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 piece 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 cogen will reduce overall operating costs and contribute to annual GHG reductions at the Empress NGL extraction facility through the utilization of cogeneration waste heat and the low emission power generated. And alongside our partners, we continue to advance 2 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…

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 expense and impairments and a higher unrealized gain on commodity-related derivatives. Second quarter earnings were negatively impacted by higher income tax expense 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 Nipisi and Mitsue pipeline systems due to contract expirations, combined with lower volumes on the Alberta Ethane Gathering system…

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 3 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 them debt, strengthening our balance sheet and positioning us well for the future. And 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 running a little bit of math, and I saw it -- the first half of the year EBITDA is repeated in the second half. You guys -- I think you might go over the top end of your new guide there. And so I was just wondering with the guidance raise, how much of that was predicated on, I guess, fee-based cash flow versus commodity cash flow? Or are there other headwinds in the second half of the year that we should be thinking about?

Jeremy, again, if you recall, typically, our marketing business, the 2 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 kind of Q2 and Q3 of last year and then a rapid appreciation in prices, whereas this year, propanes remains 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 their 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 -- the IPL facilities coming online. We are seeing -- the market is in relatively good balance. We're excited about increasing volumes of propane as more volumes build on the pipeline systems and then the mention of us looking at additional fractionation capacity, we think there's opportunity to export additional volumes. But the market is pretty balanced right now, but we are looking at 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 mean I think, obviously, the balance sheet capacity is strong, Jeremy. But our comment around the economic benefits of repaying debt at this time. I mean, I think we just look at where the fixed income markets have gone. And obviously, they've popped up here. And so in terms of being a strong free cash flow position, it does certainly make some sense to be repaying debt. In the interim -- in the short term here, obviously, with the view that as our growth program continues to take shape over the next couple of years that we'll be pulling on that at a later date. As for the share buybacks, obviously, I think I would characterize this as being on track to hit that $350 million for the first half of the year. Obviously, that was reliant on $150 million of proceeds coming back from the pulp from the NewCo transaction and using that in the second half of the year. We're obviously going to look to be opportunistic as we do that through the balance of the year, but we do feel very strong commitment to that $350 million.

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

Yes. Thanks for the question, Jeremy. I would agree with you, campus 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. And that ability to either buy back shares or pay down debt, and 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. Obviously, with the recent announcements with respect to the large swaths of land that we have dedicated to Pembina through transport and fractionation and some marketing services, as we've stated before and as I think everyone is aware, the overall fractionation complex in Edmonton is extremely full. So we will need about a 2-year lead time in order to meet our customer demand for that. So we are feverishly working. And as Scott said in his prelude there, we're really focusing on what incremental outside the frac lease boundary utilities do we need such as spec storage, front-end storage, incremental rail, connectivity, et cetera. So just really working through that. We expect to have line of sight into exactly what that looks like here by fourth quarter. And then subsequently, we would be looking to make a decision after that. But we do still have some work to do. So it's a little bit early right now. And with respect to the inflation, we obviously, like everyone else, have seen significant inflation. But with that said, over the last, I think, 14 weeks, steel prices have come down substantially. So waiting a little bit -- time is actually in your favor when sanctioning large projects right now. So we just continue to reevaluate and watch that and make sure we pull the trigger at the appropriate time.

That's helpful context. And maybe just as a broader, bigger picture follow-up, Pembina's always -- never constrained itself with the corporate capacity to look at opportunities that are opportunistic. Just maybe an update on what you're seeing in terms of additional M&A and how you balance that with all the opportunities organically that you have? Any thoughts on what you're seeing and what excites you right now on that front would be of interest?

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 maybe further understand, are the 3 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, it's -- first of all, those agreements take us a decent way down the path. You got to remember that we also have underlying frac contracts underneath that, that we're balancing the renewals of those, the timing of those, with the timing of the new contracts coming into consideration. So it's a bit dynamic, I would say. But assuming the fracs stay full with existing production, it has taken us a long way there. Secondly, as it relates to the agreements we have in place, obviously, I have to be careful with what I say because they're confidential. But we do get visibility into the drilling plans and the production profiles on those assets. And while they are not solely land dedications, they are land dedications with take-or-pay arrangements once projects get sanctioned. When we look at the producer track record of our customers, we have a high degree of confidence that those are going to turn into developments and, ergo, take-or-pay arrangements.

Right. Good color. And then as a follow-up, just on Cedar LNG, can you provide an update on that project? You have spent a little bit of capital there. But where are we in terms of commercial agreements? And how have those changed through, we call it, the last 6 months as well as the permitting side?

Rob, it's Stu. Yes, we've been progressing the Cedar project across the board. We're continuing to work our EPC, our pricing and our contractual arrangements with the EPC contracts. We've been working the regulatory process, filing all of the regulatory documents reaching out on consultation basis with all the communities, while at the same time progressing our commercial conversations. We have considerable interest in the Cedar project. It is a unique opportunity that has been secured by the Haisla Nation to -- through the pipeline being constructed by TC and the acceptance and value that the Haisla Nation see in an LNG project. The conversations are progressing commercially. There is as -- not surprising, LNG pricing today, there is a frenzy of LNG activity and people see diversification as a major success. And Canada brings substantial access to a stranded -- some stranded gas that can get to Asian markets quite cheaply. So conversations are progressing. We're moving at lightning speed in an LNG world and trying to progress those along as quickly as possible. But the conversations are very good.

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

Rob Catellier. I just wanted to follow up first on a couple of things just on the frac discussion. So 2 things there. Just curious what your appetite might be to take any capacity there on spec. I heard you mention the -- question whether it's for spec storage. So just curious about your appetite there. And given the reality of the environment we're in with respect to inflation, is there any opportunity to risk or on the cost side with potential customers there?

Rob, it's Jaret. I'll maybe take the first question. When I said spec storage, I meant -- like spec products, so product storage. Yes, on the back end of the -- on the frac there, sorry. And then with respect to the cost sharing with the customers, what we've actually seen is an appetite on the build side for people to do potential lump sum, so taking that risk premium on and taking that away from Pembina. So traditionally, we manage that. But we have seen the appetite for that on these types of assets. So that is definitely something we're looking at. And as I previously stated, obviously, we saw a significant increase in cost in a very, very rapid time period. We're also seeing that contract just as quickly. The time lines the delivery of equipment hasn't been as quick to come in. But as we're evaluating over the next few months, we expect to have a significantly better line of sight and mitigation strategy to anything incremental we would have seen maybe in Q1 of '22.

Okay. And then moving on to just the line pipeline in Aux Sable. I'm curious if you're at liberty to disclose how much capacity on line Aux Sable might have -- how much to make up of that 90% contracted in '22 and '23? And separately, how is that exposure being managed? For example, are you doing anything to hedge the Chicago-AECO differential?

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

Yes. I'm just curious as to -- it's got a high level on contracting currently, and I'm curious to know how much Aux Sable represents of that level of contractedness. And to the extent they do have exposure on Alliance? Is there anything being done to hedge the differential?

Rob, it’s Jaret. So currently, actable 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 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, more renewable power or even CCUS further down the road?

I can take that, Rob. So I'll break it into 3 buckets. So Veresen Midstream primarily is hydroelectric power. So a little bit of opportunity there, but limited opportunity due to the nature of the power that's powering those assets, so Pembina's wholly owned business. We have a lot of opportunities there to -- it won't be more CCUS because it's going to be more asset focused, reducing flaring, focusing on our emissions future emissions and gas consumption. 80% of our emissions are from the consumption of natural gas to power compression, et cetera, et cetera, burners and heat mediums. So really focusing on the efficiency around consumption of natural gas. That is one of our biggest levers. And that will be essentially the same focus as you move into the Energy Transfer Canada assets really focusing on natural gas consumption reduction, potentially some more cogens in certain areas where it makes sense, like we have at Empress in and Redwater previously. But those would be the real big ones, Rob, that we're looking at.

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 3 distinct elements of capture, transport and storage, which areas to you are the most appealing? I mean clearly, you have the Alberta Carbon Grid. But how do you think about just return profiles for those 3 buckets and then risk management on those 3 buckets?

Right now, as a corporation, we are looking at the capture aspect, as Jaret mentioned. I mean, that's -- there's ongoing work for our own emissions. And we continue to progress our own assessment of the capture capability of those assets. With the Alberta Carbon Grid, it is -- essentially, it is a gathering of emissions. It is a hub for those emissions and then transportation and sequestration from that. So we see that as something very along the lines of Pembina's capabilities. We gather product, we upgrade product and we transport and move that product. So we think it's right in line with our capabilities. We like where we're sitting with the Alberta Carbon Grid, the asset that we've worked with the Alberta government, and we're continuing to progress those opportunities. As far as the return of that, we're looking at our normal pipeline returns. We continue to have conversations with potential customers. We're continuing to bring forward our engineering cost estimates is what that's going to take and what is the price of carbon on a go-forward basis and where does it make sense. So I think we're in line right now. It's early days still for us and those conversations are ongoing. -- but there's nothing different, I would say, from Pembina's normal course businesses.

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 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. And it moves 4 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 4 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, maybe I'll start big picture on the projects, and I'll let Cam talk about the impacts on the base business. I think, as Jaret pointed out, inflation is volatile right now. And we're seeing it move all over the place. A lot of the capital projects we're seeing steel increases to the first half of the year. We've seen that come down dramatically. The 1 thing I'd say is we're probably more apt to push some of that risk off to the engineering firms, as Jared pointed out. For example, on Cedar and the FEED work we're doing there, we're looking at securing that or the majority of that under a lump sum turnkey arrangement, as well as some of the other projects we're looking at. So as it relates to some of the larger scale projects, I'd say we're more so looking at pushing that risk off to engineering firms than say to customers -- but as it relates to things like the pipe business, I think there, we're pretty comfortable. I think that's our core business. We do it very well. And so that's an area where I think Pembina will continue to warehouse that risk. Cam, do you want to talk about the base business?

Yes. On the base business, Rob, I mean, I think we've structured our business to have a fair amount of insulation from inflation. What I would say is that where we are seeing the most inflation is really a couple of points, obviously, on the labor side as everyone else is. And you can ask yourself whether that's just a function of coming out of the pandemic and catch up or whether it's more systemic and it's -- sometimes it's hard to differentiate between those 2. But we have seen a bit of inflation there more recently. And then the second piece would be on the commodity side more generally. And that goes to Jaret's earlier comment, certainly on the capital projects on the steel side. Although it has obviously moderated more recently. In the past couple of months, it's moderated quite significantly. But also clearly, on the power side, and that's been a big change this year. And obviously, commercially, much of that is protected for Pembina's account. So while there has been inflation, as you can see from the results, we've structured the business to insulate ourselves quite significantly.

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. And ultimately, I think it goes to -- I mean, if you look at where that balancing point has been throughout the year so far, it's kind of flipped to favor both ends of that spectrum at various points along the way. So we're obviously going to continue to pay close attention to it and make the decision that creates the most value based on the opportunities have us. But as the market stands today, we do see considerable value in retiring some debt in the short term and obviously positioning ourselves for strength in the future.

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?

Robert, Jaret. Customers -- we've been very active in executing extensions across our current frac complex. Obviously, the pricing is extremely high activity volumes are growing and customers are seeing that spare capacity is becoming very star. So yes, we have been successful in doing that.

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's a few different dynamics going on, on Alliance. So clearly, with where the spread was, we saw strong interruptible bids on short-term volume. That being said, as we've done -- as we've recontracted that pipeline, there's less space on the interruptible, but the space that we do have has been quite strong. I think we also highlighted in the second quarter that we typically just due to seasonality, have line pack sales. And historically, that's been relatively modest just due to the pricing. But if you look at where we would have acquired that line pack last year to where gas price is today, there was an uplift in Q2 from that that will unlikely to be reoccurring. And then lastly, we also have U.S. recourse rates that have stepped down next year. So there's a bunch of noise on Alliance, some positive, some negative.

And so is there kind of just a bit of a -- like let me put it this way. As you think about your guidance for the year and citing Alliance, is that largely due to what we've already seen in the first half? Or do you expect certain aspects to continue into the second half of the year end and possibly into 2023?

I think the aspects that we continue to see will be high-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.