Peyto Exploration & Development Corp.

Good day, everyone, and thank you for standing by. Welcome to PaytoSupport Quarter 2024 Financial Results Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question-and-answer session. To ask a question during this session, you will need to press star 1-1 on your telephone. You will then hear an automatic message advising you in your hand or face. Please be advised that today's conference is being recorded. I would now like to send the conference over to Mr. J.P. Lachance, President and Chief Executive Officer. Please go ahead, sir.

Thanks, Olivia.

Good morning, folks, and thanks for joining Payto's fourth quarter and year-end 2024 conference call. Before we begin, I'd like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory set forth in the company's news release issued yesterday. Here in the room with me to answer your questions today is Riley Frame, our VP of Engineering and Chief Operating Officer, Tavis Carlson, our CFO, Lee Kern, our VP of Drilling and Completions, Todd Burdick, our VP of Production, and Derek Zember, our VP of Land and Business Development. Before we discuss the quarter and the year, on behalf of the management group, I'd like to thank the entire PAO team, both in the office and in the field, for their contributions to a great quarter and a very strong year. We hit some real highs last year, which are detailed in the year-end press release from last night and the recent reserves report release in February. But I think what's most important takeaway is that we delivered on what we said we were going to do with the Repsol assets after making that significant acquisition in late 2023. So this time last year, we were already drilling some great wells. That continued through 2024 where we drilled a total of 41 gross wells on the old Repsol lands. That represents about 55% of our total of 75, and the outcomes from those wells exceeded our expectations by delivering a sustained 40% production improvement over our legacy programs, and combined with the near flawless execution in the field, helped the company deliver some outstanding PDP, FD&A costs in 2024 of a dollar in MCFE. On the production ops side, the team spent a lot of time redirecting gas molecules to different gas plants in the field last year to improve deliverability, and liquid recovery, but they were also able to improve on the cost by simplifying the operations out there. We saved some third-party fees on low-value ethane liquid recovery, and we moved that gas instead to the Edson plant to preserve the rest of the liquids. We also shut down the sour gas processing side of the Edson plant. And this was a big part of getting our operating cost reduction from $0.55 per MCFE in Q1 down to $0.50 per MCFE in Q4. And it resulted in improved netbacks, despite the fact that we lost about 3,500 barrels a day of base production to Atena. Lots to be outdone though. Our legacy lands last year delivered some great results too. We drilled a new flare trend right in the heart of Sundance and completed a couple of CAQA flare wells near the end of the year, which came in as expected. The team assembled those CAQA lands over the last few years through a series of crown sales and swaps with other producers. We've always had a large cardium position in CAQA, and these new Spirit River lands along with our gas processing plant really complement that. We'll monitor the performance of these wells, and then we'll go back and we'll drill some more to keep that plant full, perhaps later in the year. Over time, if we continue to like the results of those wells, we can expand the plant from 25 to about 50 million cubic feet a day to match our sales egress in the area. Then we'll increase the drilling activity accordingly. With the improvement of U.S. gas prices in Q4, the team continued to bring on new production, and we set a record of 133,000 BOEs a day in the quarter, and we achieved our target exit production of 136,000 BOEs a day in December after deploying $457 million of capital, which is near the low end of our guidance last year. This translated into a trailing 12-month capital efficiency of approximately $9,700 for flowing BOE, which is one of the strongest in our history. On the financial side, we pulled in roughly $200 million in funds from operations, or a dollar a share, in the quarter, and thanks to cash costs of $1.36 per MCFE, which is the lowest since Q3 of 2023, which is just before the Repsol acquisition, and a good net sales price of $4.28 in MCFE, thanks to our hedging and the gas market diversification in our liquids, despite the fact that the equal daily price for the quarter was only $1.40 per GJ. All this culminated into a great year with strong revenue and low overall cash costs, delivering a 64% operating margin, despite it being one of the worst average annual prices at ACO on record. When you look at our netbacks as compared to our finding costs, we achieved a solid 3.3 times field netback ratio, where if you throw in all of our cash costs, including our taxes, that ratio turns to be about 2.6. By either measure, We think that's a very effective use of shareholders' capital. We delivered a record amount of dividends in 2024 of $258 million to shareholders, and we still managed to pay down a little bit of debt. On the marketing side, obviously, our hedges did us well last year. Recall, we put those on over the last three years, and that, combined with our U.S.-priced market exposure, helped us, especially in the fourth quarter, achieve better pricing than ACO. As we look forward, We have hedged 480 million cubic feet a day for this year and 366 million cubic feet a day so far for next year at prices over $4 in MCF. And to put that into perspective, the hedge book, including some liquid hedges that we have, has secured $850 million of revenue for 2025. What's not secured is mostly floating on markets that price in U.S. dollars in Ontario and the U.S. Midwest and, of course, the Cascade Power supply deal. We still have a little bit of echo exposure through our exposure or through our EMPRESS service. If you look out beyond 2026 at our diversification portfolio, it looks really strong. I would encourage you to check out our marketing slides on the website or in our corporate presentation, and they've all been updated as of last night. One example of the quality of this book is where we have roughly 70 million cubic feet a day of gas volume that's exposed to Henry Hub through basis deals that are priced at 76 U.S. per MMBTU. And when you look at Henry Hub 2026 summer futures, currently trading at U.S. $4.17 for MMBTU U.S., this nets us back about $4.60 a gigajoule at ACO when you subtract the basis and convert the units and the currency, which is about $5.30 per MCF with our heat content. That compares to the current price at ACO on the strip at about $2.89 GJ. We continue to acquire service like this to locations where most recently I made an arrangement to add 30 million cubic feet a day of physical dawn exposure starting in November 2025 for a long-term deal, which costs us roughly $1.15 per GJ to get there. Right now, winter 25-26 at dawn is worth US $4.78 per MMBTU, or about $5.28 per GJ landed in Alberta after you improve the tolls, after you subtract the tolls and do the unit conversions. So that's $6 in MCF with our heat content. When you combine that new service with our recent Parkway deal, we have about 70 million cubic feet a day exposed to that market. And on top of that, we also have Chicago, Emerson, a little bit of Ventura, and Millen as well, exposure. Of course, we can hedge these markets, and we are, or we can let them float. But either way, the marketing diversification portfolio we have assembled looks pretty darn good. So all these different sales points in our mechanical hedging program that helps de-risk our revenues, you couple that with our industry-leading cash costs and finding costs, it really helps to reduce the volatility of our profits or our earnings over the long term, and it should give comfort to our shareholders in our return strategy. In February, our board of directors formally approved a capital budget between $450 to $500 million, which should drill us between 70 to 80 net wells, and add between 43,000 to 48,000 BUEs a day by the end of the year next year to offset our base decline rate, which we estimated around 27%. That should see us exit December of 25 at or about 145,000 BUEs a day using the bid point of that guidance. And we think we can do that with a four-week program, which is designed to hold production flat more or less through the first half of 25, similar to what we've done in past years. If we have production exposed to low prices, any low prices, we expect us to manage that similarly to what we did this past year, where we'll delay bringing it on. And of course, we're living in some uncertain times right now with the threat of tariffs on and off again by the month or by the day. But we think we're well insulated on the revenue side since we have already hedged close to two-thirds of our gas volumes and about 27% of our liquid volumes for 2025. Most of our gas contracts physically deliver in Canada, so we should be U.S. tariff exempt, but clear to the end certainly doesn't help the market sentiment or the rest of Canadians, so we hope this trade war can be resolved sooner than later. On the natural gas macro, there's plenty to be excited about with LNG ramping up in the U.S. already and LNG Canada sometime this year. The demand right here in Alberta also looks bright with The vast number of connection requests to the power grid, to the ASO network, totaling near 10 gigawatts of demand, which by my math could be 1.4 BCF a day of local demand if it was all fired by natural gas. You include phase two of LNG Canada, the Rockies SLISM LNG project that we're part of, and the NGTL expansions that are planned to the end of the decade. You can quickly get up to about seven or eight or even nine BCF a day of new demand by the end of the decade. It all comes to fruition. And that's pretty exciting for a basin that produces about 19 BCF a day. So as I like to say it, I think we're in the right business. Okay. I imagine there's some questions, Olivia. So perhaps we can go to the phones and take some of those questions.