Good morning, ladies and gentlemen, and welcome to the Rockpoint Gas Storage Inc. First Quarter 2027 Webcast and Conference Call. This conference is being recorded, and at this time, all lines are in a listen-only mode. I would now like to turn the call over to Rahul Pandey, Manager of Investor Relations. Please go ahead. Thank you, operator, good morning, everyone. With me today are Toby McKenna, CEO, Jon Syrnyk, CFO, and other members of the senior leadership team. We'll begin the call with some prepared remarks from Toby and Jon, after which we will open the call for the Q&A session. In order to accommodate as many questions as possible, we kindly request to limit your questions to one plus a single follow-up if necessary. Our investor relations team will be readily available following this call for any additional follow-up questions you may have. I would like to remind listeners that some of the comments and answers that we will provide today relate to future events. These forward-looking statements are given as of today's date and reflect events or outcomes that management currently expects. In addition, we refer to some non-IFRS financial measures. For additional information on non-IFRS measures and forward-looking statements, please refer to Rockpoint's quarterly financial statements and MD&A available on our website or SEDAR+. I'll turn the call over to Toby. Thanks, Rahul, good morning, everyone. We continue to make meaningful progress on our strategic priorities, including maximizing the value of our existing assets, growing contracted fee-for-service cash flows, and advancing capital-efficient brownfield growth opportunities. Our fee-for-service gross margin, which includes our take-or-pay and short-term storage business, increased 7% over the last 12 months basis, driven largely by 20% growth in our long-term take-or-pay gross margin. This growth was driven by higher storage rates and increased contracted volumes, reflecting disciplined commercial execution and the value customers place on our infrastructure. Fee-for-service gross margin contribution remained broadly aligned with our long-term target of approximately 85% of total gross margin, enhancing earnings visibility and reinforcing business resiliency. While our contracted business continues to provide a stable foundation, we're also focused on advancing capital-efficient growth investments. Our Warwick Battery Storage project, which is a complementary opportunity aligned with the changing needs of the energy system, continues to remain on budget and is expected to enter service in fiscal 2028. Additionally, our Warwick Gas Storage Expansion project has received all required regulatory approvals to move forward. The initial expansion is expected to add approximately 3.5 Bcf of working gas storage capacity in fiscal 2027, with potential to increase total incremental capacity to approximately 5 Bcf in fiscal 2028. Importantly, our strong financial position allows us to pursue these growth opportunities while also maintaining flexibility to return capital to shareholders. As discussed during our last conference call, returning incremental capital to shareholders through opportunistic share buybacks alongside our sustainable and competitive dividend remains an important component of our shareholder value proposition. In that regard, between June and July of 2026, we repurchased approximately 369,000 Class A common shares at a weighted average price of CAD 28.49 per share for a total consideration of CAD 10.5 million. We believe these repurchases represented an attractive use of capital. Our decision to repurchase shares reflects both our disciplined approach to capital allocation and confidence in the underlying business, supported by the long-term fundamentals underpinning growing customer demand. Turning to our take-or-pay business, we remain confident in delivering our medium-term take-or-pay gross margin contribution of 60%. Across both our operating regions, we remain focused on contract quality and pricing discipline, prioritizing long-term value creation over exclusively pursuing take-or-pay gross margin growth. In Alberta, demand remains strong as customers continue to seek reliability and flexibility in an increasingly tight natural gas market. The strong momentum achieved during the fiscal 2027 contracting season has carried into fiscal 2028, with customers initiating discussions earlier than typical, which would be our September and fall timeline. Just four months into the fiscal year, contracted Alberta take-or-pay volumes for fiscal 2028 already have increased by approximately 30% year-over-year. While these volumes will not contribute to take-or-pay gross margin until fiscal 2028, we view this as a strong signal of shifting customer behavior as they seek to secure access to our infrastructure amid increasing market volatility and tightening supply-demand fundamentals. We are observing similar evidence of the strategic value of storage in California, albeit driven by a different set of market dynamics. As previously disclosed, take-or-pay volumes for fiscal 2027 were in line with the past three years. Importantly, we achieved strong renewal results during fiscal 2027, despite it being a significantly large renewal year, with volumes roughly three times larger than the volume currently up for renewal in fiscal 2028. We continue to believe the long-term outlook for the California natural gas storage market remains constructive for the following reasons. First, California remains structurally short in natural gas and continues to rely heavily on imported supply to meet its energy needs. Second, the state's unique and dual peak demand profile creates a year-round need for storage. Third, the California Independent System Operator, or CAISO, which serves the power grid across approximately 80% of California, continues to be one of the fastest-growing markets in the U.S. and is becoming increasingly exposed to intermittent renewable generation. California's position as a top 10 state for data center development is expected to drive additional demand for reliable natural gas-fired generation. Collectively, these trends, together with significant barriers to new storage development, reinforce our view that demand for natural gas storage in California will continue to strengthen over the long- term, supporting the value of Rockpoint's strategically located assets and the benefits they provide to customers. Beyond our contracted business, we're encouraged by the macro backdrop, which continues to support both our customers and our optimization activities. Rockpoint's business model is designed to create value across a wide range of natural gas price environments, providing resilient cash flow generation. There are several constructive macro themes currently at play. First, global LNG prices have rebounded to levels seen earlier this year and remain elevated. As North American LNG supply continues to play an outsized role in balancing natural gas markets, domestic supply disruptions or demand spikes could drive higher natural gas prices. Second, natural gas production growth is expected to continue, driven by ongoing oil and NGL-directed drilling in high oil and NGL price environment. This dynamic is putting downward pressure on the near-term gas prices and in turn is enhancing seasonal spreads. Third, factors such as strengthening El Niño weather patterns and an elevated wildfire risk across Western North America could further increase volatility across energy markets, reinforcing the strategic importance of natural gas storage infrastructure. These trends enhance the insurance value of natural gas storage and expand the opportunity set for our optimization business. Stepping back from our near-term environment, these trends are also occurring alongside several long-term structural changes that continue and increase the value of storage over the long- term. Several powerful secular trends continue to gain momentum, including LNG exports, data center development, renewable power generation, and industrial natural gas demand growth. The North American natural gas market is undergoing a fundamental shift, with customers increasingly using storage for operational backstop and supply reliability rather than traditional seasonal supply-demand balancing. Given our strategic location, high deliverability, and operational flexibility, we believe our large-scale assets are well-positioned to benefit from favorable long-term market fundamentals, supporting our customer needs and driving sustained shareholder value. With that, I'll now turn the call over to Jon to provide a financial update. Thank you, Toby. Good morning, everyone. I'd like to start with three quick reminders related to our reporting framework. First, Rockpoint reports on a fiscal year that ends March 31st and therefore we are reporting and discussing our first fiscal quarter for the period ending June 30th, 2026. We take this approach to align with the standard operation of the natural gas storage business, whereby injections typically occur from April to October and withdrawals typically from November to March. Second, Rockpoint's functional and reporting currency is U.S. dollars, and as such, all reported figures are presented in U.S. dollars unless otherwise noted. Third, all quoted results reflect OpCo level performance on 100% basis, of which Rockpoint Class A shareholders hold a 40% ownership interest. Turning to our first fiscal quarter 2027 results. We delivered a quarterly adjusted gross margin of $93 million compared to $96 million in the prior- period. The results were driven by higher take-or-pay revenue offset by lower optimization revenue. Importantly, our stable contracted fee-for-service gross margin grew by 4% year-over-year, supported by 6% take-or-pay gross margin growth. Adjusted EBITDA for the quarter was $75 million compared to $77 million in the prior- period, with the variance primarily attributable to changes in adjusted gross margin. Our quarterly distributable cash flow totaled $48 million relative to $47 million in the same period of fiscal 2026. Rockpoint expects to continue reinvesting in excess distributable cash flow through organic capital projects, accretive strategic investments, and opportunistic repurchases of Class A common shares. Lastly, our net earnings for the quarter were $57 million compared to $48 million in the prior- period, with the results benefiting from lower financing costs. Overall, our results continue to reflect the strength and stability of our contracted business model while demonstrating our ability to create additional value through optimization activities over time. Given this is our first year as a public company, I would like to briefly explain how value is created and recognized within our optimization business. As quarterly results can be impacted by timing differences and gross margin recognition associated with inventory carried over from prior- periods. This growing revenue strategy delivers gross margin capture across a range of market conditions, while also providing upside potential during periods of elevated price volatility. Importantly, quarterly optimization realized gross margin results can fluctuate due to seasonality and revenue recognition timing. This dynamic is particularly prevalent in the first half of our fiscal year, when Rockpoint primarily purchases and injects natural gas, while withdrawal and sales activity, which ultimately drives gross margin recognition, is generally small. While economically accretive overall, this activity can result in low or negative quarterly gross margin recognition in certain periods due to inventory blending impacts that temporarily cause the weighted average cost of gas to exceed the sale price in the period. Ultimately, it's important to note that these dynamics do not reflect weaker underlying business performance or unhedged risk, but rather timing differences between economic value creation and quarterly reported gross margin recognition. Optimization activities are entirely discretionary. We execute transactions to lock in incremental gross margin on a de-risked basis. Optimization gross margin performance should be assessed on a last 12-month basis as timing-related impacts offset over time. Overall, our focus remains on maximizing long-term shareholder returns, not short-term quarterly outcomes. I'll pivot to our balance sheet, which continues to be strong, reflecting consistent cash flow generation and conservative financial policy. We ended the quarter well below our long-term leverage target of 3.5x, with net debt to adjusted EBITDA leverage of 3x on a trailing 12-month basis, reinforcing our commitment to financial discipline. Our net leverage provides financial flexibility and positions the company well to pursue and self-fund organic growth opportunities and other accretive capital allocation initiatives. In terms of capital allocation, our approach remains consistent and focused on maintaining financial flexibility while delivering attractive long-term total shareholder returns. First, we remain committed to maintaining a strong balance sheet. Next, we aim to invest in higher return capital efficient broad brownfield projects to grow our distributable cash flow and dividends. Beyond that, our focus will be to return capital to shareholders through a sustainable and growing dividend, as well as share buyback activity. We expect buybacks to be most active when we see a meaningful disconnect between Rockpoint's share price and the intrinsic value of the business. The pace and magnitude of those buybacks will remain disciplined and opportunistic, driven by corporate liquidity, market conditions, relative return opportunities, and growth capital needs. Longer- term, we'll be disciplined and consider deployment of capital to strategic greenfield or other broader initiatives. Overall, we are a highly cash generative business with a conservative payout ratio, and we will continue to allocate capital where we believe it will deliver optimal risk-adjusted returns for our shareholders. Lastly, we remain committed to delivering a competitive annual total return of 15% over the long- term. Our total return profile entails three components. First, 5%-6% distributable cash flow growth driven by growing storage rates across our portfolio. Second, distributable cash growth of 4%-5% underpinned by continued investment in capital efficient, high return organic growth projects, as well as other alternative forms of return of capital. Third, an attractive dividend yield backed by a conservative payout ratio. That concludes my remarks. I'll pass the call back to Toby. Great. Thanks, Jon. The broader strategic importance of North American energy and global markets continues to increase. This importance is only intensified in light of the ongoing geopolitical disruptions in the Middle East, which has severely constrained global energy supply chains. Countries across Asia and Europe are increasingly looking to diversify and strengthen their energy security by turning to North American supply. At the same time, energy demand is accelerating across North America, driven by the convergence of several long-term trends. Coupled with the constrained natural gas infrastructure, these trends are contributing to structurally elevated natural gas market volatility, which is, of course, constructive for our business. Looking ahead, we're excited about our journey to unlock long-term value for our stakeholders, and we're confident that our assets will continue to play an essential role in enabling our customers and pipeline partners to balance the growing and evolving energy needs of the communities and the regions where we operate. On behalf of Rockpoint's Board of Directors and management team, I want to thank all of our stakeholders for their continued support and partnership. With that, I'll turn the call back over to the operator for the Q&A session. As a reminder, to ask a question, simply press star one on your telephone keypad. Our first question comes from the line of Maurice Choy with RBC Capital Markets. Please go ahead. Thanks, good morning, everyone. Just wanted to start with the Alberta contracting update that you'd given us, where you had early discussions than typically. You mentioned that take-or-pay in Alberta, this contract will help increase the take-or-pay by about 30% year-over-year. Can you add a little bit more color on this, including term storage rates, what this means versus history or your expectations? Also with that, when you think about a counterparty for this contract, is it one existing one that's responding to changing fundamentals or is it a new one, for example, in the LNG or the data center sector? Thank you. Yeah. Thanks, Maurice, for the question. I'll kick off here. I think ultimately in terms of that disclosure, we are again, very pleased with execution of this contract. We think that demonstrates our ability to execute on our commercial strategy as we've discussed in the past, ultimately to transact incremental take-or-pay and convert short-term storage contracts in Alberta to take-or-pay contracts with term. Ultimately, this is a long-term contract. As you're aware, last quarter we disclosed a weighted average term on our take-or-pay across the portfolio at three and a half years, certainly this contract will help increase that overall contract tenor across the portfolio, which we're very pleased about. In terms of the additional detail on pricing or rates, we are not planning on disclosing specific contract terms such as pricing, obviously, given commercial sensitivity, but we can say that the rate was consistent with our expectations and supports our target of 4%-5% EBITDA growth driven by price over the long- term. Again, this does demonstrate with the early execution of this counterparty, they are a new customer to AECO, which is encouraging. We view that as a new customer contracting for size over the long term, extending the tenor of our take-or-pay contracts, and believe it's indicative that customers are also now sharing our view of a tighter and more volatile WCSB gas market, again, driving higher storage scarcity and value over time. Appreciate the question. Thanx, Jon. If I could just finish off with the comment you made about optimization during the quarter. You noted that this is more of a timing difference. You mentioned that philosophically, this is entirely discretionary and you wouldn't enter into this unless there's obviously a net benefit to gross margin. Can you just elaborate more about the gas price dynamics that you saw during the quarter, whether or not you continue to see that into this current quarter? You mentioned that performance is assessed on a trailing 12-month basis. Is it fair to say that these transactions will ultimately improve your fiscal 2027 results? Yeah, thanks. Sure, Maurice. Maybe just on that last bit there, the dynamic that we saw, I'll go into a little bit more detail, ultimately in what drove the timing differences was more of a dynamic between Q4 and Q1. Ultimately, keep in mind, our optimization strategy is 15% of our overall business, 85% being our fee-for-service, take-or-pay in STS. We believe our optimization strategy is a very strategic one, whereby we are able to ultimately capture value from various market conditions and be nimble in the cash and forward markets. Irrespective of whether pricing is increasing or decreasing. We can leverage our physical assets to capture value. To address your question more specifically, the conditions that we saw, primarily in California, was obviously following a mild winter last quarter. We did carry forward across Q4 to Q1, roughly 27 million dekatherms of natural gas inventory from the winter period into the summer injection season. Why was that gas carried over? It was because our asset optimizers were able to realize an opportunity to transact incremental positive gross margin by buying back previously scheduled withdrawals in the winter as a result of depressed cash pricing and hedge positive gross margin capture into the summer. Really the dynamic at play here, which I'll reiterate, is not uncommon in the storage industry and becomes, although immaterial, a bit more prominent because we're a pure-play gas storage operator. Was one because of, again, the carryover of inventory impacting our weighted average cost of gas. That's great. Thank you very much, Jon. Thank you. Your next question comes from the line of Rob Hope with Scotiabank. Please go ahead. Morning, everyone. Do appreciate the commentary on the 10 Bcf of storage in the Alberta market. I did want to though go back to the kind of commentary that you are seeing, we'll call it increasing engagement from customers. Can you maybe provide any incremental color on whether or not there are more, we'll call it chunky, take-or-pay contracting opportunities, I would imagine more in Alberta that are kind of lurking around that we could see, or even California. Just want to get a sense of kind of what the pipeline looks like now versus in prior- years. Thanks, Rob. If you look at our last three contracts, all were new counterparties and all were significant contracts coming into the Alberta market, for example, for call it the first time. That's encouraging. I think it's a testament to the North American market realizing that the WCSB is on the brink of looking what we think is a lot like the Gulf in 2014. You've heard us speak to what happened when LNG arrived in the Gulf and to where it has grown today. We're seeing a lot of similar characteristics here as LNG Canada ramps up. We have yet to understand the full impact of what AI and data center demand will do to this market. It's broadly viewed that volatility increases are coming. The only real true hedge against some of that volatility increase is through insurance, which is through natural gas storage. We're witnessing that broadly across the board. We are having continued negotiations with a handful of other, call it larger counterparties. We're also having those contract conversations with smaller counterparties. Different folks are looking at natural gas storage for different reasons. One of the major trends that we are witnessing this year is people looking for natural gas storage to protect against downside movement. Conventionally, we saw natural gas storage being used mostly as an insurance to protect against price spikes in the winter. Today, many of the users in the WCSB are using it for operational purposes, driven by LNG. LNG themselves use natural gas storage to protect against operational integrity and often need natural gas storage for quick injections as opposed to conventional users who need it for quick withdrawals. Broadly speaking, the market share is going to get taken up by different users of natural gas storage. With all of the infrastructure development that we're seeing creeping into both markets. We're continuing to see increased volatility day- by- day, month- by- month. Things are looking still really great for natural gas storage. All right. Appreciate that. Maybe moving over to Warwick and the gas storage expansion there. What specifically do you need to see to move from 3.5 Bcf to the ultimate 5 Bcf number? Then beyond that, what additional incremental opportunities do you see there? Hi, Rob, it's Scott Aycock. Excuse me. I think we just want to monitor the reservoir this winter, see the performance and likely look at some optimization, either through new drilling or compressor modifications to increase the capacity there. I'd just add, in line with previous discussions, Rob, this is a perfect example of a small scale capital, quick to execution and commercialization brownfield project that's highly accretive. As you know, we acquired the mineral leases and well and pipe infrastructure at nominal cost and have undergone this conversion, fold it into the Warwick scheme here with the update on the AER regulatory approvals. As Scott mentioned, there's a few things around the edges that we are looking to do, again, with very little incremental capital to unlock more working gas capacity, which can be very valuable in this market. In terms of your other question, what else is available? The team is working very hard to continue to advance other brownfield projects across our portfolio, both in Alberta and California. We're encouraged by the progress that continues to be made quarter-over-quarter. I think in line with our previous communications, we will certainly provide the market with project updates when applicable. Overall, our outlook and expectation on, again, deploying up to $150 million of brownfield capital, targeting that average four to six build multiple range, is intact and our team's making great strides. Thank you. Your next question comes from the line of [Varun Reddy] with JP Morgan. Please go ahead. Hey, good morning, guys. Since last quarter, I think there's been some positive developments as you guys mentioned, specifically on the data center side, but also in crude egress in the WCSB. Curious if there's any been, understand the customer perspective, but from your guys' fundamental view, any changes in terms of the pricing you guys think about in the outer years? Yeah. Thanks very much. That's a great question. In fact, we've been reflecting on this quite a bit lately. Natural gas storage, of course, it's a very logical way to draw a correlation towards the need for natural gas storage with growing natural gas infrastructure. We're seeing significant expansions being announced by a number of key parties in North America over the 5 to 10 years. That said, in the northern part of North America, we're even seeing possibly more growth come by way of increases in expansion on the crude oil side or the condensate side. We can't understate that all of it matters. To the extent that there's increases in crude infrastructure, that ultimately could lead to even further egress issues with natural gas, which has been, at least in the last couple of years, a major trend where natural gas prices have gone down to discounted levels as a result of the value increase from either the condensate NGL or crude itself value. All infrastructure expansion is good for natural gas storage. The fact that natural gas storage cannot keep up to infrastructure expansion in most ways, especially in conventional natural gas storage infrastructure, is great for the increased scarcity value of what we bring to the table. All infrastructure expansion will ultimately result in higher volatility. That higher volatility, whether it's from price discounting or price spikes, is great for our business. Great. Thank you for that. Next one maybe for Jon. I had a question. Your capacity to lean into buybacks at current levels. Understand you guys have balance sheet in a great place and organic growth opportunities thereafter, curious if you could speak to the willingness to execute further at these levels. Yeah, appreciate the question. You're bang on there. We do view our buybacks as an important tool within our broader capital allocation framework, ultimately to enhance shareholder returns. Keep in mind, Rockpoint is a highly cash generative business. With 80% + EBITDA margins and a 65% distributable cash flow conversion, we pay out about 50% of our distributable cash flow, and therefore are well positioned with excess cash available and liquidity to, like you said, pursue both organic reinvestments and other forms of return of capital, like buybacks. We do view the buyback strategy as accretive and a risk-free use of excess cash. For perspective, since the start of our buyback program in early June, we've repurchased roughly $18.5 million of shares on 100% basis. That's driving roughly 1% distributable cash flow per share growth. As you mentioned, we certainly believe our buyback strategy reflects our confidence in the business and strength of our assets, cash flow profile, and ultimately our outlook. That is a tool in our toolkit which we certainly will continue to consider going forward. Again, consistent with our capital allocation strategy, as you've seen us execute upon the last couple of months. Great. Thank you for that. Your next question comes to the line of Aaron MacNeil with TD Cowen. Please go ahead. Good morning, all. Thanks for taking my questions. Toby. Yeah. Mentioned a large renewal year in California in your prepared remarks, and I'm just hoping to revisit that dynamic for the 2027 fiscal contracting year in a bit more detail. I get that you won't speak to specific contract terms, but how would you characterize the rates and durations signed in the most recent contracting season versus the prior- year and versus the sort of legacy contracts that rolled off? I ask because at the IPO, one of the key elements of the California story was that these legacy contracts would roll off, and then you'd sort of roll into higher prevailing rates. Just given the, as you say, the materiality of all the contracts that came due, I'm hoping you can just help us better understand all the moving pieces. Yeah. Thanks, Aaron. I think, in our financial statements, we have a revenue note, which does show ultimately the breakdown in Q1 2026 relative to Q1 2025 of our take-or-pay gross margin by region. So, there, if you compare in that table, we're showing almost a 5% growth of take-or-pay in California specifically. Based on some of our previous public disclosures in our Q4 press release indicating the relatively flat year-over-year take-or-pay volume, clearly that growth is all driven by price. So to your point on us executing on recontracting and seeing the overall realized take-or-pay gross margin contribution and rate increase, I think that's indicative of that. Just to reiterate, California is a 70% take-or-pay business as it relates to the overall gross margin contribution of that region. It still very much is a mature market for us and one that we've contracted heavily into over the last couple years. You're bang on with the call-out on the renewal activity as well last year. That's one thing, an aspect that our marketers are very cognizant of. Given that last year's recontracting for fiscal 2027 was roughly three times the renewal volume as a normal year or in fiscal 2028 in California. We're very proud and pleased with the execution of that in California. Just to follow- up on California market fundamentals, just a reminder for other folks. The Costa Azul LNG facility is a major disruptor in the region. That facility, which will take up to 300 million a day, is going to compete with the supply that goes into Southern California that ultimately has an impact on Northern California natural gas prices and volatility. I believe it's been announced that that facility has had a couple of issues and is now delayed until November, which could impact prices to the downside for the rest of summer into the early fall. Further, looking to the north, the PG&E system is one of the highest demand systems for AI and data center demand. I think there's up to 12 GW of AI-related demand in the queue. While we do believe that the majority of that will be serviced by renewables, every single bit of that growth needs to be backstopped in some form. We view natural gas volatility, natural gas fire generation demand in the state continuing to enhance the value of those long-term contracts, [Aaron], on a macro basis. We really like our position in California and our role there is critical. We serve a growing demand sector, even if natural gas specifically itself isn't growing in demand. That's super helpful. Thank you. I want to switch gears to the CPUC change of control process. I know you can't comment on what Brookfield may or may not do with the Class B shares. From a purely technical standpoint, I've noticed in the CPUC filings that you may not get that sort of change of control until February of 2027. Can you speak to what may constitute a change of control? Specifically, could Brookfield sell down its economic interest in the OpCos down to, say, 51% following the October 15th lock-up? Practically speaking, does this push back any potential secondary until next year? Thanks for the question. I guess first on timeline, as you aptly noted, the February timeline in their disclosure. We, as well, obviously saw that date, and I'd just say in terms of timing, keep in mind they're not bound to that date. However, that timeline is consistent with what we've communicated in the past, and that the expectation is for that decision to be in the first half of calendar year 2027. Then I think, as it relates to Brookfield's remaining 60% ownership in any decisions going forward, that's obviously not something that Rockpoint can comment on in terms of their intentions. As they've shown, I think ultimately the expectation, if they were to pursue, would be some kind of orderly transaction. Again, do not want to speculate on their behalf. Ultimately, the change of control application does need to be approved in order for them to sell down below that 50% target. In terms of the October, that being the lifting of the 12-month lockup on the exchange agreement, again, can't speculate on that. Again, we'll point you to the timelines that we've discussed in the past on the change of control approval. Great. Fair enough. Thanks, guys. I'll turn it back. Thanks, Aaron. Your next question comes from the line of Patrick Kenny with National Bank Capital Markets. Please go ahead. Yeah. Hey, guys. I guess we have seen at least one large gas producer announce a bit of a pause on growing its production volumes. I appreciate the comments around liquids rich drilling activity continuing. Just wondering how you might be viewing perhaps a slightly more flattish gas production profile in Western Canada, at least over the near- term, just in terms of maybe pushing back that 60% medium-term take-or-pay target, or what other dynamics might be at play here to keep your outlook intact for locking in additional take-or-pays, including with LNG-related customers. Yeah. Thanks, Pat. We hear from time to time that production's going to remain flat. The evidence hasn't really shown that to be the case. We do see, for the most part, opportunistic taking of white space when one producer elects not to produce and allowing for another. I point, in this case, just towards the overall value of the NGLs in Western Canada. While one producer might be going after one target, another producer may have a strategic value of going after another, and therefore the oil price might be the bigger driver as to why they might take up that white space and/or other liabilities that producer may have. More than ever, we've seen producers vertically integrate in North America. They're taking out transport positions. They're entering into offtake arrangements with LNG facilities. They're taking out storage. This is a new trend that we've seen over the past couple of years. It ultimately drives a different type of behavior as far as how they operate on a daily basis. That said, the infrastructure continues to be tight. In the north here, NGTL continues to go through a variety of upgrades to their system. We're seeing continued curtailments. There's curtailments in the east and the west, for example, that are outside of our jurisdictions that are impacting price today in a bearish way. We saw prices this morning in Alberta net go to CAD 1.30. That's off of a maintenance that's occurring both out east and in the west, as well as on NGTL. There's so many factors that drive volatility outside of increasing production or increasing demand. At the same time, we're continuing to see more wildfire risk than we've seen. The last decade has seen a proliferation of wildfire risk. That has an impact on both production and demand. We're seeing that across the entire west with how hot things are this year, and now we have an announcement of a Super El Niño, which could put further pressure on those regions with drought. There's just so many variables that drive volatility, and lastly, something that we haven't really spent a lot of time on volatility in the west, LNG Canada has had three, four months of flaring. At some point when that flaring activity is not allowed anymore, it's going to contribute to even more volatility on the pipelines, and that's going to push gas ultimately, in our view, on a more frequent basis into Alberta and Alberta storage facilities, including Rockpoint, are going to benefit from that volatility. Just so many different variables, it's really hard to point to one that we rely on. We're broadly speaking of the view that enhanced infrastructure and enhanced volatility is here to stay. Got it. Okay. Thank you for that color. Then maybe just an update on the M&A landscape, particularly in the Gulf Coast. There's still obviously lots of momentum on the LNG export front there, and I'm just wondering if you're seeing even further acceleration in demand for brownfield or even greenfield expansions, and if that's, I guess, creating an increased opportunity for incumbents like yourselves, North American operators to step in and accelerate some development down there. Just maybe how you're thinking about Gulf Coast as an investment opportunity relative to, say, accelerating share buybacks going forward. That's a really great question. Agreed, that is what we are seeing. On just conventional natural gas infrastructure alone, we're seeing a bigger increase in the South, ultimately in the Gulf region, than we're seeing in the North, and that's mostly because of LNG. It's also because of AI and data center opportunities. And the reality that producers are able to team up with end users to create a supply/demand pipeline. Those pipelines are being backstopped by the various incumbents, and they are, because of salt proliferation in the Gulf, allowing for potential new storage expansion. We're really encouraged by the inbounds that we get in that regard. Since going public, the markets maybe understand our role a little bit differently than they did when we were private. And as a result, we've got a variety of partnership and expertise inquiries into how we might facilitate storage expansion. Particularly, those calls come in that region, and we are encouraged by some of the developments there. That said, our brownfield pipeline is continuing to evolve. Our California assets and our Alberta assets all have multiple opportunities for some limited, albeit limited, storage brownfield expansion. We've got, certainly, the customer demand and the price signals coming into the market to move forward with some of those projects, which we'll hope to give you more color on as the year progresses. Big picture, yes, we do like the Gulf. It's one of the great storage markets in North America. It's not that we don't like the Northeast and the Midwest. They're great places to operate as well. Just the opportunities are a little bit more limited due to the mature infrastructure and the reality that most of the caverns for storage are conventional in nature, which adds an element of difficulty on bringing new projects to market. Okay. I'll leave it there. Thanks, Toby. Your next question comes from the line of Robert Catellier with CIBC Capital Markets. Hey, good morning, everyone. I just wanted to go back to Alberta for a second and that new contract. I think you indicated that it increases your currently contracted capacity by 30% for 2028. How much remaining uncontracted capacity do you have in Alberta for fiscal 2028 marketing? Should we view this contract as an indication of a broader step change in contracting activity in Alberta in general? Hey, Robert. Thanks for the question. Sorry, I think I heard the question correctly, but ultimately you were curious. We were highlighting the 30% increase with the addition of that new 10 Bcf per year contract relative to take-or-pay levels in Alberta in fiscal 2027. For further context, as you're aware, we've communicated at a high level that in the past that California as being 70% take-or-pay. Alberta historically has been closer to that 20% or just under. Hopefully that gives you can connect the dots on the relative size of this new contract. I think ultimately in terms of our messaging, this was one consistent with your initial thought or reaction there. We think it's not just the contract, it's the indication of ultimately, again, new customers entering this new market with AECO at Rockpoint. It's a large contract of scale for term and checks the box in terms of what we have been looking for. We still think that Alberta is very much in the early innings of a continued growth phase. We're excited to kind of accelerate into that with further take-or-pay contract activity over the coming years. So to sum up our comment, as Toby alluded to earlier, our take-or-pay target, that being 60% of our overall gross margin contribution over the medium- term, we continue to feel very good about. Okay. That's pretty good color. As you're seeing new customers, and even existing customers transact, it seems like they're going for contract duration here, but is there any need for greater flexibility or what's the relative sensitivity to pricing compared to prior cycles? Great question. If you look at Alberta, conventionally speaking, the market wasn't as concerned about flexibility as it was about price. It was driven predominantly by the needs of merchants and marketers in the old days, providing balancing services to end users in other markets such as in Ontario, Midwest, Northeast, and the West. Today, led by California, but also ultimately driven really by the arrival of LNG in the Gulf, the operational users of natural gas storage not only are demanding a higher degree of service and reliability, but they're also taking away market share from conventional users due to the way that they reserve that capacity. That reservation, that insurance requirement, has changed the landscape on how folks use natural gas storage. In the Western Canadian example, which you point to, we envision it looking a lot like the Gulf did 10, 12 years ago. As a result, we are witnessing a higher demand for more bespoke, higher deliverability contracts in our portfolio than those conventional contracts. The price elasticity to getting that service is not happening to the extent where we're trying to figure out ways to develop salt in the WCSB, but we're witnessing more and more demand for bespoke high deliverability contracts. Customers, at this point, appear willing to pay that. It's our view that we're in those early innings that Jon and I point out, that we're going to look a lot like the Gulf if things continue down this path. The most recent contracts, just another encouraging measure of our thesis. That's helpful. One last one. I was just curious, I think you rightly touched on the condensate story and obviously liquid targeted drilling is going to have some associated gas with it and have an impact on the market. Is that something you're seeing in discussions today, or is that something for three to five years down the road? Maybe another way to ask the question, what do you think is going to drive contracting in Alberta over the next three years? LNG, I think, is going to create the first shot across the bow for scarcity. Folks are aware it's happening. I would say, the needs of producers are definitely creeping into the market. That vertical integration that I spoke about is a newer trend. Are producers willing to forego that much needed income in the summer? To be determined. Operational flexibility has to have a balance, with respect to how they run their working capital. The AI data center one, I would say right now, is really surprising as well. This is a fast moving business. We're getting a number of inbounds with folks willing to pay for flexibility. In the particular case of just backstopping a development is their first priority, I would say. Some have already moved into operational thinking where they're of the view that if they can get in early to natural gas storage contracts, can they get a discount relative to what it will look like in, say, a year or two years from now? Those strategic thinkers are also arriving at the table. I would say LNG will be the first driver in the WCSB, followed by AI and data center development, probably with the third category, by way of folks just looking to dispose of gas due to oil targeted drilling. Quite frankly, the third category probably will get taken care of by the merchants. There's a highly sophisticated group of marketing and merchant players in the WCSB that understand this really well. Among the services they provide is just egress of any form. A lot of them own storage in order to help their customer base deal with the changing needs of energy today. The three all, from our perspective, converge towards increased values. A lot of really interesting discussions, and we're having a lot of fun with the strategic discussions in particular, especially the ones around AI, which are really starting to show up more than they did five, six months ago. Okay. Thanks so much. Your next question comes from the line of Ben Pham with BMO Capital. Please go ahead. Morning. I wanted to go back to the California contracting outlook. I recognize the big renewals that you achieved for fiscal 2027. I was wondering if you can perhaps unpack the outlook a bit more. I am curious, respect to 2028 fiscal, you can share the renewal percentage that's going to be open. Are discussions typically in the fall, as well as number two, Alberta? Can you talk about the customers if there's any, not necessarily pushback, but is there any perhaps increasing discussions around price sensitivity and where storage rates are in California? Hey, Ben. Thanks for the question there. Yeah. I think, as it relates to the renewal, the point we were trying to make and it's in our press release there, is just ultimately the tightness and the scarcity, going into our forward year with significantly less renewal activity available, we think will drive more tension. In that market, as you know, the current users are more operational in nature, a bit more focused on the utility side. I think, ultimately, that's a dynamic that we think can be favorable when our marketers are entering into a recontracting season going forward. I think, consistent with previous commentary we've made in the past, o verall storage values are not just tied to a seasonal value, especially in that market. There is considerable insurance values put on the services that we provide because we are critical infrastructure to help balance the supply-demand in the region. I think that is one aspect where we run our spread option models to understand what current market inputs would suggest are applicable rates. We will go through our recontracting season in line with the original timeline, that being consistently more so in the fall in that market. In the meantime, as you've heard from both Toby and myself, we continue to remain constructive on the overall fundamentals in that market and the value that our customers place on our services, whether that's to protect their or their customers' interests or ultimately to participate in the market themselves. Maybe just to continue, you mentioned mild weather conditions as part of the last couple of years. Do we need to see weather conditions turn back to normal for increased activity on more contracts? Yeah. In the old days, the milder weather typically would result in higher intrinsic spreads or wider spreads, just due to the reality that there's a larger carryover from the winter to the summer period. The opposite, obviously, was true in other years. No question, California has had two or three fairly warm winters. At the same time, though, this year, for example, we saw prices arrive in California well below variable costs. We had natural gas prices this summer arriving in California below $2 on a sustained basis. That's natural gas that costs $1 to leave Alberta. The reality that customers of storage are able to participate in managing their storage opportunistically with very inexpensive injections and protecting themselves against high price events in the winter is as important to them as just having insurance against a high winter spike or having operational flexibility against other needs in the market. We continue to see, broadly speaking, consumer usage to be willing to pay more and more for flexibility. We also see our customers having success. That's a really important part of our renewals. When we talk about these large renewal seasons, of course, if they had three mild winters and had what they would call paid a premium and weren't able to use that for insurance, would they get approved to go and do it again? The reality is that they're making money. There's a balance there that we have to recognize at all times in our partnerships with our customers. The reality is that they're making money even in bearish years or low weather years because of distressed pricing that's crept into the North American market. Just broadly speaking, volatility just continues to increase is the message. A warm winter could be as important to natural gas storage as a cold winter. For us to be able to have a warm winter, which is forecasted, for example, with the Super El Niño forecast that the markets seem to accept, that could be really good for Rockpoint, where we're able to carry over inventory inexpensively into a prior season. That reduces our injection risk for the prior season. It reduces our overall operational costs. It also means that there's distressed pricing in the winter for the market to go into contango. There's so many reasons why a low-priced environment is as important to storage as a high-priced environment. Just a reminder that, yes, California has seen a couple of warm winters. A cold winter in California, in the past, has been really good for storage. The warm winters are looking at least as though they've been liquidating very similarly and overall, we welcome both. Understood. I had to respond to a couple of questions on the share buyback. You compared that relative to organic growth. Can you remind us about the, I think that the language is around excess distributable cash flow. Your stock price as I think is below what you've been buying stock previously this year. How do you think about your excess balance sheet capacity for share buybacks at this point? Yeah. Thanks, Ben. Consistent with our comments earlier, we are in a very strong liquidity position. We have an excellent balance sheet. We have CAD 70 million of cash on hand at year-end. Ultimately, as mentioned, share buyback activity, again, is just one other tool that we have to drive incremental shareholder return and one which we would continue to assess on a very periodic basis. As mentioned previously, the relative return on the various opportunities, whether it's this, whether it's brownfield deployment, et cetera. Again, we're in a very strong liquidity position with cash available to deploy brownfield capital per our schedule as well as consider other opportunities for a more fulsome return of capital to our overall shareholders. You identified our activity in June and July. Again, that's something that we'll continue to reassess and be a part of our strategy. Okay. Got it. Thank you. Thanks, Ben. There are no further questions in queue at this time. I would now like to turn the call back over to Rahul Pandey for closing remarks. Thank you all once again for your time, your interest, and for joining us today. We encourage you to contact our investor relations team with any additional questions you may have. We wish you a great day.