Good morning, ladies and gentlemen, and welcome to the Pembina Pipeline Corporation Q1 2023 results. At this time, all lines are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you need assistance, please press star zero for the operator. This call is being recorded on Friday, May 5th, 2023. I would now like to turn the conference over to Cameron Goldade, Chief Financial Officer. Please go ahead.
Thank you, Joanna. Good morning, everyone. Welcome to Pembina's conference call and webcast to review highlights from the Q1 of 2023. On the call today, we have Scott Burrows, President and Chief Executive Officer, along with other members of Pembina's senior officer team, including Jaret Sprott, Janet Loduca, Stu Taylor, and Chris Scherman. 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 and analysis dated May fourth, 2023, for the period ended March 31st, 2023, as well as the press release Pembina issued yesterday, which are available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Scott to make some opening remarks.
Thanks, Cam. The Q1 , Pembina reported earnings of CAD 369 million and adjusted EBITDA of CAD 947 million, which reflects continued strength in the Western Canadian Sedimentary Basin, growing demand for services from customers, and another strong contribution from our marketing business. Overall, we maintained Q1 volumes across the conventional pipelines consistent with the same period in the prior year, and we were happy to see volume growth from rising industry activity sufficiently offset the impact of the previously disclosed Northern Pipeline system outage. We resumed partial service of the Northern system on February 23rd and look forward to the resumption of full service sometime in the latter half of the Q2. With that, seeing our full impact of growing producer activity reflected in Pembina's results for the rest of the year.
As we highlighted with our release yesterday, there's been exciting progress on a number of fronts. First, Cedar LNG recently received its environmental assessment certificate from the BC Environmental Assessment Office and a positive decision statement from the Federal Minister of Environment and Climate Change, which collectively represent a significant step forward for the project. In addition, we signed a memorandum of understanding with ARC Resources for a long-term liquefaction services agreement for half the capacity of Cedar LNG. Work towards signing of definitive commercial agreements is ongoing. Cedar LNG is expected to be structured as a tolling business, providing a low risk, long-term cash flow stream, further strengthening Pembina's financial resilience. We continue to expect activities related to our four work streams, engineering, regulatory, commercial, and financing to converge for a final investment decision to be made in the end of the Q3 of 2023.
Second, we have continued to achieve many commercial successes, securing and strengthening the contractual underpinning of our business. Strong liquid prices and financially well-positioned and capable producers are leading to current growth in the basin. Longer term, we see the industry readying itself to capitalize on West Coast LNG development, the Trans Mountain pipeline expansion, and growth in Alberta's petrochemical industry. We maintain our positive outlook for growth in the WCSB and in the Northeast BC Montney in particular, where certain large producers continue to signal the potential for significant visible multi-year growth. We previously disclosed the long-term midstream service agreement signed in 2022 with three premier Northeast BC Montney producers for transportation and fractionation services.
Based on the company's public disclosure, this could represent in excess of 120,000 barrels per day of incremental NGLs and condensate by 2030, for which Pembina has contractual rights to substantially all. In addition, we have recently secured additional long-term production and facility dedications and executed new pipeline transportation contracts with existing customers for approximately 65,000 barrels per day of incremental volume across the Peace Pipeline system. Customers continue to demonstrate the value they place on the Peace system, the backbone of Pembina's integrated value chain. Given its many advantages, including its extensive reach, capacity of 1.1 million barrels per day, product segregation across four commodities, high reliability, low operating cost, and multiple delivery points, service on the Peace Pipeline continues to be in high demand.
Third, the sale of Pembina Gas Infrastructure's interest in the Key Access Pipeline System was completed on April 26th. Proceeds from the sale were used to reduce debt at Pembina Gas Infrastructure. Fourth, the Phase VIII Peace Pipeline Expansion continues to progress well. Height manufacturing is complete and construction progressed at several locations in the Q1 of 2023. The project has an estimated cost of approximately CAD 530 million and is now trending under budget. We expect Phase VIII to enter service in the H1 of 2024, with three pump stations expected to enter service in 2023. This continues our track record of pipeline construction being a core competency at Pembina.
Finally, I am pleased to say that we have raised our quarterly common share dividend by CAD 0.015 per share or 2.3%, beginning with the dividend to be paid in June. Inclusive of the increase declared last September associated with the closing of PGI transaction, our dividend is approximately 6% higher year-over-year, reflecting both the impact of our strategy and our financial resilience. I will now turn things over to Cam to discuss in more detail the financial highlights of our Q1 of 2023.
Thanks, Scott. As Scott noted, Pembina reported Q1 adjusted EBITDA of CAD 947 million, which represents a CAD 58 million or 6% decrease over the same period in the prior year. The combined impact across pipelines and facilities from the Northern Pipeline system outage was approximately CAD 54 million in the Q1. The other major variance quarter-over-quarter was in the marketing and new venture segment, where adjusted EBITDA declined by CAD 98 million compared to the prior period. In the Q1 of last year, marketing and new ventures adjusted EBITDA saw record quarterly results due to sharp increases in commodity prices. Compared with the prior period, marketing and new ventures results this quarter reflected lower NGL margins as a result of lower propane and butane prices and lower margins on crude oil resulting from the lower prices across the crude oil complex.
Realized gains on commodity-related derivatives for the quarter compared to losses recognized during the Q1 of 2022, and a lower contribution from Oxbow as a result of lower NGL prices and recontracting in the Q4 of 2022. In addition to the aforementioned drivers, Q1 adjusted EBITDA was impacted by the net effect of higher crude and condensate volumes and higher recoverable project costs on the Peace Pipeline system, higher revenues from Cochin Pipeline, Vantage Pipeline, and AEGS, lower adjusted EBITDA contribution from Ruby Pipeline, lower revenue related to recoverable costs on the Horizon Pipeline system in the Q1 of 2022, the PGI transaction and stronger performance from certain gas processing assets, including the former ETC plants and the Dawson assets, and lower corporate, general and administrative expense, primarily due to lower long-term incentive costs, partially offset by higher information technology related maintenance costs.
Earnings in the Q1 were CAD 369 million, representing CAD 112 million or 23% decrease over the same period in the prior year. In addition to the factors impacting adjusted EBITDA, excluding the lower contribution from Ruby, earnings were impacted by lower unrealized gains on commodity-related derivatives. Positive impacts captured in adjusted EBITDA from PGI, offset by interest expense, income tax expense, and depreciation resulting from the PGI assets recorded at fair value, which are all included in the share of profits from PGI. Additionally, lower acquisition fees and lower income tax expense. Total volumes of 3.188 million BOE per day for the Q1 represent a decrease of approximately 5% over the same period in the prior year.
Volume decreases were attributable to both the pipelines and facilities divisions, including, most notably, the net impact of the Northern Pipeline system outage, the Ruby Pipeline, the previously announced disposition of the Empress I and Empress VI assets. Higher crude and condensate volumes on the Peace Pipeline system resulting from increased upstream activity. Higher volumes at the former ETC plants and at the Dawson assets, and higher volumes at AEGS and on the Vantage Pipeline due to third-party outages in the Q1 of 2022. If we adjust for the impact of the dispositions and the Northern Pipeline outage, volumes in the quarter would have grown by approximately 2% over the Q1 of 2022.
Based on the Q1 results and the outlook for the remainder of the year, our 2023 adjusted EBITDA guidance range of CAD 3.5 -CAD 3.8 billion remains unchanged and includes the impact of the Northern Pipeline system outage and positive effects of widening frac spreads due to lower natural gas prices. Based on the 2023 guidance, cash flow from operating activities is expected to exceed dividends and capital expenditures. We continue to plan for excess free cash flow in 2023 to be used to pay down debt, further strengthening the balance sheet and preparing the company to fund future capital projects.
At May 31st, 2023, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.6x or 3.5x after adjusting for the closing of the sale of PGI's interest in KAPS, which occurred subsequent to the quarter. Pembina expects to exit the year with a ratio of 3.3x-3.6x, supporting a strong BBB credit rating. I'll now turn things back to Scott for some closing remarks.
Thanks, Cam. Coming off a record year in 2022, I'm very pleased with the strong start to the Q1. I remain extremely optimistic about the state of our business and our ability to capitalize on growth in the WCSB while pursuing transformational projects such as Cedar LNG. I want to remind you that Pembina will hold its annual meeting of common shareholders today at 2:00 A.M. Mountain Time, 4:00 P.M. Eastern Time. 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, please visit the shareholder information page under the Investor Center tab at pembina.com. We would once again like to thank all of our stakeholders for their support.
Before we get to questions, I wanted to take a moment to address the wildfires in Alberta. Last night, Brazeau County Council declared a state of local emergency and an evacuation order has been issued for the town of Drayton Valley, where one of our field offices is located. This is a very difficult time for all the people in the area, including our employees, contractors, and customers. Our focus is on the safety of everyone involved. Pembina activated our emergency response and incident management processes, and we are working to ensure all our staff and families are safe and receive the support they need. Please stay safe, everyone. With that, please go ahead and open the line up for questions.
Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press the star followed by the one on your touch tone phone. You will hear a three-tone prompt acknowledging your request. If you would like to withdraw your request, please press star followed by two. If you are using a speakerphone, please lift the handset before pressing any keys. First question comes from Jeremy Tonet at JP Morgan. Please go ahead.
Hi, good morning.
Morning, Jeremy.
Just wanted to start off with the conventional pipe outlook, if I could. If I recall correctly, last quarter, I believe commentary might have suggested 3%-5% growth. In the release last night, I think there was a reference to 4%-6% growth. Just wondering if we're seeing kind of a little bit of incremental growth in the basin for you guys relative to where you were before, or any color on that would be helpful.
Yeah. I think you're right, Jeremy. I think there's obviously a strong start to the year and volumes came in higher than we were initially anticipating. You know, we're still pretty optimistic about volume growth through the back half of the year. Like I said, signaling that kind of 4%- 6% volume growth.
That's helpful there. Thanks. Just pivoting to the guidance, you know, the Northern system having more of an impact in the Q1 than expected and lingering in the Q2 here represent the headwind, but guidance being reaffirmed. Just wondering if you see offsets, if it's in the marketing business or pipes and facilities. Just wondering how you see kind of these gives and takes and whether you see kind of a bias within the guidance range towards the high end or the low end at this point in time.
Hey, Jeremy, I'll take that. Yeah. I think you're right. I mean, two probably tailwinds offsetting, you know, obviously the impact of the Northern headwind. You hit on the first one already. It would be in the marketing segment, obviously with, you know, with natural gas prices having softened here as we've moved out of Q4 into Q1 and beyond. You know, I think they've essentially halved from where they were, you know, sort of the middle of Q4 last year. That obviously in the short term is a tailwind for our marketing business and is contributing to making up a substantial amount and then some of the impact of the Northern outage.
As we referenced in the release and Scott was just speaking to, I mean, obviously we are seeing strong volumes on the conventional side as well. You know, particularly the crude and condensate side continues to show strength, and that's helping make it up. The rest of the business, you know, sort of chugging along. Actually, obviously, as we said before, you know, many of our assets are running, you know, at very high utilization s o we're working to, you know, to be able to find millions and tens of millions of dollars out of increasing utilization and increasing service where possible.
Yeah. Jeremy, I think at the highest level, we're seeing a lot of tailwinds on the infrastructure side of the business. I think the headwinds really is on the NGL side. I mean, propane's gone from CAD 0.80- CAD 0.65 in the matter of a week to a week and a half. You know, pick your day and pick your forecast, but right now we're pretty comfortable with the guidance range.
That's very helpful. Just one last one, if I could, as it relates to Cedar on the LNG side. Is it fair to say there's not really any meaningful hurdles left to a positive FID at this point, kind of crossing I's, crossing T's and dotting I's. Just as you think about construction here, the, you know, the modular build seems like it would kind of de-risk construction and inflationary concerns that we've seen elsewhere. Is that still a fair way to think about things or any other updates you wanna share there?
Yeah, I'll jump in and Stu can round it out. I would say there's still some pretty big hurdles to get over. You know, we only have half of the capacity under MOU, but we're feeling pretty confident in our ability to fill the facility now. You know, until we have agreements signed, obviously we don't have that, but we're feeling pretty optimistic about that. As it relates to the engineering, you know, the teams are still working through all that, and we don't have a final cost estimate yet. We expect that in the next couple months here s o we'll see how that comes in. Obviously, capital cost is a large driver of the project.
To round out your question, you know, there is about 80% of the cost that we expect to be under some form of a lump sum agreement, which really would protect Pembina from a capital cost perspective.
Jeremy, Stu. Yeah, I mean, we continue to progress, you know, our four major work streams of regulatory, commercial, engineering, and finance. You know, good progress has been made across the board. You know, a lot of work still to undertake and push to get to the finish line here. You know, we've made good progress on the regulatory side. We've made good progress on the commercial side with the first MOU and are working hard on another and others to follow. You're right. The plan is to have this built in a shipyard in Asia.
We're working with the EPC contractors and those shipyards to finalize that and come forward in, you know, middle of the year here, we should have some insight and clarity on where that will be and what that cost estimate should end up. As Scott said, it'll be a lump sum contract for 80%+ of our capital costs.
That's very helpful. I'll leave it there. Thank you.
Thank you. The next question comes from Linda Ezergailis at TD Securities. Please go ahead.
Thank you. Just following up on Cedar LNG, is there a reason why you're targeting FID by the end of the Q3, such as are there any sort of expiring supply or component procurement agreements or commercial discussions that dictate that timing? Or is it okay if the FID slips into Q four or next year? Can you please indicate the minimum level of capacity that needs to be firmly contracted at FID?
Linda, it's Stu again. You know, we always had it as the Q3 of 2023. You know, as I've mentioned already, we have four work streams trying to coordinate all four to some time. You know, as we sit here and look, and making some progress and, you know, we did kick off an additional FEED study to be done, and the timing of that pushed it a little bit further back. It's just coordinating all of that work stream, trying to align on a date. You know, we're currently sitting with, you know, working hard to have that FID by the end of the Q3, as mentioned in the press release.
You know, it could possibly slip. At this point in time, everything is full speed and targeting the end of September for that. As far as the contracting, you know, we've gone forward. You know, we're looking to contract 100% of the capacity at this point in time. You know, we will make some call in the future as to, you know, what level. We're pretty confident on the MoE work that we're going through in the definitive progress that we've already made that we'll be able to contract 100%. We haven't contemplated or sat back and looked yet at, you know, a minimum number. Right now everything is pushing to contract the entire capacity.
Okay. Thank you. Just as a follow-up, in terms of your discussions with producers in the region, can you talk about how your discussions are going in terms of the services that they're looking to add, when it is new services, are they trending any way based on choosing full path versus discrete services? Any other attributes in terms of the duration that they're preferring longer versus shorter, and conviction they have on firming things up would be helpful.
Good morning, Linda. It's Jaret. It kind of broke out there, but I think the question was with respect to the producers. I'll start. Right now, I think what we're hearing from our producers is obviously that gas egress is becoming the largest constraint here in Western Canada. We're hearing a lot, you know, we're obviously seeing the well performance continues, and I know I say this every quarter, but the well performance continues to excite Pembina and obviously our customers highly. There's resolution in Northeast BC and I think with some of the recent public announcements, you can see that some of the customers are getting a little bit more bullish on their short term.
When I mean short term, like two to three year development plans, which obviously is also very exciting to Pembina. With respect to your question on services that the customers, I think you've seen that some of our customers choose to build their own gas plants. Some of our customers choose to utilize PGI for that service. Obviously, the Peace Pipeline is instrumental to, you know, a large portion of the customers in Western Canada getting their products safely and reliably into the Edmonton market. Obviously with the addition of RFS IV, there's high demand for existing one, two, and three frac services, but also incremental. You know, that's even, you know, that wide space in RFS IV is closing very quickly
It honestly depends with respect to your question on term and tenure of what people are looking for. It really depends on the customer. I think we recently announced that the 65,000 barrels on Peace, that averaged about six years. You can see some customers are a little bit shorter and some customers like that certainty for, you know, longer term, long range plans of, you know, north of seven to.10 years.
Thank you. Just as a short term-
There was a few questions there. Did I get them all?
Sure. I think I lost track of my questions as well. Maybe more in the short term. Will any of your facilities, potentially, directly or indirectly be affected by any sort of NGTL maintenance this summer?
The stuff definitely up in Northeast BC, some of our customers in and around the Dawson Creek area, they do see restrictions. You know, but they're pretty savvy and, you know, they also have, many of our customers have Alliance capacity, so they're pretty savvy in capturing it, moving volumes from receipt points, moving volumes onto, their firm contracts on Alliance, et cetera. You know, we did see some noise in Q1, but, you know, the over-performance of the assets kind of muted the noise of the Northern outage and any announced maintenance.
Great. Thank you.
Thank you. Next question comes from Robert Hope at Scotiabank. Please go ahead.
Morning, everyone. Questions on capital allocation. You know, you reiterated kind of the view that 2023 cash flow, you know, would be quite strong and CapEx, you know, would be much less than that. Just in terms of the dividend with the increase there to preserve that financial flexibility, can you maybe add some color on, you know, the future growth plans that you see out there, I guess, beyond Cedar that, you know, could give you some near term, you know, capital expenditures to eat into your financial capacity?
Yeah, Rob, I think, you know, we continue, you know, as we outlaid kind of some of the volume growth that we're seeing across the basin, we think that there continues to be opportunities to invest in our core business, whether it's incremental laterals or pump stations across the system to capture the growing volumes. In addition to that, we obviously have a suite of opportunities we're working on in our new ventures group, such as the Alberta Carbon Grid, and some of the other projects that we're not quite ready to talk about just yet. We are looking at all opportunities in the energy transition space, whether it's ammonia, hydrogen, methanol, and we're working really hard on those projects and seeing great progress on that front.
We expect as we move through this year, we're gonna round out a capital program in 2024, 2025 that's going to have an increased capital from where we are today. We're making sure that we're well-positioned from a financial point of view.
I appreciate that. Then just maybe turning over to your partnership to evaluate a TMX ownership stake. Can you maybe update us on your thoughts there, especially given kinda continued delays and expanded capital costs?
Yeah. Hey, Rob, it's Cam. I mean, I think, obviously we're very proud of our partnership that we have with WIPG and being selected as their operating partner, you know, in evaluating the opportunity to invest and own, that pipeline. I mean, I think we continue to believe that that asset, you know, from a standalone basis or standing back is a, is a world-class asset, obviously. You know, it's gonna have access to one of the most long-lived and probably high-valued crude markets, you know, for the next few decades here as we move through, as we move through this.
I think, obviously, you know, with the, with the increases that we've seen, I mean, obviously we have to justify for ourselves that, you know, the economic proposition around the pipeline, you know, remains really exciting and continue to do that work. You know, I think that, you know, obviously we can't buy something that's not for sale, right now. You know, we'll continue to evaluate and look at it over time. We think the asset is a great asset a nd obviously, just like any acquisition, it's got to be a good deal for Pembina, and obviously remain within our guardrails, which is something you've seen from us in the past and we remain squarely committed to.
You know, those continue to be the parameters as we evaluate, consider that opportunity just as we would any other, and we have no intention of straying from that.
Thank you.
Thank you. Next question comes from Patrick Kenny at National Bank Financial. Please go ahead.
Thank you. Good morning. Just on the Northern Pipeline incident, sorry if I missed it, but is the cause still under investigation or do you have clarity on what needs to be done to rectify the system? Just wondering if there could be, you know, a continued drag on cash flow beyond Q2 if there's more integrity work that needs to be done across the system, depending on the findings.
Morning, Pat. Jared here. Right now the investigation continues, but all indications are pointing to stress corrosion cracking. That is a result of a poor coating repair during construction that was done about 25 years ago. Right now, one of the cost increase from about $30 million that we put out last quarter to the $54 was us getting more integrity work done. You know, real great work from our surface land group and our integrity group to be able to go out and do that work quicker than we thought. We've done a substantial amount of integrity work on the pipeline to date, and all indications are showing us that we don't have a systemic problem on the asset.
This, this, you know, looking like it should be a one-off. With respect to your question on future integrity and drag on cash flow, right now what we're doing is obviously we'll have a little bit of incremental integrity work to do on other like assets, but it's not material in nature. What I would say is that we're reevaluating, just the, you know, we spend about I think around CAD 150 million-CAD 175 million a year on integrity, geotech, environmental work. We're just reevaluating our full suite of the 16,000 pipelines in our risk assessment on prioritization of that capital.
Okay. Thanks for that, Jaret. It's a bit of a rarity to see pipeline projects under budget these days. You could just, you know, walk us through some of the positive highlights of the Phase VIII Peace Pipeline Expansion that's, you know, helping to drive costs below budget there.
You bet. Great question. Pat, obviously, like, we have a fairly extensive knowledge of pipelining in Western Alberta and Northeast BC. I think, you know, our seasoned team, we know where the tough spots are. We know how to cross some of the really tough river crossings. We know what work needs to be done in what season. I think in partnering with, w e have great partnerships. We align ourselves on our values, our safety commitment, you know, and our partners are aligned with that. I think through our great contracting strategies, you know, the win-win with our partners, it's allowed us to continue to, you know, even outperform what our expectations are. That's, you know, I think it's just great experience, great track record, and knowledge.
Okay. Thank you. Last one for me, if I could, maybe for Cam. Just in terms of deciding whether or not to execute the NCIB, is the target leverage ratio still, you know, that 3.75-4.15 range? Would, you know, managing the buyback program be towards the midpoint of that range, or do you prefer to keep leverage below that long-term target range for now, or at least until interest rates start to come back down?
Yeah, you know, I think we recognize, Pat, that we are, you know, below that stated range. You know, obviously as Scott mentioned earlier, I mean, we have a number of exciting opportunities looking forward and, you know, obviously, as we've done in the past, I mean, we've always positioned our balance sheet, to be able to seize, you know, opportunities and be in a strong position to be able to weather cycles as they, you know, as they may occur or as opportunities may come. When we look at the decision to use cash flow towards reducing debt this year, you know, it is largely a function of seeing the opportunities come, you know, in the next two to three years here. A lso, you know, looking at the pure economics of it. you know, we sort of look at, you know, interest rates obviously and where our cost of debt is.
You know, we look at that relative to the alternative and, you know, right now, taking all that into account, you know, we think it makes sense to temporarily retire some debt, you know, with free cash flow and have that capacity available, you know, for opportunities in the future.
Okay, great. Thanks for that. I'll leave it there, guys.
Thank you. The next question comes from Robert Catellier from CIBC Capital. Please go ahead.
Yeah. I just wanna touch on Cedar LNG again. I'm wondering if how the recent economic weakness is influencing your risk appetite as well as the appetite of customers for offtakes. I know you sounded quite bullish in your opening remarks. Also the same question on the financing stream. How's the tightening credit market conditions impacting the availability of project financing?
Hey, Rob, it's Stu. You know, we're sitting here, obviously, it's a long-term project. you know, It's a totally model as described, 20-year, you know, 100% take or pay contracts. You know, we have to FID, and obviously we will be in service, you know, in the late 2027, early 2028 timeframe. People are taking a longer term view of what the LNG market will be. It's gone through, as you're well aware, some, you know, fairly high pricing, in the recent times. but people are, you know, long-term forecast with some steady pricing.
We are seeing with, you know, I think, with our EA announcement, with our first MOU announcement, you know, we've seen enhanced interest and people coming out and, you know, we've got a lot of requests for engagement. We're progressing a number of conversations for that second, third MOU. So, you know, the long-term economic view, you know, we're managing the cost. As Scott mentioned, we'll have our EPC contract cost in the midsummer here. You know, we're optimistic and anxious to get that and, you know, progress the commercial arrangements and everything is lining up for, you know, FID execution, you know, later this year.
Just on the financing, Rob, a couple thoughts. I mean, obviously the first is I think, you know, the partnership with the Haisla Nation on this, you know, is just a real key aspect of the project over so many work streams and just strategically. It shows up in the financing side as well because obviously the opportunity to work with a group like that and be a part of this project really excites the financing market. People wanna be involved with this and wanna support this project.
I would say the second thing is that obviously with the scale of the project as it is, you know, the area of magnitude of capital costs that we're talking about and an appropriate capital structure on top of that. You know, to be blunt, I mean, we're not in the same stratosphere as the Gulf Coast mega projects. That, you know, the aggregate capital need is smaller and obviously more digestible for, you know, the core LNG and core lenders to Pembina and to a project like this. I think, you know, we're not seeing impact of that so far and you know, quite honestly, people wanna be involved with this project.
Okay. That's good color. Thank you. Just on the variance in EBITDA impact from the Northern Pipeline system outage, Jaret talked about the additional investment in integrity work. I just can't help but wonder, just given the volumes, if there wasn't an investment in customer care as well. In other words, more investment in spending to truck volumes to other facilities. Was that at all a factor in the CAD 54 million versus the CAD 30 million guide?
You know, all that's factored in, Rob. You know, I would say that, I mean, the big pieces were obviously, you know, lost revenue and then the integrity work, and the remediation work on that. All of that would have been factored in.
Okay. Thank you.
Thank you. Next question comes from Ben Pham at BMO. Please go ahead.
Hi. Thanks. Hey, Mark. Can you comment on PGI? Is it trending higher than your expectations? There's some positive commentary in your package. Can you also comment on, is there any areas or gas processing assets that you're seeing utilization hit a level where you may need to look at the bottleneck opportunities?
Great question, Ben. It's Jaret here. The PGI integration and commercial opportunities with the rest of our business continue to, like, surpass our initial expectations. We recently just executed another with one of our larger customers, another pipe and processing deal, showing, you know, the value of that integrated value chain. That was obviously very exciting.
With respect to the volumes, the volumes do continue to grow, and I think it specifically mentioned the ETC, former ETC assets and the Dawson assets. We're seeing that gas growth, obviously, with the liquids growth that we're seeing on the LBP side, obviously gas comes along with that. Obviously the HBP has been impacted by Northern. Yeah, volumes are very strong. I think there was a question earlier, it might have been Rob. Specifically, like just last week, PGI management presented to the board, and PGI is actively advancing engineering and commercial discussions on CAD 750 million of gross incremental projects to, you know, either de-bottleneck or expand, you know, enhance our business. It's becoming a very exciting time.
The diversity of those assets across, you know, the oily Montney, the liquids rich Montney or the even the drier. We got access to the Cretaceous, and then obviously we're in the Duvernay. You know, it really allows, you know, the customers to be, you know, very fairly fluid and dynamic on what they need to drill. It's a very exciting portfolio. I'll speak on behalf of Pembina and the partner, we're very excited with the growth opportunities there.
Okay, great. Then, there's also commentary about ammonia methanol. As in terms around the CapEx program, can you comment on how broad you're looking at in terms of that value chain? Because I mean, there's different components where it's small dollars and there's some that could be multi-billion dollar projects.
Hey, Ben, it's Stu. Yeah, you know, we're looking across the board at this point in time. You know, we have, you know, the Pembina asset base and looking to utilize the asset base from an operations perspective, from a feedstock perspective, from a siting and operation perspective. You know, we're in conversations with people ranging from small, as you mentioned, small dollar capital opportunities. We're looking at being a service provider, in some cases, bringing, you know, water, pipeline, feedstock pipeline integration, power integration to their asset. In other cases, we're taking a more fulsome view and trying to, you know, evaluate the opportunity where we might be partnered with a under a major play such as an ammonia facility, as well.
It's a bit across the board at this point in time as we look at what those opportunities may be and trying to understand where Pembina best fits and, you know, where the best use of our capital will be.
Okay. Thank you.
Thank you. The next question comes from Robert Kwan at RBC Capital Markets. Please go ahead.
Hey, good morning. If I can just go back to your Northern outlook for the Q2. How much of that estimate is still repair, cleanup, you know, ILIs versus lost revenue now that you've started up and are expecting to ramp up? I guess where I'm going is if you can't get to full rates, what's more of the ongoing lost revenue impact if this continues?
Morning, Robert. The majority of the cost in the Q2 is lost revenue. You know, missing out on the C2+ essentially from Younger and obviously some of our other customers are currently still restricted, but that is most of it. There's some minor integrity repairs still ongoing, but that is the majority.
Yeah, I would say it's sort of around or less than about a third of that estimate, Robert.
Got it. Just can you talk a little bit more about the path to getting full rates? You know, what do you need? What's the regulatory interplay? When do you expect to get that approval?
Yeah, you bet. Great question. Although we don't have formal approval yet, we have been working with the AER, the Alberta Energy Regulator, throughout this time to ensure we're aligned on bringing this pipeline back in safely. I'd mentioned in Pat's question, you know, the incremental integrity work we've done. Everything is pointing that we don't have a systemic problem, like I mentioned, we will be working with the regulator, you know, to, you know, get this pipeline back on safely. I would like to mention, Robert, that, you know, if there were any indications that this pipeline couldn't be operated safely and we were gonna put our people, you know, the communities or the environment in jeopardy, we obviously wouldn't be pursuing that path.
What we've seen so far is giving us the confidence that we can get back to maintaining the current operation at the restricted rate and get back to full operation, you know, in short order.
Okay. I don't know, are you willing to disclose what full operation date is embedded in the CAD 25 million-CAD 30 million?
It's a range, Robert, and the reason we haven't disclosed it is that, you know, there's still a couple hurdles with the regulator. It'd be presumptive to be finer on that until we've obviously crossed those hurdles. You know, it's obviously sort of the H2 of the quarter here, but, you know, hopefully we'll be able to be clear on that very soon.
If I can just finish with the NGL recontracting year, can you just give some color as to how that shook out, both volume and pricing-wise, and frame that against what would have been embedded in guidance?
Chris, do you wanna take that one?
Yeah, sure. Happy to take that. Hi, Robert. You know, I think contracts here really went as expected. We had some volume impact here from Northern, but in general, everything sorta turned up like we thought it would. You know, in addition, pricing really was relatively positive when you looked at it with some new demand coming on with the new PDH, as well as continued sort of strong numbers off the West Coast. Pricing was shaking out, really as expected, through contracting.
Okay, that's great. Thank you very much.
Thank you. There are no further questions. I will now turn it back over for closing comments.
Well, thanks again, everyone. Thanks to all of our employees and our customers and our contractors for helping us along. I'd invite everyone to join in to our AGM presentation this morning, where we'll update you again on the business and our outlook for the year. Thanks everyone.
Thanks.
Ladies and gentlemen, this concludes your conference for today. We thank you for participating. We ask that you please disconnect your lines.