Tourmaline Oil Corp.

Good morning, ladies and gentlemen, and welcome to the Tourmaline Q4 2021 results conference call. At this time, all lines are on 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, March 3, 2022. I would now like to turn the conference over to Scott Kerker. Please go ahead.

Thank you, operator, and welcome, everyone, to our discussion of Tourmaline's results for the years ended December 31, 2021, and 2020. My name is Scott Kerker, and I'm the general counsel for Tourmaline. Before we get started, I refer you to the advisories on forward-looking statements contained in the news release as well as the advisories contained in the Tourmaline Annual Information Forum and RMDNA available on CDAR and on our website. I also draw your attention to the material factors and assumptions in those advisories. I am here with Mike Rose, Tourmaline's President and Chief Executive Officer, Brian Robinson, Vice President of Finance and Chief Financial Officer, and Jamie Hurt, our Manager of Capital Markets. We will start by speaking to some of the highlights of the last quarter and our year so far. After Mike's remarks, we will be open for questions. Go ahead, Mike.

Thanks, Scott, and thanks, everybody, for dialing in, and we're pleased to go through our strong 2021 results. So lots of highlights. Full year average 21 production of 441,000 BOEs a day was up 42% year over year. Our current production is ranging between 500 and 510,000 BOEs a day, and we expect a Q1-22 exit of between 510 and 515,000 BOEs per day. Full year 21 after tax net earnings were a record $2.03 billion or $640 per diluted share. Our full year 21 cash flow was a record $2.93 billion or $925 per diluted share and up 147% year over year. And importantly, we generated a record $1.49 billion of free cash flow in 2021. Exit 21 net debt was $973 million or below the low end of our range, long-term range of $1 to $1.2 billion. Year-end 21 PEP reserves of 947 million BOEs were up 50% year-over-year, including 2021 production. Total approved reserves of $2.19 billion were up 39%. and 2P reserves of 4.24 billion BOEs were up 33% over year end 2020. We replaced 677% of 21 annual production of 161 million BOEs with 2P additions of a little over a billion BOEs. The 2P reserve value equates to $97.54 per diluted share. The total approved reserve NAV equates to $62.70 and PDP $33.77 using the same pricing and discount rates. Tourmaline now has 19.5 TCF of 2P natural gas reserves. Turning to production specifically, as mentioned, current production ranging between 500 and 510,000 BOEs per day. our full year 22 average production guidance of 500,000 BUEs per day remains unchanged. All three of our operated EP complexes are producing at or above full year 22 guidance levels, which of course is very encouraging. Looking at some of the financial highlights, as mentioned, full year 21 after-tax net earnings were a little over $2 billion. Fourth quarter 21 cash flow was $968 million and full year 21 cash flow was that record $2.93 billion. On the shareholder return front, we increased the base dividend three times in 2021 to a total of $0.72 per share. So that was a 29% increase over the course of the year. And we paid our first special dividend of $0.75 per share in October of 2021. And we have committed to returning the majority of annual free cash flow to shareholders and we are executing on that plan. Subsequent to year end 21, we increased the annual base dividend up to 80 cents per share and paid our second special dividend of $1.25 per share this time in February. Moving to the budget and the outlook. Q4 21 EP capital expenditures were $411 million. And as previously discussed, we accelerated the construction of the Gundy Phase II deep cut and the Aitken 46C expansion into the second half of 2021. Both projects were completed on budget and are currently on stream and at full capacity. In 2022, at current strip pricing, We expect to generate cash flow of $4.05 billion or $11.97 per diluted share and free cash flow of $2.85 billion or $8.43 per diluted share on unchanged EP capital expenditures of $1.125 billion in 2022. We continue to maintain our strong capital discipline. We always build 2.5% inflation per annum on both capital and operating costs into the company's five-year EP capital plan. As mentioned, our exit 21 net debt was $973 million, or 0.25 times 21 net debt to Q4 21 annualized cash flow, and below the company's long-term debt target of $1 to $1.2 billion. We had another strong reserve year in 2021. Year-end 21 PDP reserves of 947 million BOEs, as mentioned, were up 50%, including annual production of 161 million BOEs. 21 PDP FD&A costs were $7.27 per BOE, including changes in future development capital, and that yielded a PDP reserve recycle ratio of 2.5. Our total approved FDNA costs in 21 were $594 per BOE, and our 2P FDNA was $454 per BOE, including changes in FDC. Importantly, we have only booked 3168 gross locations of a total drilling inventory of 22,715 gross locations. So we've only booked 14% of the overall inventory. to achieve our year-end 21 2P reserves of 4.24 billion BUEs. So there's lots more to come. The current FDCs associated with 2P reserves represent only three years of prospective cash flow at strict pricing. On the marketing front, in 21, we further diversified the gas marketing portfolio by establishing a U.S. Gulf Coast LNG long-term net-backed supply agreement with Chenier Energy. In 2023, Termaline will become the first Canadian EP company participating in the LNG business with full exposure to JKM pricing, providing a material increase to anticipated 2023 cash flow. In November 22 of this year, the company will increase gas volumes exported to Western US markets from 345 to 445 million cubic feet per day, with approximately 67% of that gas accessing the premium price PG&E California market. NGL price realizations in the fourth quarter of 21 were up 24% over third quarter 21. And a reminder, we are the largest NGL producer with anticipated average production levels of over 70,000 barrels per day in 2022. Turning to E&P, we are the busiest operator in the basin. We drilled a total of 280 net wells during 21 for a total of 1.289 million meters drill. We have systematically increased our lateral length of our horizontals by over 30% since 2018, while simultaneously reducing actual drill complete cost per lateral foot by 30% in that time period. We operated 13 drilling rigs and four to five frac spreads across the three EP complexes during January and February of this year as planned. We continue to operate all five drilling rigs in Northeast BC with multiple high performance pads at Sundown, Gundy, Aitken, and LaPrees, all contributing a little ahead of expectation. The facility expansions at Gundy and Aitken were accelerated into second half 21 and completed on budget. The Aiken 46C expansion and deep cut installation was executed in 120 days for $96.5 million. The previous owner had estimated 270 days for a capex of $116 million. We continue to evolve the Conroy North Montney development project. This minimum 100,000 BOE per day gas and liquids project is currently planned in the 25-26 timeframe. coinciding with the projected startup of LNG Canada and the anticipated related strong intrabasin natural gas pricing. And some strong recent pads. The Three Well Upper Charty Lake pad in our Peace River High Complex has averaged a combined production rate of 2,500 barrels of oil per day and a little under 3 million a day of gas over the first two weeks of production. It just came on stream. And we had a very strong two-well wheel ridge pad at Smoky in the north end of the deep basin complex, which between the two wells combined tested at over 65 million per day during the testing period. A goal or a good time for some very strong wells. We are updating our exploration program. We've been working on it for over two years. We have successfully tested six new horizons spread across the three operated complex, so it's working well. In our year-end 21 reserve report, we've already booked 845 BCF of 2P reserves from the discovery so far, and further successful delineation drilling is planned in all three complexes over the next 12 months. And we will disclose further details in upcoming quarters as we can. And this initiative, we believe, provides shareholders with an additional, unique, long-term growth and value accretion opportunity on top of the regular EP program. A brief acquisition update. We indicated mid-21 that we were pausing our larger corporate acquisitions, but we have also indicated that $200 million to $300 million of annual free cash flow could be allocated to further smaller complementary asset acquisitions within our existing complexes. During Q421 and thus far in Q1 of this year, we completed a number of these small acquisitions that in aggregate we believe are meaningful. So to that end, we've acquired 2,400 BOEs per day of production, an estimated 43 million BOEs of 2P reserves, those are internal company estimates, 295 growth sections of land, and that includes land sales that we've gone to, and an additional 238 gross drilling locations for total cash outlay between the two quarters of just a little under $64 million. So very strong metrics. Looking at environmental performance improvement, we had a very busy and successful year in 21 with multiple initiatives making measurable progress on emissions reduction. We have an engineering team in place and it's been there for over three years developing and implementing new proprietary emission reduction technologies, executing our expanded water management initiatives, managing third party environmental related research, evolving a methane testing center and managing an emerging carbon offset business. We are investing 20 to 40 million per year now on environmental performance improvement activities. We have now displaced diesel with nat gas on all of the drilling rigs in the operated fleet We have where possible one rig running directly on high line power and this has provided a significant emissions reduction and cost savings so a double win for shareholders. During 21 we entered into a JV with Trican to utilize the first tier 4 nat gas frac unit in Canada so further work on our diesel displacement initiatives. The company achieved its net 25% methane reduction target in 21 three years earlier than anticipated. And we're not done there, and we've set new methane reduction targets, and we'll execute on those as well. In 21, the Emission Testing Center, or what we refer to in our literature as the ETC, it's the first of its kind in the world. It's at the West Wolf gas plant in the Deep Basin, and it became fully operational in Q4. And it's critical in evolving new technology and methodologies to materially reduce methane and other emissions across the entire EP business. We did announce that the board of directors have declared a quarterly cash dividend on the common shares of 20 cents per common share as anticipated. And finally, related to our emission reduction, natural gas we see is the great enabler of our future energy transformation. It will be the largest component of the future energy stack for a very long time, and Canada should be supplying as much of our low-emission natural gas to the rest of the world through a material and growing LNG business. It's the best thing we can do for global emissions and for the Canadian economy.