Pembina Pipeline Corporation (NYSE:PBA) Q1 2023 Earnings Call Transcript

Pembina Pipeline Corporation (NYSE:PBA) Q1 2023 Earnings Call Transcript May 5, 2023

Pembina Pipeline Corporation misses on earnings expectations. Reported EPS is $0.45 EPS, expectations were $0.54.

Operator: 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. This call is being recorded on Friday, May 05, 2023. I would now like to turn the conference over to Cameron Goldade, Chief Financial Officer. Please go ahead.

Cameron Goldade: Thank you, Joanna, and good morning, everyone. Welcome to Pembina’s conference call and webcast to review highlights from the first quarter of 2023. On the call today, we also have Scott Burrows, President and Chief Executive Officer along with other members of Pembina Senior Officer team including; Jaret Sprott, Janet Loduca, Stu Taylor, and Chris Sherman. I’d like to remind you that some of the comments made today may be forward-looking in nature and are based on Pembina’s current expectations, estimates, judgments, and projections. Forward-looking statements we may express or imply today are subject to risks and uncertainties, which could cause actual results to differ materially from expectations. Further, some of the information provided refers to non-GAAP measures.

To learn more about these forward-looking statements and non-GAAP measures, please see the company’s Management’s Discussion and Analysis dated May 04, 2023, for the period ended March 31, 2022, as well as the press release Pembina issued yesterday, which are available online at pembina.com and on both SEDAR and EDGAR. I will now turn things over to Scott to make some opening remarks.

Scott Burrows: Thanks Cam. For the first quarter, Pembina reported earnings of $369 million and adjusted EBITDA of $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 first quarter volumes across the conventional pipelines, consistent with 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 23 and look forward to the resumption of full service sometime in the latter half of the second quarter and 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.

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We continue to expect activities related to our four work streams; engineering, regulatory, commercial and financing to converge for final investments decision to be made in the end of the third quarter 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 and 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 permanent gas infrastructure’s interest in the key access pipeline system was completed on April 26. Proceeds from the sale were used to reduce debt at Pembina gas infrastructure. Fourth, the Phase VIII Piece pipeline expansion continues to progress well. Pipe manufacturing is complete and construction progressed at several locations in the first quarter of 2023. The project has an estimated cost of approximately $530 million and is now trending under budget.

We expect Phase VIII to enter service in the first half 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. And finally, I am pleased to say that we have raised our quarterly common share dividend by $0.015 per share, or 2.3% beginning with the dividend to be paid in June. Inclusive of the increased 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 first quarter of 2023.

Cameron Goldade: Thanks, Scott. As Scott noted, Pembina reported first quarter adjusted EBITDA of $947 million, which represents a $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 $54 million in the first quarter. The other major variants quarter-over-quarter was in the marketing and new venture segment, where adjusted EBITDA declined by $98 million compared to the prior period. In the first quarter 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 first quarter of 2022 and a lower contribution from Aux Sable as a result of lower NGL prices and recontracting in the fourth quarter of 2022.

In addition to the aforementioned drivers, first quarter 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 coaching pipeline, vantage pipeline and AEGS, lower adjusted EBITDA contribution from Ruby, lower revenue related to recoverable costs on the Horizon Pipeline system in the first quarter of 2022, the PGI transaction and stronger performance from certain gas processing assets, including the former EPC 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 first quarter were $369 million, representing a $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 first quarter, 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 — 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 first quarter 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 first quarter of 2022. Based on the first quarter results and the outlook for the remainder of the year, our 2023 adjusted EBITDA guidance range of $3.5 billion to $3.8 billion, remains unchanged and includes the impact of the Northern Pipeline system outage and positive effects of the widening frac spreads due to lower natural gas prices. Based on the 2023 guidance, cash flow from operating activities is as 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 31, 2023, based on the trailing 12 months, the ratio of proportionally consolidated debt to adjusted EBITDA was 3.6 times or 3.5 times after adjusting for the closing of the sale of PGI’s interest in KAPS, caps which occurred subsequent to the quarter. Pembina expects to exit the year with a ratio of 3.3 times to 3.6 times, supporting a strong BBB credit rating. I’ll now turn things back to Scott for some closing remarks.

Scott Burrows: Thanks Cam. Coming off a record year in 2022, I’m very pleased with the strong start to the first quarter. 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 PM Mountain Time, 4:00 PM Easter 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 www.pemena.com.

We’d 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 Brazos County Council declared a state of local emergency and an evacuation order has been issued for the town of Drayton Valley where our field office 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. We have 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.

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Q&A Session

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. First question comes from Jeremy Tonet at JPMorgan. Please go ahead.

Jeremy Tonet: Just wanted to start off with the conventional pipe outlook if I could, and if I recall correctly, last quarter I believe commentary might have suggested 3% to 5% gross and in the release last night, I think there was a reference to 4% to 6% growth. And just wondering if you’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?

Scott Burrows: 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. So, we are still pretty optimistic about volume growth through the back half of the year and like I said, signalling that kind of 4% to 6% volume growth,

Jeremy Tonet: That’s helpful there. Thanks. And just pivoting to the guidance, the northern system having more of an impact in the first quarter than expected and lingering in the second quarter here represents the headwind. But guidance being reaffirmed and 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.

Jaret Sprott: Hey, Jeremy, I’ll take that. Yeah, I think you’re right; two probably tailwinds offsetting, obviously the impact of the northern headwind. You hit on the first one already. It would be in the marketing segment, obviously with natural gas prices having softened here as we’ve moved out of Q4 into Q1 and beyond. I think they’ve essentially halved from where they were sort of the middle of Q4 last year. And so 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 him, obviously we are seeing strong volumes on the conventional side as well, particularly the crude and condensate side continues to show strength and that’s helping make it up.

The rest of the business, sort of chugging along and actually obviously as we said before, many of our assets are running at very high utilization. So we’re working to be able to find millions and tens of millions of dollars out of increasing utilization and increasing service that were possible.

Scott Burrows: 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. Propane’s gone from $0.80 to $0.65 in the matter of a week to a week and a half. So, pick your day and pick your forecast. But right now, we’re pretty comfortable with the guidance range.

Jeremy Tonet: That’s very helpful. And just one last one if I could, as it relates to Cedar on the LNG side, are there, is it fair to say there’s not really any meaningful hurdles left to a positive FID at this point? Kind of crossing eyes crossing Ts and dotting Is, and just as you think about construction here, 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 want to share there?

Jaret Sprott: Yeah, I’ll jump in and Stu can round it out, but I would say, there are some — there’s still some pretty big hurdles to get over. We only have half of the capacity under MOU, but we’re feeling pretty confident in our ability to fill the facility now, until we have agreements signed. Obviously we don’t have that, but we’re feeling pretty optimistic about that. And then as it relates to the engineering, 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, and so we’ll see how that comes in. Obviously, capital cost is a large driver of the project now that — but to round out your question, there is about 80% of the cost that we expect to be under some form of lump sum agreement, which really would protect Pembina from a capital cost perspective.

Stuart Taylor: Jeremy, it’s Stu, yeah, we continue to progress our four major work streams of regulatory, commercial, engineering and finance and good progress has been made across the board. A lot of work still to undertake and push to get to the finish line here. We remain — 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 middle of the year here, we should have some insight and clarity on where that will be and what that cost as should end up, but as Scott said, it’ll be a lump sum contract for 80%-plus of our capital cost.

Jeremy Tonet: That’s very helpful. I’ll leave it there. Thank you.

Operator: Thank you. The next question comes from Linda Ezergailis at TD Securities. Please go ahead.

Linda Ezergailis: Thank you. Just following up on Cedar LNG, is there a reason why you’re targeting FID by the end of the third quarter? 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 Q4 or next year? And can you please indicate the minimum level of capacity that needs to be firmly contracted at FID?

Stuart Taylor: Linda, it’s Stu again. We always had it as the third quarter of 2023. As I mentioned already, we have four work streams trying to coordinate all four to sometime and, as we sit here and look and making some progress and we did kick off an additional feed study to be done and the timing of that pushed it a little bit further back. So it’s just coordinating all of that work stream, trying to align on a date and we’re currently sitting with working hard to have that FID by the end of the third quarter as mentioned in the press release. It could possibly slip, but at this point in time, everything is full speed and targeting that the end of September for that. As far as the contracting, we’ve gone forward. We’re looking to contract a 100% of the capacity at this point in time.

We will make some call in the future as to that level, but we’re pretty confident on the MOU work that we’re going through in the definitive progress that we’ve already made that we’ll be able to contract a 100%. We haven’t contemplated or sat back and looked at a minimum number. Right now everything is pushing to contract the entire capacity.

Linda Ezergailis: Okay, thank you. And 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 discreet services and 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?

Jaret Sprott: Good morning, Linda. It’s Jared. It kind of broke out there, but I think the question was with respect to the producers, I’ll start, so 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 — we’re obviously seeing the well performance continues, and I know I say this every quarter, but the weld performance continues to excite permanent 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 a very exciting to Pembina.

And then 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 plan. Some of our customers choose to utilize PGI for that service. Obviously the peace pipeline is instrumental to a large portion of the customers in Western Canada getting their products safely and reliably into the Edmonton market. And then obviously with the addition of RFS IV, there’s high demand for existing one, two and three frac services, but also incremental and that’s even — that white space in RFS IV is closing very quickly. So, and 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 piece, that averaged about six years.

So you can see some customers are a little bit shorter and some customers like that certainty for longer term long range plans of north of seven to 10 years.

Linda Ezergailis: Thank you. And just as a short term, there’s …

Jaret Sprott: There were a few questions there. Did I get them all?

Linda Ezergailis: Sure. I don’t 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?

Jaret Sprott: The stuff definitely up in Northeast BC, some of our customers in and around the Dawson Creek area, they do see restrictions, but they’re pretty savvy and 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 on to their firm contracts on alliance, etcetera, but, we did see some noise in Q1, but the over performance of the assets kind of muted the noise of the northern outage and any announced maintenance.

Operator: Thank you. Next question comes from Rob Hope at Scotiabank. Please go ahead.

Rob Hope: Good morning, everyone. Questions on capital allocation, you re reiterated kind of the view that 2023 cash flow would be quite strong and CapEx 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 the future growth plans that you see out there, I guess, beyond Cedar that could give you some near term capital expenditures to eat into your financial capacity?

Scott Burrows: Yeah, Rob, I think, we continue, 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. But 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.

And so we expect as we move through this year, we’re going to round out a capital program in 2024, 2025, that that’s going to have an increased capital from where we are today. So we’re making sure that we’re well positioned from a financial point of view.

Rob Hope: I appreciate that. And 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 kind of continued delays and expanded capital cost?

Cameron Goldade: Yeah. Hey, Rob. It’s Cam. I think obviously we’re very proud of our partnership that we have with WIPG and being selected as their operating partner, in evaluating the opportunity to invest and own that pipeline. I think we continue to believe that that asset from a standalone basis or a standing back is a world class asset. Obviously, it’s going to have access to one of the most long-lived and probably high valued crude markets for the next few decades here as we move through — as we move through this. I think obviously, with the increases that we’ve seen, obviously we have to justify for ourselves that the economic proposition around the pipeline remains really exciting and continue to do that work. I think that obviously we can’t buy something that’s not for sale right now.

And so, we will continue to evaluate and look at it over time. We think the asset is a great asset and 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. So, those continue to be the parameters as we evaluate, consider that opportunity just as we would any other and we have no intention of stray from that.

Operator: Thank you. Next question comes from Patrick Kenny at National Bank Financial. Please go ahead.

Patrick Kenny: 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 rectify the system? Just wondering if there could be 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?

Jaret Sprott: Good morning, Pat. Jaret here. So yeah, right now the investigation continues, but all indications are pointing to stress, corrosion cracking. And that is a result of a poor coating repair during construction. That was done about 25 years ago and so right now, one of the costs increased from about $30 million that we put out last quarter to the $54 million, was us getting more integrity work done, 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. So we did — 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 — 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. But what I would say is that we’re reevaluating just the — we spend about a $100 million and I think around $150 million to $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.

Patrick Kenny: Okay. Thanks for that chair and then I guess on the flip side, it’s a bit of a rarity to see pipeline projects under budget these days. So perhaps you could just, walk us through some of the positive highlights of the Phase VIII expansion that’s helping to drive costs below budget there?

Scott Burrows: You bet. So great question. So Pat, obviously, like we have a fairly extensive knowledge of pipelining in Western Alberta, Northeast BC. I think, our seasoned team, we know where the tough spots are. We know how to cross some of the really tough river crossings. We know when — what work needs to be done in what season. I think in partnering with — we have great partnerships. We align ourselves on our values. Our safety commitment, and our partners are aligned with that and I think through our great contracting strategies, the win-win with our partners, it’s allowed us to continue to even outperform what our expectations are. Yeah, and that’s — I think it’s just great experience, great track record and knowledge.

Patrick Kenny: Okay. Thank you. And then 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 lever leverage ratio still, that 3.75 to 4.25 quarter range, and would — 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?

Scott Burrows: Yeah, I think we recognize Pat that we are, below that stated range. Obviously, as Scott mentioned earlier, we have a number of exciting opportunities looking forward and obviously as we’ve done in the past, we’ve always positioned our balance sheet to be able to seize opportunities and be in a strong position to be able to weather cycles as they as they or as opportunities may come. And so when we look at the decision to use cash flow towards reducing debt this year, it is largely a function of seeing the opportunities come in the next two to three years here and also, looking at the pure economics of it, we sort of look at interest rates obviously and where our cost of debt is. We look at that relative to the alternative and right now taking all that into account, we think it makes sense to temporarily retire some debt, with free cash flow and have that capacity available for opportunities in the future.

Patrick Kenny: Okay. Great. Thanks for that. I’ll leave you there, guys.

Operator: Thank you. The next question comes from Robert Catellier from CIBC Capital. Please go ahead.

Robert Catellier: Yeah, I just want to 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, and also the same question on the financing stream, how’s the tightening credit market conditions impacting the availability of project financing?

Stuart Taylor: Hey, Rob, it’s Stu. We’re sitting here, obviously it’s a long-term project. We’re looking, it’s a tolling model as described 20-year, a 100% take or pay contracts. We have to FID and obviously we will be in service in the late 2027, early 2028 timeframe. So people are taking a longer term view of what the LNG market will be. It’s gone through, as you’re well aware, some fairly high pricing in the recent times. But people are long term forecast of some steady pricing. We are seeing with I think with our EA announcement, with our first MOU announcement, we’ve seen enhanced interest in people coming out and we’ve got a lot of requests for engagement. We’re progressing a number of conversations for that second, third MOU.

So, the long term economic view, we’re, we’re managing the cost. As Scott mentioned, we’ll have our EPC contract cost in the mid-summer here and, we’re optimistic and anxious to get that and progress the commercial arrangements and everything is lining up for FID execution later this year.

Cameron Goldade: And just on the financing, Rob, a couple thoughts. Obviously the first is I think the partnership with the Haisla First Nation on this, it is just a real key aspect of the project over so many work streams and just strategically and 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 want to be involved with this and want to support this project. I would say the second thing is that obviously with the scale of the project as it is the area of magnitude of capital costs that we’re talking about and an appropriate capital structure on top of that, to be blunt, we’re not in the same stratosphere as the Gulf Coast mega projects.

And so the aggregate capital need is smaller and obviously more digestible for the core LNG and core lenders to Pembina and to a project like this. So I think, we’re not seeing impact of that so far and quite honestly, people want to be involved with this project.

Robert Catellier: Okay. That’s good color, thank you. And then just on the variance in EBITDA impact from the Northern pipeline system outage, Jaret talked about additional investment 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 $54 million versus the $30 million guide?

Cameron Goldade: All that’s factored in. Rob, I would say that, the big pieces were obviously, lost revenue and then the integrity work and the remediation work on that, but all of that would’ve been — would’ve been factored in.

Operator: Thank you. Next question comes from Ben Pham at BMO. Please go ahead.

Ben Pham: Hi, thanks. Good morning. Can you comment on PTI, is it trending higher than your expectations or some positive commentary in your package? And then 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 bottom net opportunities?

Jaret Sprott: Great question, Ben. It’s Jaret here. So 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 as showing, the value of that integrated value chain. So 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, but we’re seeing that gas growth, obviously with the liquid growth that we’re seeing on the LVP side, obviously gas comes along with that and then obviously the HVP has been impacted by Northern, but yeah, volumes are very strong.

I think there was a question earlier, it might have been, it might have been Rob, but specifically, like just last week PGI management presented to the board and PGI is actively advancing engineering and commercial discussions on $750 million of pros incremental projects to either debottleneck or expand enhance our business. So, it’s becoming a very exciting time and the diversity of those assets across, the oily Montney, the liquids-rich Montney, or the even the dryer and then we got access to the Cretaceous, and then obviously we’re in the , it really allows, the customers to be very fairly fluid and dynamic on what they need to drill. So, it’s a very exciting portfolio and I can — I’ll speak on behalf of Pamela and the partner. We’re very excited with the growth opportunities there.

Ben Pham: Okay, great. And then there’s also commentary about Ammonia. Can you — and as in terms around the CapEx program. Can you comment on how broad you’re looking at in terms of that value chain, because, there’s different components where it’s small dollars and there’s some that could be multi-billion dollar projects.

Stuart Taylor: Hey Ben, it’s Stu. Yeah, we’re looking across the board at this point in time. We have the Pembina asset base and looking to utilize the asset base from an operations perspective, from a feedstock perspective, from a citing and operation perspective, work 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, water pipeline feedstock, pipeline integration, power integration to their asset. And then in other cases, we’re taking a more fulsome view in trying to, evaluate the opportunity where we might be partnered with under a major place such as an ammonia facility as well and so, 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 where the best use of our capital will be.

Operator: Thank you. And the next question comes from Robert Kwan at RBC Capital Markets. Please go ahead.

Robert Kwan: Hey, good morning. If I can just go back to your Northern outlook for the second quarter, how much of that estimate is still repair, clean up, 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 loss revenue impact if this continues?

Stuart Taylor: Morning, Robert? The majority of the loss, the majority of the costs in the second quarter is loss revenue, missing out on the C2 plus 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.

Jaret Sprott: Yeah, I would say, it’s sort of an around or less than about a third of that estimate, Robert.

Robert Kwan: Got it. And just, can you talk a little bit more about the path to getting full rates what do you need — what’s the regulatory interline? When do you expect to get that approval?

Stuart Taylor: Yeah, you bet. Great question. So 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. So I’d mentioned in, I think in Pat’s question, the incremental integrity work we’ve done. So everything is pointing that we don’t have a systemic problem, like I mentioned, but we will be working with the regulator to get this pipeline back on safely. And I would like to mention, Robert, that if there were any indications that this pipeline couldn’t be operated safely and we were going to put our people, the communities or the environment in jeopardy, we obviously wouldn’t be pursuing that path. So, what we’ve seen so far is giving us the confidence that we can get back to maintain the current operation at the restricted rate and get back to a full operation, in short order.

Robert Kwan: Okay. I don’t know, are you willing to disclose what full operation date is embedded in the $25 million to $30 million?

Cameron Goldade: It’s a range, Robert, and the reason we haven’t disclosed it is that there’s still a couple hurdles with the regulator, and so it would be — it’d be presumptive to be finer on that until we’ve obviously crossed those hurdles. So, it’s obviously sort of the second half of the quarter here, but, hopefully we’ll be able to be clear on that soon.

Robert Kwan: Understood. If I can just finish with the NGL recontracting year, if you just give some color as to how that shook out both volume and pricing wise and frame that against what would’ve been embedded in guidance.

Scott Burrows: Chris, do you want to take that one?

Chris Sherman: Yeah, sure. Happy to take that. Hi, Robert. I think contracts here really went as expected. We had some volume impact here from Northern, but in general, everything sort of termed up like we thought it would. In addition pricing really was relatively positive when you looked at it with some new — some new demand coming on, with the new PDH as well as continued strong numbers off the West Coast. Pricing was shaking out really as expected through contractor.

Robert Kwan: Okay. That’s great. Thank you very much.

Operator: Thank you. There are no further questions. I’ll now turn it back over for closing comments.

Scott Burrows: Well, thanks again, everyone. We’re pretty proud of our strong start to the year and thanks to all of our employees and our customers and our contractors for helping us along and I’d invite everyone to join into our AGM presentation this morning where we’ll update you again on the business and our outlook for the year. Thanks everyone.

Operator: Ladies and gentlemen, this concludes your conference for today. We thank you for participating and we ask that you please disconnect your lines.