Good afternoon, ladies and gentlemen, and welcome to the Tidewater Midstream and Infrastructure and Tidewater Renewables Third Quarter 2025 Financial Results Conference Call. At this time, all lines are in listen-only mode. Following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star- zero for the operator. This call is being recorded on Thursday, November 13th, 2025. I would now like to turn the conference over to Ian Quartly, Chief Financial Officer. Please go ahead, sir. Thanks, Chloe. Welcome, everyone, to the joint conference call for the third quarter 2025 results of both Tidewater Midstream and Infrastructure and Tidewater Renewables. Joining me today is our CEO, Jeremy Baines, who will provide an update on operations during the quarter. I will follow with the financial results, and then we will open the line for your questions. This morning, both Tidewater Midstream and Tidewater Renewables reported results for the third quarter ended September 30, 2025. A copy of the news releases, financial statements, and MD&As may be accessed on SEDAR+ or on the respective company websites. Before we get started, I'd like to note that today's call is being recorded for the benefit of individual shareholders, the media, and other interested parties who may want to review the call at a later time. The recorded call will be available through SEDAR+. Some of the comments made today may be forward-looking in nature and are based on Tidewater Renewables' current expectations, judgments, and projections. Forward-looking statements we express today are subject to risk and uncertainties, which can cause actual results to differ from expectations. Further, some of the information provided refers to non-GAAP measures. To know more about these forward-looking statements, non-GAAP measures, and risk factors, please see the company's various financial reports, which are available on the respective company websites and on SEDAR+. I'll now turn the call over to Jeremy. Thanks, Ian. Thanks to everyone for joining us today. During the third quarter, we continued to advance our strategic initiatives, including the acquisition of the Western Pipeline, which successfully closed on September 25th. Across our portfolio, we delivered consistent operational performance in our midstream assets and solid financial results at Tidewater Renewables, all while executing planned maintenance and turnarounds to ensure long-term reliability and efficiency. I'll begin with Tidewater Renewables, followed by Tidewater Midstream, covering regulatory and strategic developments, operational performance, and maintenance activities, and followed by commercial updates. Starting with regulatory developments, on September 5th, 2025, the Government of Canada announced a CAD 370 million biofuels production incentive program to address the economic challenges caused by U.S. subsidies and policies. The incentive program is expected to provide per-liter support for qualifying Canadian producers of renewable diesel and biodiesel from January 2026 through December 2027. With the HDRE complex expected to produce between 150 million and 170 million liters annually during this period, Tidewater Renewables is well positioned to benefit once the program is implemented. In addition, the Government of Canada also announced its intention to make targeted amendments to the Clean Fuel Regulations to further support Canada's biofuel sector. We understand the government will develop the amendments in consultation with industry stakeholders this fall, and we are actively planning to participate in this process. Moving to operations at the HDRE complex, throughput during July and August averaged 2,920 barrels per day, or 97% of design capacity, prior to the scheduled turnaround in September. The turnaround was originally expected to last three weeks, but was extended by two weeks due to higher-than-anticipated bowing in the Hydrodeoxygenation reactor beds. Following the planned turnaround, there was a two-week unplanned outage during October due to an equipment anomaly, which was temporarily repaired to resume operations. Throughput has averaged approximately 2,330 barrels per day to date during November, with rates expected to return to full capacity in December 2025 after the affected component is reinstalled. Utilizing the learnings from the first two years of operations, including insights gained from this turnaround, we have optimized the turnaround schedule to extend the catalyst life to approximately two and a half years. This means that the next turnaround at the HDRE complex is planned for the spring of 2028, which allows us to maximize production during 2026 and 2027 while the biofuels production incentive program is in place. Lastly, for renewables, a few comments on commercial progress. We have significantly increased our contracted offtakes, which now cover 100% of forecasted renewable diesel production for the remainder of 2025. This compares to 70% of forecasted production for the second half of 2025, as disclosed in Q2. Looking ahead to 2026, over 80% of forecasted renewable diesel production is expected to be directed toward renewable diesel sales, inclusive of environmental attributes. All of these sales are structured with U.S. import- parity pricing benchmarks, aligning pricing with prevailing U.S. market values and reducing our exposure to Canadian emission prices. The remaining volumes are expected to be sold into the spot market, where current Canadian pricing remains favorable. Tidewater Renewables Regulatory Developments and Strategic Initiatives. Starting with regulatory and strategic developments, on November 12th, 2025, Tidewater Renewables executed an initiative agreement with the Government of British Columbia to provide BC-LCFS credits to support the production of low-carbon renewable diesel and renewable gasoline from the hydrotreater co-processing unit at the Prince George Refinery. These BC-LCFS credits are expected to fund approximately 50% of the cost of renewable feedstocks required to operate the hydrotreater co-processing unit during 2026 and 2027 at previously achieved rates of 300 barrels per day. In addition, the sale of co-processed low-carbon transportation fuels into the British Columbia market will generate CFR emission credits and additional BC-LCFS credits for Tidewater Renewables. On the strategic front, we closed the acquisition of the North Segment of Pembina's Western Pipeline System on September 25th, 2025. Now that the transaction has closed, our immediate focus is on integration activities and having our team take over operations of the pipeline in November. Once that occurs, we expect to be able to start realizing the expected operational synergies and the CAD 10 million–CAD 15 million of anticipated annual cost savings we announced previously. We also continue to advance our non-core asset sales program. On October 21st, the Sylvan Lake Gas Processing Facility was sold for cash proceeds of CAD 5.5 million. We continue to work on further divestiture opportunities, including growing market interest in repurposing energy sites for data-centered developments. We look forward to updating the market as discussions progress. Next, let's turn to the operations at the Prince George Refinery. Throughput at the Prince George Refinery averaged 10,313 barrels per day in the third quarter of 2025, a 4% increase from Q2 2025, though lower than Q3 2024 due to differences in feedstock composition and operational adjustments. The semiannual heat exchanger cleaning was completed in early October, and throughput levels have since normalized to approximately 12,200 barrels per day. As part of our ongoing maintenance optimization strategy, we have transitioned PGR to a five-year turnaround cycle with the next major turnaround planned for the second quarter of 2028. While refined product margins remained under pressure during the third quarter, driven by wider wholesale discounts and an oversupply of diesel in Western Canada stemming from U.S. renewable diesel imports and elevated regional refinery utilization, we are encouraged by the stronger crack spreads observed recently. Prince George crack spread averaged $90 during the third quarter, which increased to $93 for October and has been over $100 during November. These improving market conditions are expected to contribute to better realized margins in Q4 and into 2026. Now I'll move on to our broader midstream operations. At the DRC Gas Processing Facility, throughput averaged 124 million cubic feet per day in the third quarter, up from 95 million cubic feet per day in the second quarter of 2025. As disclosed last quarter, the increase was expected following the repair work completed at Plant 3 in late June. The Ram River Gas Plant remains temporarily curtailed. We have experienced record-low natural gas prices during the third quarter, and operations have not yet resumed. Once we see natural gas market conditions improve on a substantial sustained basis, combined with the more supportive sulfur markets we are experiencing, Ram River is expected to return to prior throughput levels, enhancing overall midstream gas processing capacity. Commodity markets in Western Canada remain challenging, with low ACO spot prices leading to selective shut-ins. However, we remain optimistic longer term as LNG Canada and other export projects ramp up, supporting higher forward ACO prices and renewed demand for processing capacity. Looking ahead, we remain focused on driving operational excellence, enhancing margins, and executing strategic initiatives, including maximizing efficiency at PGR and HDRE complex, strengthening commercial platforms and offtakes, advancing our SAP project while managing capital prudently, progressing non-core asset sales to unlock liquidity, and continuing to advocate for a fair regulatory environment. We believe these building blocks position us for both revenue growth and margin expansion during the remainder of 2025 and beyond, ensuring we continue to deliver value for shareholders while advancing our long-term strategy. With that, I'll now turn it to Ian for the financial review. Thanks, Jeremy. I'll begin with Tidewater Renewables' financial results, and then we'll discuss Tidewater Midstream's consolidated financial results. Tidewater Renewables reported a net loss of CAD 1 million during the third quarter of 2025, compared to net income of CAD 13 million for the second quarter of 2025. The decrease in net income is primarily due to two non-cash items, the first being a significantly smaller unrealized gain on soybean oil derivative contracts in the current period, and the second being a loss on the warrant liability revaluation, which resulted from the significant increase to Tidewater Renewables' share price during the third quarter of 2025. Adjusted EBITDA was CAD 16.5 million for the third quarter of 2025, a 54% increase over the second quarter of 2025, primarily due to higher contributions from the equity investment, which totaled CAD 7.9 million during the third quarter. As Jeremy mentioned previously, we continue to have success selling renewable diesel, inclusive of all the environmental attributes, which we call R100. There are a number of significant advantages to this commercial structure compared to selling the emissions credits separately, which I want to quickly highlight. The first benefit is that R100 sales result in faster cash collection and reduced working capital, as the total cash proceeds from the sale of the diesel and all the environmental attributes are received within a week or two of the physical sale. The second benefit is that R100 is priced off highly liquid and observable U.S. benchmark prices. In the future, we may hedge a portion of contracted R100 sales and the corresponding feedstock purchases to effectively lock in a gross margin on contracted sales. The third benefit is that our customers are used to purchasing under this commercial structure, as it mirrors how they purchase the import alternative. As a result, Tidewater Renewables expects to sell over 80% of forecasted 2026 production as R100. Turning to Tidewater Midstream, the third quarter consolidated net loss attributable to shareholders was CAD 34.1 million, compared to a consolidated net loss attributable to shareholders of CAD 16.3 million for the second quarter of 2025. The increase in net loss is primarily due to the unrealized gain on derivative contracts that was recognized in the comparative period. Consolidated adjusted EBITDA was CAD 16.2 million for the third quarter of 2025, consistent with the CAD 16 million reported in the second quarter of 2025. The higher contribution from the equity investment in the third quarter was offset by lower midstream margins resulting from the historically low ACO pricing and higher corporate costs. On September 30th, 2025, with the support of our syndicate of lenders, the Tidewater Midstream Senior Credit Facility was amended to waive the requirements to comply with the quarterly financial covenants at September 30th, 2025, and December 31st, 2025. The amendments provide Tidewater Midstream with added flexibility as we continue to execute ongoing strategic initiatives. Finally, on August 28th, 2025, following the special resolution approved by the Tidewater Midstream shareholders at the May 27th, 2025 annual and special meeting, Tidewater Midstream completed a share consolidation on a 20-for-1 basis. Proportionate adjustments were also made to the conversion price of the corporation's outstanding convertible unsecured debentures, as well as the corporation's LTIF plans. That concludes our prepared remarks. Chloe, please operate the line for questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. To join the question queue, you may press star and one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star and the number two. We'll pause for a moment as callers join the queue. Our first question comes from the line of Rob Hope from Scotiabank. Your line is open. Good morning, everyone. Maybe on the CAD 370 million biofuels program incentive, how have discussions with stakeholders progressed on that? When could we see some additional clarity on that? Is the expectation that it will be in place for January 26, 2026? Yeah. We are waiting for the final release of the details, but they have clearly stated it will be in place for January 1, 2026. We expect to hear late this year or early in the new year, but the government seems very committed to this. They announced it in the fall economic statement a year ago, and with the announcement by the Prime Minister, it's all moving ahead. We are waiting for final details of exactly how it works, but it looks like it's going to be a very good support for the Canadian renewable diesel industry. Would you be willing to give an estimate of just assuming it is laid out as planned, how much of a benefit it will be in 2026 for LCFS? Yeah. We're not 100%. We haven't seen the final rules and regulations, so we don't know exactly what's included or what's not included. Based on us back calculating into the potential liters of production of renewable diesel and biodiesel that we see that could be in place for this program, our best estimate is it's somewhere between 15–21 cents per liter. All right. Excellent. Thank you. Once again, if you have a question, please press star and one. Our next question comes from the line of Maurice Choy from RBC Capital Markets. Your line is open. Thank you. Good morning, everyone. I am sort of coming back to the PGR move to a five-year turnaround cycle from four years previously. Can you speak to that position as well as if there is a trade-off in terms of utilization rate? For example, do you need to run at a lower rate in order to have a longer turnaround cycle? More broadly, I think you mentioned in your MD&A that five years is well within the industry norms. What was the reason why it was four years in the past? Yeah. That's a good question. Thanks for the question. It's hard for me to speak to a lot of the past practices, but with advances that are being made in catalyst technology and industry advances, we always are monitoring the performance of these things. We've seen many other refineries go to these five-plus-year turnaround cycles. We've been doing a very heavy risk sort of evaluated determination of, is this appropriate for us? We think we can go all the way without seeing impacts to throughput and yield. Obviously, we're going to monitor performance. We always monitor the performance of our catalysts and so forth as we go. There are a couple of sort of, call it critical spare pieces of equipment based on what we saw last turnaround that we might look to put on hand just to make sure that if something on that front went wrong, we could quickly address it. We are very confident that we have done the right risk-based approach, that we can make it without impacting throughput, yield, and that obviously this extends and lowers our maintenance CapEx at the refinery almost 20% over a five-year cycle. What was previously a four-year cycle is now very meaningful. It is pretty much industry standard, and we are managing it appropriately. I understand. Maybe as a quick follow-up, I guess, Jeremy, you're coming up to your two years as CEO here. I wonder whether or not, instead of comments about the past management, anything that you are now seeing that is worth changing in terms of whether it's turnaround, whether it's culture, whether it's people, anything of that sort that you want to tackle in your third year? Yeah. I mean, we've already made a significant amount of changes around people. I believe we made a lot of changes around culture, and we're focusing on it's continuing to move that focus on real cash flow generation and efficient and reliable operations at our facilities, making sure we're doing the appropriate risk things and coring up our assets to make sure that all the assets are actually generating an appropriate return or that we're turning them into cash. It continues. When you start looking at the long list of changes we've made in, I guess, almost two years, maybe call it whatever, 19 or 20 months that we're at now, it's continuation of that program. There were a lot of things that needed to be changed, and we've made a lot of progress, and we're going to continue that path. Understood. If I could finish off with, I think, Ian, you made a comment about the benefits of selling your production as R100. Can I ask what was the obstacle from selling this as R100 in the past that perhaps has changed to allow you to do so now? Was it a strategy decision not to do so in the past? Yeah, Maurice. The reason we did not previously sell R100 is we had the contract with Tidewater Midstream to sell essentially all the LCFS credits produced from July 2024 to March 2025 under the transaction that was completed kind of mid-2024. We could not produce a fully loaded barrel. That ended in April, and we essentially transitioned to R100 sales from that point forward. Understood. Thank you very much. Just one other piece, I guess, to add to Ian's. The change in the law on the Canadian renewable mandate made it a little bit easier to do that as well. It is extremely helpful for the business and to keep sustainable, reliable cash flow throughout the year with a quick gas cycle. There are no questions at this time. I would now like to turn the conference back to Mr. Colcleugh. Please go ahead. Thanks, everyone, for joining the call. The team is available to address any outstanding items with their contact information at the bottom of each company's press release. Thank you. This concludes today's conference call. You may disconnect your lines. Thank you for participating and have a wonderful day.