook for the remainder of the year, Pembina has raised the 2022 adjusted EBITDA guidance range to $3.575 billion to $3.675 billion. Relative to the previous guidance, the revised outlook for 2022 primarily reflects stronger marketing results, higher contributions from the Alliance and Cochin pipelines, as well as certain assets in the Gas Services business and the anticipated closing of the NewCo transaction later this month. Year-to-date, Pembina has generated cash flow from operating activities of nearly $1.3 billion, which has been used to fund dividend payments and the capital program with the excess used to repurchase common shares and reduce debt, thereby strengthening the company's leverage metrics. Since late 2021, Pembina has repurchased 2.7 million common shares at a total cost of approximately $122 million. Pembina remains committed to common share repurchases up to $350 million, subject to the closing of the NewCo transaction. Additional excess cash flow in the year, if any, is expected to be used to reduce debt and position the company for the future. I'll now turn things back to Scott for closing remarks.

Thanks, Cam. As I reflect at the midpoint of the year, I am pleased with our results and our prospects. With stronger-than-expected performance, we've been able to raise guidance twice. We expect to close our NewCo transaction this month, and through the combination of three complementary platforms, create a premier, highly competitive Western Canadian gas processing entity. We continue to advance our multibillion-dollar portfolio of projects, including Cedar LNG and Alberta Carbon Grid. We've allocated capital both to common share repurchases and paid down debt, strengthening our balance sheet and positioning us well for the future. We are executing on our ESG strategy and making progress towards the targets we set last year. More broadly, in our view, the potential opportunities within the Western Canadian Sedimentary Basin remain underappreciated. Pembina continues to observe steady volume growth on key systems, and a positive outlook for additional future growth is being informed by a number of factors, including the sound financial position of Pembina's customers, price strength across all commodities in Pembina's value chain, the quality of the WCSB formations, such as the Montney and the Duvernay, the development of LNG facilities on Western Canada's West Coast, the expansion of the Trans Mountain pipeline, and potential growth and diversification within Alberta's petrochemical sector. Overall, Pembina's outlook for meaningful medium-term volume growth in the WCSB remains unaltered and is being supported by customer commitments and contracting success and is materializing in prospective future growth projects. Thank you for joining us this morning and for your continued support. Please go ahead and open up the line for questions.

We'll take our first question from Jeremy Tonet with JP Morgan.

Scott, I was analyzing the numbers, and I noticed that the EBITDA from the first half of the year seems to be repeated in the second half. I think you might exceed the upper limit of your new guidance. With the guidance increase, I was curious about how much of that is based on fee-based cash flow compared to commodity cash flow. Are there any other challenges in the second half of the year that we should be aware of?

Jeremy, again, if you recall, typically, our marketing business, the two largest quarters historically have been Q1 and Q4. We obviously had a very strong Q1 this year. If you look at the pricing on the forward curve, it does continue to remain backwardated, which helps inform our view as we set the guidance range. But also, Q1 of this year benefited obviously from adding inventory in Q2 and Q3 of last year and then a rapid appreciation in prices, whereas this year, propanes remain quite strong. So our inventory and our carrying cost of inventory is a lot higher than it was last year, which just means as you go into the winter, there's potentially less margin based on the curve we see. So I would suggest that we always get nervous when people annualize Q1 or even half point of the year because there is seasonality in the marketing business, which helps drive probably a lower outlook for marketing through the back half of the year. All that being said, we do see some of that offset by continuing volume increases across the system.

Jerry, it's Cam. I'll just add to that, that it's worth reminding everyone that the second half of the year. Typically, Q3 and early Q4 is when our integrity teams are the most active as well. And so we typically see some profiling higher costs through Q3 and early Q4. So that does contribute to some of the seasonality as well.

Got it. Maybe just picking up on the propane point there, I was wondering if you could provide updated thoughts on how you see the propane balance in the basin right now. Is there a need for more exports? Or do you think things are balanced? Or just kind of curious, I guess, where you see things heading at this point.

Jeremy, it's Stu. The propane market is currently in a relatively good balance with the IPL facilities coming online. We are excited about the increasing volumes of propane as more is added to the pipeline systems. Regarding our exploration of additional fractionation capacity, we believe there is an opportunity to export more volumes. Overall, while the market is well-balanced right now, we are looking at opportunities for incremental growth.

Got it. And just with capital allocation. I know you talked about higher interest costs, I guess, impacting how you think about deploying excess cash here. But as it relates specifically to the buyback portion up to $350 million, as you mentioned there, would timing of buybacks be more a function of balance sheet capacity or share price? Or how do you balance those factors?

Yes, I think our balance sheet capacity is strong. Our comments about repaying debt now are informed by the current state of the fixed income markets, which have increased recently. Given our robust free cash flow position, it makes sense to reduce our debt. In the short term, we plan to do this while maintaining flexibility as our growth program develops over the next couple of years, at which point we may take on more debt again. Regarding share buybacks, we are on track to reach the $350 million target for the first half of the year. This is dependent on receiving $150 million from the pulp transaction, which we plan to utilize in the second half of the year. We intend to be opportunistic with this throughout the year, as we are very committed to achieving that $350 million goal.

Got it. Just real quick, last one. Scott, the CFO process, just wondering if there's any updates you could provide us there on the timeline? It seems like the CFO functions are being performed very well right now, but just curious what you can say.

Yes. Thanks for the question, Jeremy. I would agree with you, Cam's doing an excellent job, which has allowed us to run a full and thorough process. I would say that we are in the ninth inning of that process, and we would look to update the market in, I'll call it, the next month or so.

We'll take our next question from Linda Ezergailis with TD Securities.

Just as a follow-up to Jeremy's question about share buybacks, and to build on that, can you provide some updated thoughts on your dividend policy and philosophies? I mean, the market is anticipating the increase after the NewCo transaction closes. But beyond that, how do you view future increases being matched? Would it be an annual or would it be, again, opportunistic related to big projects or accretive transactions? And how do you think about balancing payout ratio with retaining capital for growth investments?

Yes, Linda. So as we publicly stated, we will be increasing the dividend off the closing of the NewCo transaction. So expect an update on that in the next couple of weeks. As I look forward, really, we want to tie our dividend growth to a form of cash flow per share growth. So we would expect to resume normal course dividend increases. And then we always look at them in terms of closing of major acquisitions or closing of large greenfield opportunities coming into service. We've typically looked at a second dividend increase over time. But as we stand right now, I do think we aspire to getting back to normal course annual dividend increases. Obviously, those were paused in 2020 and 2021, just with the uncertainty around the pandemic. As far as our payout ratio is concerned, we're somewhere in the neighborhood of 55% to 60%. So we feel pretty good about the amount of capital we're retaining. That ability to either buy back shares or pay down debt, I think really positions us as some of that growth comes back into being more visible.

That's a helpful update. And then maybe if you could just help us with the timing of potential FID on some of your other larger projects. I guess, the frac that you're looking at, when do you expect to be in a position to make a decision on that? And can you give us some estimate of what magnitude of cost we're looking at in this inflationary environment and how the contractual attributes might differ versus any prior frac commitments and agreements you've had?

Linda, it's Jaret. With the recent announcements regarding the large areas of land we have allocated to Pembina for transport, fractionation, and some marketing services, as mentioned earlier and acknowledged by everyone, the overall fractionation complex in Edmonton is very full. Therefore, we will require about a two-year lead time to satisfy our customer demand. We are working diligently on this. As Scott mentioned earlier, we are concentrating on the additional utilities we need outside of the frac lease boundary, such as spec storage, front-end storage, and more rail connectivity. We expect to have a clearer picture of what that will entail by the fourth quarter, and we plan to make a decision afterward. However, there is still quite a bit of work to be done, so it’s a bit premature at this point. Regarding inflation, like everyone else, we have felt its effects significantly. That being said, over the past 14 weeks, steel prices have dropped considerably. Therefore, taking a bit more time is actually beneficial when sanctioning large projects currently. We will continue to reassess the situation to ensure we proceed at the right moment.

That's helpful context. As a broader follow-up, Pembina has always been open to considering various opportunities. Can you provide an update on what you're observing regarding additional mergers and acquisitions, and how you reconcile that with the organic opportunities available? I would be interested in your insights on what you are seeing and what currently excites you in that area.

Yes, Linda, I think our short-term priority here really is to close the existing acquisition, NewCo transaction. We expect to close out in the next couple of weeks. And there's a heavy lift once that gets closed. That's when the real work begins in terms of integration. And quite frankly, getting after all the commercial opportunities we see on that asset base that we just haven't been able to do due to obviously pre-close being under restrictions with the Competition Bureau. So I think we're pretty focused on that asset. We also have the KAPS disposition underway as well. So those are our focuses right now. Bigger picture at some point, we will return to look at opportunistic M&A. But in the current environment, we're focused on what's in front of us.

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

I wanted to circle back on the frac. Maybe to clarify and further understand, are the three agreements in Northeast B.C., the area of dedication there, how far does that get you to support the 55,000 barrel a day frac? And secondly, how are you thinking about area dedications versus firm volumes to backstop such an investment?

Yes, Rob, those agreements take us a decent way down the path. It's important to remember that we also have underlying frac contracts that we're balancing the renewals of with the timing of the new contracts. So it is a bit dynamic. Assuming the fracs stay full with existing production, it has taken us a long way there. Regarding the agreements we have in place, I have to be cautious with what I say because they're confidential. However, we do have visibility into the drilling plans and production profiles for those assets. While they are not solely land dedications, they include land dedications with take-or-pay arrangements once projects are sanctioned. Considering the producer track record of our customers, we have a high degree of confidence that these will turn into developments, and consequently, take-or-pay arrangements.

Rob, it's Stu. Yes, we've been making significant progress on the Cedar project across the board. We are continuing to focus on our EPC, pricing, and contractual arrangements with the EPC contracts. We have been navigating the regulatory process, submitting all necessary regulatory documents, and engaging with the communities on a consultation basis while also advancing our commercial discussions. There is strong interest in the Cedar project, which is a unique opportunity secured by the Haisla Nation through the pipeline being built by TC, as well as the acceptance and value that the Haisla Nation sees in an LNG project. The commercial conversations are advancing well. There is currently a lot of activity in the LNG market, and many view diversification as a significant achievement. Canada offers considerable access to stranded gas that can be delivered to Asian markets at competitive prices. Therefore, the discussions are moving forward rapidly in the LNG sector, and we are working to push these along as quickly as we can. Overall, the conversations are very promising.

We'll take our next question from Robert Catellier with CIBC Capital Markets.

I wanted to follow up on a couple of points regarding the frac discussion. I'm interested in your willingness to take on any capacity there on speculation. I heard you mention a question about whether it involves spec storage, so I am curious about your interest in that area. Additionally, considering the current inflationary pressures, is there a chance to share the risk on costs with potential customers?

Rob, it's Jaret. I'll take the first question. When I referred to spec storage, I meant product storage. Regarding cost sharing with customers, we've noticed an interest in lump sum agreements, which would transfer some risk from Pembina. Traditionally, we have managed that risk, but there is increasing interest in this approach for these assets. This is definitely something we are considering. As I mentioned earlier, we have observed a significant and rapid increase in costs, and we are also seeing contracts adjust quickly. However, equipment delivery timelines have not been as fast. As we evaluate over the next few months, we anticipate having a clearer strategy and mitigation plan for any incremental changes we might see compared to Q1 of '22.

Okay. Moving on to the Alliance pipeline in Aux Sable, I would like to know if you can share the capacity on line Aux Sable and how much of that 90% is contracted in 2022 and 2023. Additionally, how are you managing that exposure? For instance, are you taking any steps to hedge the Chicago-AECO differential?

Sorry, Rob, I'm not sure I understood the question on Alliance. Could you just clarify it?

I'm curious about the current high level of contracting and how much Aux Sable contributes to that level. Also, do they have any exposure on Alliance, and is there any strategy in place to hedge the differential?

Rob, it’s Jaret. So currently, Aux Sable does have some capacity. Talking into the new gas here, that all goes to essentially zero. That will be upstream customers taking that capacity.

Very minimal long-term exposure. But to the extent of our short-term exposure, we are hedging a portion of the AECO-Chicago differential at the level, not at the Pembina level.

Great. Got it. And so last question for me then is, I'm curious what the opportunity and the vision is for reducing emissions at NewCo once that's closed. For example, are there opportunities for more renewable power or even CCUS further down the road?

I can take that, Rob. I'll break it into three parts. Veresen Midstream primarily deals with hydroelectric power, offering some opportunities, but they are limited because of the nature of the power used to operate those assets. Pembina's wholly owned business has many opportunities that won't focus on carbon capture, utilization, and storage, but rather on asset efficiency, reducing flaring, and addressing future emissions and gas consumption. Eighty percent of our emissions come from using natural gas for compression and other heating applications. Therefore, we are concentrating on improving the efficiency of natural gas consumption, which is one of our biggest strategies. This focus will also apply to the Energy Transfer Canada assets, with an emphasis on reducing natural gas consumption and possibly adding more cogeneration in specific areas, similar to what we have done at Empress and Redwater in the past. These are the main initiatives we are prioritizing, Rob.

We'll take our next question from Andrew Kuske, Credit Suisse.

Maybe a big picture question. You touched upon some of the LNG dynamics and inherently longer term, but there's some stuff happening in the front end. When you look across your platform and your footprint, do you see an opportunity on a longer-term basis to have maybe a smaller-scale Redwater look like on the B.C. side?

We have looked at that previously, Andrew. We've essentially shelved that opportunity. And the real reason for that is due to the connectivity. A frac by itself, if you had the same rail connectivity to get barrels to the West Coast, does make a lot of sense. But the inability due to just the quality of the rail infrastructure in Northeast B.C., for example, and getting a unit train out of there, it's just actually impossible. But I guess nothing is impossible with the right amount of capital, but it’s economically not feasible. It does make economic more sense to bring that into the Edmonton market and rail it out there in a unit train capacity. So we pretty much all shelved that opportunity.

Okay, great. Appreciate that. And then maybe just sort of building upon the economic opportunities and the compounding of your asset base. When you think about just CCUS and sort of the three distinct elements of capture, transport, and storage, which areas do you see as the most appealing? I mean clearly, you have the Alberta Carbon Grid. But how do you think about just return profiles for those three buckets and then risk management on those three buckets?

Currently, as a company, we are focusing on the capture aspect, as Jaret pointed out. There is ongoing work regarding our own emissions, and we are advancing our assessment of the capture capabilities of those assets. The Alberta Carbon Grid is essentially a collection point for emissions, functioning as a hub for their transportation and sequestration. We view this as closely aligned with Pembina's capabilities, as we gather, upgrade, and transport products. We believe it fits well with what we do. We are pleased with our position in relation to the Alberta Carbon Grid, which we are developing in collaboration with the Alberta government, and we are continuing to explore these opportunities. Regarding returns, we are looking at our typical pipeline returns and are in discussions with potential customers. We are also preparing our engineering cost estimates to understand what will be needed and the future price of carbon to determine where it makes sense. I believe we are currently aligned, although it is still early in the process, and those discussions are ongoing. There is nothing particularly different from Pembina's usual business activities.

We'll take our next question from Matthew Weekes with IA Capital Markets.

Just looking at the contracts that you've signed with producers in Northeast B.C. I'm just wondering if you think to account for those volume commitments and then looking at your asset footprint, are you able to provide an idea of where you are in terms of utilization at this point? And how much more room you have to sort of just expand volumes without really deploying too much capital to incremental capacity.

Right now, the Peace system, obviously, with Phase 7 coming into service in condensate service that allowed us to repurpose some different pipes to give us incremental NGL service. Phase 9 is being executed as we speak, and Phase 8 has been sanctioned. So where I'm going with all that, once that is essentially built out, on average across the system, you have to recall that we have a system that goes all the way from Northeast B.C. into Edmonton. So hundreds of kilometers long. It moves four different products, C2+, C3+, crude, and condensate. With all that said, currently, we're around 72% utilized across that system. So we do have significant running room to accommodate future volumes across those four products into the Edmonton market.

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

If I can just start at a higher level, you had some commentary just around inflation and the impact it may have, I guess, maybe some cautious statements around future projects. I'm just wondering though, as you go forward, typically, you haven't had capital cost protection. Is that something that you would consider? And as you talk with your customers, just given that hasn't generally been the norm for your types of infrastructure? Is that something they're amenable to?

Yes. Rob, I'll begin with an overview of the projects, and then I'll hand it over to Cam to discuss the impacts on the base business. As Jaret mentioned, inflation is currently unpredictable and fluctuating significantly. We're observing rising steel costs in the first half of the year, but those prices have decreased considerably. One thing I want to highlight is that we're likely to transfer some of that risk to the engineering firms, as Jaret indicated. For instance, with the Cedar and the FEED work we're undertaking there, we aim to secure most of that through a lump sum turnkey agreement, along with some other projects we're considering. Regarding larger scale projects, I would say that our focus is on shifting risk to engineering firms rather than to customers. However, in terms of our pipe business, we feel confident since that is our core competency. We excel in that area, and Pembina is prepared to manage that risk. Cam, would you like to discuss the base business?

Yes. Regarding our core operations, I believe we have organized our business to be relatively protected from inflation. The primary areas of inflation we're experiencing are in labor costs, which is a common challenge for many right now. It's difficult to determine whether this is simply a rebound effect from the pandemic or if it represents a more lasting trend. We have noticed some inflation in that area recently. The second factor involves commodities, which relates to Jaret's earlier remarks about our capital projects, particularly in steel. Although there has been a recent moderation in those costs, they have decreased significantly over the last couple of months. Additionally, we have seen notable changes in power costs this year. Fortunately, much of this inflation is covered in our agreements, so despite the rising costs, our results demonstrate that we have effectively structured our business to provide substantial insulation against these challenges.

That's great. And if I just kind of think about the more cautious statements here and tie it back to capital allocation, I just want to be clear on something you said earlier. While you're committed to the buyback, it sounds like at this point, instead of scaling the buyback higher, you're seeing a lot more optionality in basically warehousing that capital on the balance sheet, reducing leverage, whether that's temporarily or permanently. Is that fair?

I think that's a fair comment, Rob. Ultimately, if you look at where that balancing point has been throughout the year, it has shifted to favor both ends of that spectrum at different times. We will definitely continue to pay close attention to it and make decisions that create the most value based on the opportunities available. However, as the market currently stands, we see significant value in retiring some debt in the short term and positioning ourselves for future strength.

If I can just finish with a couple of follow-ups from earlier questions. On RFS IV, Scott, you mentioned, obviously, what you want to contract for but importantly, you need to secure what's there? Is there an update as to where you are in terms of getting all the contracts you need and extending term? Are customers amenable to extending term for what's I through III?

Customers have been actively involved in executing extensions across our current frac complex. Pricing is very high, activity volumes are increasing, and customers are finding that spare capacity is becoming quite limited. Therefore, we have been successful in these efforts.

And when you say success, like what percentage of the capacity is where you need to start looking at IV?

I don't have that off the top of my head, Robert, but we could have a follow-up.

Okay. That's great. And then just for Alliance, and the results that we're seeing this quarter, a very strong kind of proportionate EBITDA. How does that compare to, as you look forward, factoring in the new contracts and whatever those rates would be. But as well, how much of this quarter came about from any of the interruptible volumes or any other kind of volumes that would have been subject to bids that may have been inflated due to basis?

Yes, I think there are several factors at play regarding Alliance. With the current spread, we experienced strong interruptible bids for short-term volume. However, as we have recontracted the pipeline, there is less availability for interruptible space, although the space we do have remains quite strong. In the second quarter, we mentioned that we typically see line pack sales due to seasonality, which have historically been modest because of pricing. But looking at last year's line pack acquisition compared to current gas prices, there was an increase in Q2 that is unlikely to happen again. Additionally, U.S. recourse rates are expected to decline next year. Therefore, there is a mix of influences on Alliance, some favorable and some unfavorable.

As you consider your guidance for the year and reference Alliance, is the outlook primarily based on what we've observed in the first half, or do you anticipate certain trends to persist into the second half of the year and possibly into 2023?

I think the aspects that we continue to see will be high utilization. Going into the year, we weren't fully utilized, whereas now we're basically full on that pipeline. And we are seeing a stronger differential through the back half of the year, which should lead to continued strength in any of the short-term kind of daily, monthly contracting efforts there.

Ladies and gentlemen, this concludes today's question-and-answer session. At this time, I'd like to turn the conference back to Scott Burrows for any additional or closing remarks.

Just a few closing remarks. Just wanted to thank everyone for their time today and your questions. We’re really excited about what we’ve achieved in the first half of the year and are equally excited as we move through the back half of the year. So I hope everyone has a safe and healthy summer, and we’ll chat soon.

Ladies and gentlemen, this concludes today's conference. We appreciate your participation. You may now disconnect.