Good morning, and thank you for joining AltaGas' Fourth Quarter 2025 Results Conference Call. This call is being webcast, and we encourage following along with the supporting slides that can be found on our website.

Speakers this morning will be Vernon Yu, President and Chief Executive Officer; and Sean Brown, Executive Vice President and Chief Financial Officer. We're also joined by Randy Toone, President of Midstream; Blue Jenkins, President of Utilities; and Jon Morrison, Senior Vice President of Corporate Development and Investor Relations.

We will refer to forward-looking information on today's call. This information is subject to certain risks and uncertainties as outlined in the forward-looking information disclosure on Slide 2 in the presentation.

As usual, prepared remarks will be followed by a question-and-answer session. I'll now turn the call over to Vernon.

Thanks, Aaron. Good morning, everyone, and thanks for joining our Q4 conference call.

I'll start by introducing Sean Brown, who joined us in January as our new CFO. Sean has been in the energy business for more than 25 years as an executive and an investment banker.

Sean's strong financial background adds to our existing bench strength at AltaGas, and he will help drive the continued execution of our strategic priorities. Today, we will review our Q4 and full year financial results.

We'll reaffirm our 2026 guidance and update you on our progress of our strategic priorities. Our performance in 2025 reflects the strength of our people, assets and relationships, which positions us well for continued success in 2026.

I'm going to kick off my remarks by reviewing some of the highlights from 2025, including our financial performance and the execution of our strategic priorities. I'll then review our growth projects and our project backlog, talk about the importance of natural gas for long-term customer affordability and close by reviewing the current LPG export market.

John will then cover our financial results and outlook in more detail. Let's start on Slide 4.

Our 2025 results were driven by strong performance in both Midstream and Utilities. We delivered normalized EBITDA close to the top of our guidance range, exceeding $1.86 billion for the year.

Earnings per share came in at $2.23, which was in the upper half of our guidance range. We executed our strategic priorities by optimizing our asset base, delivering record global export volumes, record throughput at North Pine and Pipestone, along with active regulatory filings at our Utilities.

We continue to de-risk the business through long-term contracts and export market diversification in Midstream and extending regulatory approvals for the Utilities asset modernization program. We strengthened our balance sheet, exiting the year at 4.7x adjusted net debt to EBITDA and saw our credit rating outlook move from negative to positive.

We advanced key growth projects. Pipestone II came into service in December, and we saw great construction progress at REEF, reached positive FIDs on REEF Optimization 1, the RIPET methanol removal project Phases 1 and 2, expanding the Dimsdale gas storage facility and the Keweenaw Connector Pipeline in Michigan.

These results translated into a 29% total shareholder return in 2025 and a 5-year TSR CAGR of 22%, where we have meaningfully outperformed our peers. Turning to Slide 5.

Pipestone II is complete and is operating close to full capacity. The project was delivered on time and on budget, further strengthening our Midstream value chain.

On Slides 6 through 8, we highlight our construction progress at REEF. Phase 1 is now 70% complete, which was in line with our plan.

We now have all the LPG accumulators and bullets on site. All 3 LPG accumulators should be placed on their foundations this week.

You can see a picture of the arrival of the 2 accumulators on Slide 8. Study construction has accelerated and remains on plan.

We have successfully installed 8 of the 13 spans. The remaining sections will be put in place later this spring, and we've kicked off work on the loading platform.

Phase 1 of the rail corridor and utility corridor have been finished. This includes the full rail yard and the rail offloading modules.

Opti-1 is also advancing on plan and is expected to be in service for mid-2027. Overburden removal has been completed and blasting activities will start this month.

Opti-1 will add another 30,000 barrels a day of propane export capacity, which is higher than our original expectations. Slide 9 shows that the RIPET methanol removal project and the Dimsdale gas storage expansions both remain on time and on budget.

These new facilities will contribute to our 2027 growth outlook. Slide 10 highlights our Midstream project offer, where we continue to advance multiple growth projects, including a Townsend De-Propanizer, a Northeast BC liquids expansion focused on improving long-term rail logistics, progressing additional phases of REEF, including the potential of adding ethane exports given the strong demand from China as well as a North Pine frac expansion and more gas processing with Pipestone III.

Let's turn to Slide 11. We're set to start construction of the Keweenaw Connector pipeline this spring.

All the long lead items have been ordered and the entire right-of-way has been secured. We remain very active with $1.7 billion of modernization programs across our 4 jurisdictions, which will improve the safety and reliability of our network.

We are also advancing our data center opportunity set with multiple FEED studies completed. And we have now started construction of the natural gas connections to feed Phase 1 of a 24-megawatt facility in Maryland, which is expected to be completed by year-end.

Slide 12 highlights the importance of natural gas during today's energy affordability crisis for Utility customers across North America. Natural gas is the most affordable and reliable heating source in the U.S.

The cost of electricity for home heating is more than 3x more expensive than natural gas across our jurisdictions. This cost advantage is only getting bigger.

Recent electric bill increases are coming in at over 10% per year, which is 4x current inflation. This trend will continue as more and more investment is needed to replace America's outdated electrical grid.

Natural gas is the only energy solution that is scalable, affordable and reliable to meet growing North American energy demand. Public policy should prioritize cost-effective outcomes by avoiding unnecessary electrification that increases customer bills and reduces energy reliability.

We believe that policymakers should be incentivizing natural gas infrastructure for space heating across the country. Asian demand continues to grow and is expected to be up by nearly 25% by 2030.

This is being fueled by new household demand in markets like India and the continued growth at PDH facilities in China. In 2026 alone, we are expecting to see 300,000 barrels per day of increased propane demand due to Chinese PDH start-ups.

Since the beginning of 2025, we've seen very strong demand for non-U.S. LPG supply with global trade sanctions.

This has caused Chinese imports of U.S. propane to decline by more than 50% in 2025.

And the market continues to pay a premium for non-U.S. propane.

On the supply side, the local Canadian butane market is currently oversupplied due to certain facility outages. Both of these supply and demand factors are tailwinds for our 2026 outlook.

The FEI forward curve has strengthened materially in 2026 as highlighted in the bottom right chart. We saw FEI move up with winter weather in Asia, then further up with the recent Saudi supply disruption and even further up with the Iranian conflict.

As a result, March FEI propane spreads are almost 50% higher than the start of the year, underscoring the severity of the Middle Eastern supply shock. Let's turn to Slide 14.

2025 marked a step change in our export destinations with 45% of our volume landing in China, where our market share has now increased to about 6% of China's imported propane. AltaGas now represents 5% of Canada's total national trade into Japan, South Korea and China, amounting to about $2.5 billion in 2025, which we expect to double by 2030 with the start-up of REEF and Optimization 1 and the continued debottlenecking at our existing export facilities.

We're also proud to be investing in Asian economic activity with $600 million invested in Japan, South Korea and China over the last number of years to support the expansion of our global export business. This is in concert with very large investments that we've made with domestic manufacturers and engineering companies in Canada and the U.S.

Finally, on Slide 16, we're committed to our strategy of disciplined capital allocation. With approximately $5 billion of investment capacity over the next 3 years, we can fund $3.5 billion of growth while staying within our financial guardrails.

Investment in our high-quality organic growth backlog supports long-term enterprise growth of 5% to 7% per year, which will generate meaningful and sustainable shareholder value creation. And with that, I'll now turn it over to Sean.

Thanks, Vernon, and good morning, everyone. I'm excited to be here for my first quarterly conference call with AltaGas.

I'll begin with an overview of our consolidated quarterly financial results, followed by segment performance, a discussion of our balance sheet strength and conclude with our 2026 outlook. Turning to Slide 17.

We closed the year with a strong fourth quarter, delivering normalized EBITDA of $564 million, an 8% increase year-over-year and normalized EPS of $0.77, consistent with the same period last year. In the quarter, we exported more than 124,000 barrels per day of LPGs, including over 85,000 barrels per day from RIPET, a new quarterly record despite the impact of a 28-day labor disruption.

At RIPET, we are pleased to sign a new 5-year agreement with the union in late December. This agreement supports increased vessel loading and higher throughput moving forward and reflects AltaGas' commitment to working collaboratively with our unions to deliver positive outcomes for all stakeholders.

Utilization across the balance of the Midstream platform was strong with throughput volumes up an average of 4% year-over-year across our gas processing, fractionation and extraction assets. With respect to our Utilities business, colder weather and a growing customer base drove increased usage, as I will discuss on the next slide.

The fourth quarter also saw several important regulatory outcomes, including approval of new rates in D.C. at 61% of our ask, a USD 25 million extension of the PROJECTpipes 2 ARP program in D.C.

through June 2026, approval of a USD 700 million ARP amendment in Virginia extending through 2028 and the filing of a new rate case in Maryland late in the year. In addition, subsequent to year-end, we recently filed a USD 61 million rate case in Michigan.

And this week, we received approval for our DC SAFE ARP program to spend USD 150 million from mid-2026 to mid-2029. In terms of segmented results, I'll start with Utilities on Slide 18.

Utilities normalized EBITDA was $383 million, up 14% year-over-year. Performance was driven by rate base growth from ARP modernization investments, asset optimization initiatives and an 18% increase in usage, supported by colder weather in D.C.

and Michigan and continued customer growth. Results also benefited from the partial settlement of Washington Gas' pension plan.

These positives were partially offset by lower realized contributions from the retail energy business and higher operating and maintenance costs, driven by increased labor requirements during cold weather and higher employee incentive expenses driven by AltaGas' rising stock price. During the quarter, we deployed $255 million of capital in Utilities, including $117 million towards modernization programs and $113 million towards system betterment initiatives.

As noted, we remain active on the regulatory front with 3 active rate cases. Shifting focus to our Midstream business on Slide 19.

Normalized EBITDA was $202 million, an 11% increase over Q4 of last year. As noted, we exported more than 124,000 barrels of LPG per day during the quarter through 21 VLGCs and for the full year, averaged in excess of 126,000 barrels a day across 83 ships at our Ferndale and RIPET terminals.

Throughout the year, demand for our open access export terminals continued to strengthen, supported by long-term tolling agreements with investment-grade counterparties. These agreements enabled us to achieve our 60% tolling target, further enhancing cash flow durability.

The remainder of the Midstream portfolio also performed well year-over-year, particularly our Montney focused assets where gas processing volumes increased 6% and fractionation volumes increased 14%. Pipestone throughput increased 11%, while North Pine operated near its 25,000 barrel per day capacity.

Constructive fundamentals for natural gas storage continue to reinforce our decision to advance both phases of the Dimsdale expansion, which will play a key role in managing Montney production growth and large LNG demand pulls in the years ahead. During the quarter, we remain disciplined in managing commodity exposure.

Our export business was largely insulated from price volatility through commercial tolling agreements and a structured hedging program. Looking ahead, approximately 80% of expected 2026 global export volumes are either tolled or financially hedged with an average FEI to North America spread of approximately USD 19 per barrel on non-toll volumes.

In addition, substantially all of our 2026 Baltic freight exposure is hedged through a combination of time charters, financial instruments and tolling arrangements. We continue to manage frac spread exposure through our disciplined risk management program.

We have seen a meaningful uplift in frac spreads since the beginning of the year, which we have used to increase our hedge position, which now sits at roughly 70% through 2026. Let's turn to our balance sheet on Slide 20.

Following the decision to retain our stake in the Mountain Valley Pipeline, we issued $460 million in equity, achieving an equivalent deleveraging impact as if we had divested our working interest while retaining asset upside. These actions resulted in a year-end adjusted net debt to normalized EBITDA ratio of 4.7x, slightly below the midpoint of our 4.5 to 5x target range and led to positive credit revisions from both S&P and Fitch.

As we have commented recently, operating performance and progress on expansions at MVP continue to reinforce our decision to retain the asset. Since announcing our decision, the Southgate extension received unanimous FERC approval and key North Carolina water permits.

The MVP Boost, which will add 0.6 Bcf a day of capacity through low-risk compression continues to progress well and is expected to enter service by mid-2028. The project is supported by investment-grade Utilities and is expected to generate a build multiple of approximately 3x EBITDA.

We are reaffirming our 2026 guidance, as shown on Slide 21, with normalized EBITDA of $1.925 billion to $2.025 billion and normalized EPS of $2.20 to $2.45. Headwinds and tailwinds remain relatively balanced at this stage.

Year-over-year tailwinds in 2026 will include new utility rates in Virginia, Maryland and D.C., incremental contributions from Pipestone II and the Dimsdale Phase 1 expansion and continued growth in global exports supported by increased dock capacity at RIPET. These are expected to be partially offset by lower merchant volumes and more moderate retail energy performance.

The 2026 capital budget, as shown on Slide 22, remains unchanged at $1.6 billion with 69% of consolidated capital dedicated to Utilities and 27% to Midstream. Compared to last year, Utilities will see a meaningful increase in both spending and share of total capital reflecting significant opportunities around asset modernization as well as reduced requirements in Midstream following the completion of Pipestone II and lower capital needs at REEF.

Of the $1.1 billion Utilities capital program, 71% is allocated to modernization and system betterment initiatives, supporting safety, reliability and efficiency. This is expected to drive approximately 10% rate base growth in 2026.

Turning to Slide 23. I'll close by reiterating AltaGas' proven track record of delivering per share growth, which has translated into material share price outperformance.

The company continues to offer an attractive value proposition, as shown on Slide 24. Our low-risk infrastructure platform supports stable, growing earnings and cash flows, underpinned by disciplined capital allocation and a robust organic growth pipeline.

With that, I'll turn it back to the operator for the Q&A session.

I know this is a bit of a sensitive question, but I feel -- compelled to ask it. I was wondering, just understanding you've had a long history of constructive respectful dealings with First Nations.

I'm wondering if there's anything you can share on the Metlakatla situation and their interest in the Trigon terminal. Any update you can provide there would be much appreciated.

And specifically curious if you can confirm whether you're still engaged in active discussions with the Metlakatla.

It's Vernon here. I think you're absolutely bang on that we're disappointed that we're having a disagreement with the Metlakatla First Nation kind of in the public.

At AltaGas, we take a lot of pride in the fact that we're a good neighbor and that we've been have had very strong relationships with all of our communities and particularly with our First Nation partners. We've had indigenous equity participation deals and mutual benefit agreements for many, many years.

And in fact, we've been working with the Metlakatla and Prince Rupert since 2017 with the development and start-up of RIPET and REEF. So across our footprint, I think we have 15 mutual benefit agreements in Alberta and British Columbia.

In fact, we have 6 mutual benefit agreements on the coast for both REEF and RIPET. With the construction of REEF, we've been actively working with various indigenous businesses where, in fact, about $350 million of REEF's total capital cost is being done by indigenous businesses, and we're really proud of that.

So our hope is to continue to work with all of our First Nations partners. Obviously, we want to continue to have dialogue with them at Metlakatla.

We do speak with them fairly regularly. We're at a point right now where we're having a disagreement on a couple of items, particularly related to Trigon.

And I guess we felt like we've been drawn into the situation because Trigon would like to build a competing LPG export facility on Ridley Island. The regulator and the landlord of Prince Rupert, the Prince Rupert Port Authority doesn't agree that they have the ability to do that.

And we need to obviously defend our commercial rights and protect our export franchise. So we feel that having exclusivity is an important feature.

It's a common feature that you see in port development globally and in Canada. As an example, for REEF, we spent along with our JV partner, Vopak, about $100 million of that risk capital before we were able to get our permits to go ahead and that regulatory process, in fact, took around 7 years.

So without these types of commercial arrangements, it's very difficult for project proponents to put risk capital at work because you need to ensure that you're going to get a healthy and reasonable return on your overall capital once your facility is up and running. So long and the short is we've continued to have active dialogue with all First Nations along the coast, and we hope that we can find a mutually benefit solution as we go forward.

Okay. I had a couple of questions on the operations.

A little surprised, Sean, to hear your comment about the puts and takes of the tailwinds and headwinds being relatively balanced. I would have thought maybe the change in commodity prices would have put the balance in favor of the tailwinds.

But with that in mind, given the change in commodity prices we've seen some producers such as Tourmaline are claiming to reduce deep Basin activity. With that in mind, are there any direct impacts from that disclosure from Tourmaline on AltaGas?

And just in general, what's your sort of expectation of how the G&P business might develop for '26 compared to when you released guidance?

Maybe I'll start, Rob. So we've seen upstream customers want to take more control of gas processing, both in BC and Alberta for some time.

And I think that the interesting part of that is by them taking control of that part of the business, they get more control over their liquids, which is positive to us because Tourmaline and other producers realize that the best outlet for their liquids is for global exports. And Tourmaline is obviously one of our largest customers.

So I think anything that they're contemplating, we generally stand to benefit because they have a deep understanding of market dynamics and how to maximize the netbacks of their LPGs. I think Sean and Randy can talk about just the outlook for this year.

Yes, I can start, certainly. I mean, I hear your comment, Rob, around the puts and takes.

I mean, as we sit here today, certainly, there is constructive tailwinds given some of the geopolitical activity. But the thing I would say is it is early in the year as well.

So we're trying to remain balanced as we think about the discussion around the full year. And if you look at the shape of the curve in general, I mean, it's fairly backwardated.

So it's all of that, that we put together when we thought about our prepared remarks. But your point is a good one where as you sit here today in isolation, probably the tailwinds are quite positive, and we feel good about where we are to start the year.

Okay. And just one quick one on the Utilities.

Just wondering if you could provide a sensitivity to rate base growth, sort of big picture outlook should the various building energy performance standards in your jurisdictions pass as intended and survive any of the legal challenges?

Yes, thanks, Rob. It's a good question.

We continue to work our way through that. As you would expect, the uncertainty seems to be more impactful than the actual change in the standards.

So as we look across our business, the growth rate, we don't think is materially impacted as we look across how things are being built and what's being built. What we're seeing is uncertainty of investment being more driven by the -- some of the other policies in the area.

So as we look across that growth rate, we still connect -- we still have positive customer growth, very strong customer growth in Maryland. As you saw in the prepared remarks, we still see -- our first data center contract happens to be in Maryland right in the middle of all of those battles.

So at the moment, I don't know that I'd call it significant by any stretch, and I think that process is going to take a while, but we continue to educate the regulators and the decision-makers and of course, the investors in these projects about the overall affordability impacts and how to think about that more holistically. So we're optimistic that we'll get to a good place without significant impact.

Rob, just as a data point, the municipal government in D.C. excluded all of their buildings from those net zero standards.

So it just tells you how [indiscernible] some of these initiatives are.

I want to go back to the forward curve for global exports. You are correct.

It is very backwardated, but we continue to see kind of, we'll call it, higher pricing push further out into the curve. Just given these dynamics, how do you think about your remaining merchant exposure through the year?

Will you be looking to lock in pricing? Are you willing to ride out some spot exposure there?

And in addition, are you able to push incremental spot barrels through if you're able to accumulate them?

Well, Rob, let me start and Randy can jump in if I miss something. So you're right.

The curve is highly backwardated, but the curve has gone up a little bit. We're quite comfortable with our hedge positions right now where we're about 80% hedged for the year.

We are benefiting a little bit from supply differentials. And then on our open merchant volumes, we are seeing strong demand for those barrels with obviously the supply outages coming out of the Middle East.

We will -- and it is a unique market where you're seeing everything on the screen that you see may not be fully representative of the final sales price that we get. So we think we're perhaps being a bit cautious in talking about this.

But if this continues to play out where the straits are shut down for an extended period of time, I think we're in a good position with our current financial hedges that we don't really need to do any more.

All right. Appreciate that.

And then maybe just turning over to REEF Opti-1. So can you walk us through how it went from 25,000 barrels a day to 30,000?

And is that 300 now firm? Or could there be some further upside there as well?

Rob, it's Randy. Just with the further detailed engineering of Opti-1, the teams identified some adjustments that added the extra 5,000 barrels.

So there's nothing unique there. It's just as you go through detailed engineering, the team plans optimizations.

Dovetailing on with the prior question, I'm curious if you could give some sort of breakdown as to like what really drove the wider hedge spreads in the second half versus the first half. Is that a function of like layering on hedges recently with Far East propane spreads being a lot wider?

Is it contribution that's pretty meaningful on the butane side? Just curious if we could get a breakdown of that to inform the much wider locked in spreads in the back half of the year.

It's Randy. I think it's a combination of both.

It's -- we actually have seen some -- the spreads widen, and so we've took advantage of that to put in some hedges. But it's also -- it's higher -- we have higher hedges on butane, which is a larger spread.

Okay. Understood.

And then just on the potential projects that you guys called out in the slide deck, I mean a lot of those addressed liquids growth out in the future. So just like curious how you guys would, I don't know, maybe clarify some of the hurdles that are remaining on each of them where you might rank order them in terms of build multiple or timing perhaps?

I think the Townsend depropanizer is probably the most we should see an FID sometime in the next 12 months or so. That really is customer-driven at this point, whereas customers bring on more volumes, we have an obligation to process those volumes for them.

Then we, obviously, with the depropanizer are able to get the liquids out and move them to the West Coast at our North Pine rail facility. I think REEF Optimization II is also a 2026 potential FID project.

There, obviously, the strong commercial support. It's really just locking down the capital cost.

So we have a firm Class III cost estimate and then finalizing one permit amendment that we need to go ahead with that. The other ones are probably in that 12 to 15 months out, maybe 24 months out.

And all of these projects are relatively low capital, low build multiples, so highly attractive and should be very competitive as we do our capital allocation going forward.

Okay. Great.

One real quick one just on REEF Opti-2 since you brought it up. I mean is that sanctioning contingent upon any progress made with the discussions with the Metlakatla?

We're obligated to do consultation with all of our First Nations, and the consultation process will go into the regulator, and the regulator will make a determination if we've done sufficient consultation.

This is Eli on for Jeremy. Just wanted to start on the balance of Midstream versus Utility capital within the backlog.

We see nearly twice as much Utility growth capital versus Midstream. And so if we see some of these projects in the backlog move ahead on the Midstream side, could we see that mix shift move a little?

Or -- and then maybe just thinking about sort of the strong returns you generate from those Midstream projects, could we see sort of higher within the range of that 5% to 7% long-term annual growth if you were to sanction more Midstream projects?

Eli, I think you've asked a great question. You would have seen us in the last couple of years slow down our Utility spend a little bit when we had some very attractive Midstream projects to execute.

And the good news that we found is that those Utility growth opportunities didn't go away. They just got deferred a year or 2.

So I think if we are in a situation where we have more projects than investment capacity, we're going to have to go through and do our process of capital allocation and the best risk-adjusted returning projects will get priority. So the nice thing about Utility capital is its ratable growth.

So -- because the bulk of our capital that we're spending is modernization capital with rate riders, so we get that almost immediate growth from it. Midstream projects do have a longer gestation period and build cycle.

So while they may be more attractive, they are lumpier in nature. So I think if we're successful in filling up the full growth hopper, we'll be very comfortable to be in the upper end of our medium-term growth guidance.

Great. I had a smaller accounting question as a follow-up.

We've seen some consistent transaction or restructuring expenses, and I know it's been a while since the last larger transaction. Any color on what those kinds of add-backs pertain to?

Are you -- sorry, are you referring to sort of normalization in general?

Yes. I mean I think we see restructuring costs and transaction costs, just looking at some of the reconciliations within the MD&A.

Yes. I mean if you look -- just think about last year alone, I mean, with respect to the MVP transaction, there certainly would have been some there.

There was some changes otherwise. But I mean, in general, the biggest one would have been really around MVP that I'd highlight.

Maybe more detailed question on WGL. Can you quantify or attempt to quantify what the realized ROE was for 2025 versus 2024.

I'm going to -- just give me a second here, Ben.

Yes. So on the portfolio for WGL, realized we were within about 100 bps of the authorized on the total portfolio.

That varies a bit by jurisdiction, as you would expect, but the total portfolio, about 100 bps of authorized -- within authorized.

Okay. So it sounds like it's generally unchanged versus 2024 then in terms of the relative difference?

I think it's a little bit better than 2024, maybe 10 or 20 basis points. We expect that to improve further in this year because of the DC rate case going in, getting approval for the DC rate case and having those rates go ahead.

So we think we'll be in the range of about 70 basis points in 2026, Ben.

Yes. I think that's right.

I would add, Vernon, to that and just Ben, so that we have a full year of the DC rate case. We have rates in effect from Virginia at the start of the year, subject to refund on that final case.

And then we filed for Maryland, and we expect to have rates -- new rates in effect in Q4. So I think you see a consistent progression in '24 to '25 to '26.

And as we've said in the past, Ben, that doesn't include asset optimization, which is always an opportunity for us to improve returns as well, and that will be consistent this year.

Got it. And there was an earlier question on the propane export hedging.

You provide some details there on the level and the shape of it. You also provided the sensitivity as well; $1 a barrel is $10 million.

Is that sensitivity, is that incremental to the price levels you disclosed? Is that some lower number that's baked into your 2026 guidance?

So that would be what's baked into our 2026 guidance, Ben.

And presumably, that's probably lower just given when you put your budget out versus how the spot has moved since then?

Yes, that's fair.

First question here is just on Prime Minister Carney's meetings in India and the government's release citing the ongoing engagement for more LPG exports into India. So I'm just wondering, generally, just what your thoughts on that given of all the different things you talked about energy-wise, LPGs are probably most actionable in the near term.

And then there was also a statement about addressing higher shipping costs. And I'm just wondering if you've got some color or thoughts on that as well.

Well, I think, Robert, the dynamic with India is there is very strong demand in India for more LPGs. Remember, I think 300 million people in India still cook with charcoal.

And I had recently met with Minister Hodgson, who indicated when he was in India that India is very keen to get people off that cooking charcoal and propane is obviously the best alternative for that market. As you know, India is a little bit far away from Canada.

So Middle Eastern barrels will always be advantaged going into India just because of shipping costs. Once you go past about South China, we become disadvantaged on a shipping cost basis.

So you've seen us kind of move initially with RIPET into Japan and Korea, where we had a material shipping advantage. We've seen the Chinese market open up to us primarily because of U.S.

trade tensions. And then as demand continues to go up and if Canada disproportionately grows in supply, we do have an opportunity to expand to other markets.

And that's why we're so keen to have REEF Opti-1 and hopefully Opti-2 follow up and provide access to Canadian producers to all of these markets.

And just in terms of the government statements that both are going to work on helping address the shipping cost differential, do you see that then as just a redirection of flow? Is that maybe higher contracting for you or possibly new capacity?

We haven't seen any direct linkage yet. So we look forward to engaging with the government and seeing what they're thinking about.

Okay. Just the last is on fractionation capacity, and you kind of outlined some potential projects in North Pine and Townsend.

I guess just as you think about your existing integrated network and possibly further increasing capacity at REEF, do you feel the need to even further increase your control of NGL fractionation beyond what you've outlined for Townsend and North Pine?

We're actively working with a number of our customers, primarily NGL aggregators that have significant amounts of frac capacity and growing frac capacity. So we're looking to offer full-service solutions from the wellhead to the dock, basically in a JV-like partnership with a number of these companies.

Obviously, you've seen in the last 12 months, we press released transactions with Keyera, Pembina and Wolf, all of which are building incremental fractionation. So our view is if we're able to bundle these solutions through partners, so it's not critical that we own more frac capacity.

But I think we're uniquely situated in Northeast BC, where with North Pine and Townsend, we can provide just that much of a better logistical option because of where our rail facilities are, Robert.

I guess just on the appointment of Mr. Evans as Chair, we've seen a decent uptick in bitumen production over the past few years and a fairly constructive outlook here for egress expansions going forward.

I know the exports platform and execution of REEF is top priority. But just wondering if we should be reading into any longer-term shift in strategy related to looking at participating in any opportunities to extend your service offering to oil sands producers, whether it be on the propane solvent front for SAGD projects or perhaps investing more heavily into condensate infrastructure, either in BC or Fort Saskatchewan?

Well, Pat, I don't think you can read a ton into Derek's appointment of a change in strategy. We're going to be disciplined in how we put our capital to work.

We feel like we obviously have strategic advantages in NGLs and global exports, as you pointed out. If there are opportunities to work with oil sands producers about moving NGLs from Fort McMurray to other markets, well, for sure, we'd be happy to investigate that.

But I wouldn't read too much. And we just want to have Board members with deep industry knowledge and great management experience that provides advice as we continue to try to grow and optimize our business.

Okay. Got it.

And then maybe just back on the unsecured growth backlog. So you touched on the cost advantage of gas over electricity on the Utilities front.

It seems to suggest some upside there to the CapEx plan. Yet obviously, still a lot of attractive projects in the queue on the Midstream side.

So I'm just wondering how you might be thinking about bringing in some strategic JVs or other financial partnerships, just whether it be on the U.S. side of the border or up in Canada, just to make sure you don't have to pass up on any opportunities from a funding standpoint.

Well, the good news is our investment capacity grows each and every year as we add cash flow. So we have a natural uplift in the amount of capital we can put to work.

Some of these things that we're looking at, obviously, in the unsecured hopper are further out in time where we'll have more investment capacity. But at the end of the day, if we've got great projects that pass all of our investment hurdles, our finance team will figure out a way to get them financed.

Great. Thanks again to everyone for joining the call this morning.

The Investor Relations team is around if you have any further questions. Have a great day.