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Good morning. My name is Michelle, and I will be your conference operator today. At this time, I would like to welcome everyone to the Topaz Energy Corp. First Quarter 2023 Results Conference Call. [Operator Instructions] Mr. Scott Kirker, you may begin your conference.
Thank you, Michelle, and welcome, everyone, to our discussion of Topaz Energy Corp.'s results for the 3 months ended March 31, 2023 and 2022. My name is Scott Kirker, and I'm the General Counsel for Topaz. 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 Topaz Annual Information Form and its MD&A available on SEDAR and on the Topaz website. I also draw your attention to the material factors and assumptions in those advisories. I'm here with Marty Staples, Topaz President and Chief Executive Officer; and Cheree Stephenson, Vice President, Finance and Chief Financial Officer. They will start by speaking to some of the highlights of the last quarter and the year so far. After the remarks, we will be open for questions. Marty, Cheree, go ahead.
Thanks, Scott. Good morning, everyone, and thanks for attending the Q1 conference call for Topaz. First quarter production volumes of 18,900 BOE per day set a new record for Topaz. From Q1 last year, production grew 17%, driven by 50% higher total liquids royalty production partly attributed to the Keystone and Deltastream acquisitions in addition to operating development over the year.
From the prior quarter, production grew 3%, driven by a 4% production increase in Northeast B.C. Montney in addition to strong activity and production results across our fee title mineral group. Royalty production across our other core areas was generally consistent with the prior quarter and saw maintenance development activity.
In Q1, 164 gross wells were spud and 183 gross wells were brought on production. First quarter drilling was diversified across Topaz's portfolio as follows: 30% Clearwater, 22% Northeast B.C., 18% Deep Basin, 13% Peace River, 10% West Central Alberta and 7% Southeast Saskatchewan. Of note, 36 gross wells were spud at these BC Montney during the first quarter, which is a 71% increase from Q4 2022. And in the Clearwater, operators continue to advance waterflood development, 10% of the 63 gross wells spud are injection wells. At March 31, Topaz had 88 gross wells drilled but not yet brought on production, which is a 22% increase from Q1 2022.
Topaz continues to see consistent development and top-performing wells, drilled across royalty acreage in each core area as well as strong activity from its fee title mineral portfolio. Through the first quarter of '23 the operator working interest production across Topaz's royalty acreage represented approximately 9% of total Western Canadian sedimentary basin production and the 27 to 29 active drilling rigs across Topaz's acreage represents approximately 12% of the [total] active rig fleet across Western Canada.
Based on planned operating drilling activity, Topaz expects to resume 27 to 29 drilling rigs active on its royalty acreage following spring breakup with 3 to 4 rigs maintaining active through breakup. Our Q1 royalty production revenue of $60.9 million was 39% weighted to natural gas and 61% to total liquids, and we did realize sour and heavy crude oil differential pricing pressure in Q1, which has alleviated into Q2. Topaz realized pricing before hedging was 3.23 per Mcf of natural gas and 87.50 for oil, that is Canadian. In addition, Topaz realized 63 per Mcf of hedging gain on gas and $1.31 per barrel on hedging gain on oil. Our infrastructure business continues to provide stable inflation protected income which enables strong dividend support. Through Q1, we once again realized 99% utilization on our natural gas processing capacity and generated total processing revenue and other income of $17.3 million. We incurred $1.9 million in operating expenses in Q1, resulting in an operating margin of 89%. Our Q1 annualized infrastructure operating income of $62 million represents 36% of our annualized Q1 dividend.
In the first quarter, Topaz generated $71.3 million or $0.50 per diluted share, and we distributed 60% of cash flow to shareholders through dividends. Our excess free cash flow was allocated debt repayment, which resulted in a 7% reduction to our year-end 2022 net debt. At March 31, Topaz had $376.5 million of net debt which represents 1.1x net debt to cash flow and approximately $600 million of available credit capacity, which provides financial flexibility for strategic growth opportunities. We have confirmed our previously announced 2023 guidance assumptions, including average annual royalty production ranging between 18,300 and 18,800 BOE per day, the midpoint of which represents 10% growth over 2022 and approximately $65 million in annual infrastructure revenue. Given the strong first quarter production, we may update our volume guidance in conjunction with second quarter results once we determine the impact of spring breakup in our Q2 production volume.
We hope to see you at 9:00 a.m. for our AGM at the Petroleum Club on June 14 and look forward to discussing Q2 with you on the next call. We're pleased to answer any questions at this time.
[Operator Instructions] The first question comes from Matthew Weekes of iA Capital Markets.
Just wondering if you can kind of comment on the outlook for potential acquisition activity. And given the strong state that the balance sheet, is that the amount repaid in the quarter? And just kind of what you're seeing out there in terms of royalties versus infrastructure?
Yes. Thanks, Matt. It's been a mix between the 2. We're seeing some royalty opportunities, some infrastructure opportunities. One thing we're very cautious of is just the tier, I think, with more cash on the balance sheet, as you indicated. We have seen some of the opportunities go down a tier. And we've always kind of looked at this company, this portfolio is high-quality assets. So we are always very cautious to kind of proceed with M&A that doesn't keep that value inside our organization.
Okay. I appreciate the commentary on that. And just one more question for me. In terms of -- has Topaz looked at different ways to sort of diversify their gas price exposure over the long term to different hubs, whether it's through sort of different hedging strategies or potentially different contract structures in the cores and with your payers. I'm just wondering if that's something that's sort of being looked at for the long term.
Matt, it's Cheree. So we definitely look at this all the time. We don't hold or carry transport, and we don't take in kind at this point. We are -- for the Tourmaline gas production we are paid on an AECO 5A basis. So we've done financial contracts overlaying that, and we've done fixed swaps. We've also balanced the exposure to 5A and 7A, and recently, we've done some diversion to NYMEX pricing for about 10% of our gas volume. In addition to that, we're, yes, constantly looking. But if we don't hold the transfer, don't have access to the transport, we don't want to do anything synthetically that would expose us to higher risk. So one big thing to note, though, is we do not pay transfer costs. We just pay that 1% marketing fee. So that does obviously vary with commodity price. So in the quarter, we paid $369,000 in marketing fees due to the reduction in gas price. So that's a lot lower if you do the math on about $0.40 an Mcf average transfer costs within the basin. So we feel we are winning there. But we will continue to look to diversify if and where we can.
[Operator Instructions]
The next question comes from Josef Schachter of Schachter Energy.
Just to follow up on Matt's question about the M&A side. With -- as you mentioned in the call [or] in the notes as well, 61% liquids, 39% natural gas and yet you want to be considered a natural gas royalty income-producing company, are you going to be looking more towards natural gas deals going forward or natural gas condensate? How do you see the mix given the heavy oil has grown so much in the last couple of quarters?
Yes. Josef, thanks for the question. Keep in mind, that's a revenue number that we've put out. So it's in our portfolio right now, 70% of our royalty acreage is exposed to natural gas, 30% is oil liquids weighted. So we always do think we'll be predominantly weighted to natural gas. And if you think about the complex that's setting up right now, particularly in Northeast BC with Tourmaline's Conroy build-out, that is the largest project we'll see in Western Canada over the next 2 years. They're going to build a 400 million a day facility. We already have a royalty on all of that acreage. And so really, the 400 million a day facility they build and all the drilling activity that takes place, we've already paid for that. So we are exposed to the biggest growth project in Western Canada.
What that translates to us is about $100 million of EBITDA at forward strip pricing without us spending any additional dollars. So as much of liquids as we add, we've got this Tourmaline company that's going to come up behind, and I think backfill the natural gas wedge that we've kind of changed a little bit. So we do always expect we'll be 70% to 75% exposed to natural gas overall in our portfolio. It's just with the big kind of gap in pricing between oil and natural gas right now, we are seeing some bigger revenue stream from the oil side. But we do expect that gas wedge is going to soon kind of expand and we are bullish on gas kind of into the future, particularly in pricing.
One last one. When is Conroy coming on and when does that start impacting your financial statements?
So they've started ordering construction for the facility of Conroy already, so we do anticipate by the end of '24, that facility will be close to being built for sure, by 2025. They wanted to time it around LNG Canada. And so we do think by 2025, we'll start seeing some of the results. And that production just doesn't all show up at once. So they've got a step-up into filling that facility. So we do think the latter part of '24 we'll start seeing some activity to kind of get ready to fulfill the obligation of that 400 million a day facility. In the meantime, I think that's going to bode well for gas price dynamics.
The next question comes from Aaron Bilkoski of TD.
My question is on non-oil and gas royalties, in this last quarter or so, we saw freehold talking about exploring, non-oil and gas royalty opportunities. [Price got] highlighted, potash revenue and water disposal revenue. I just I'd be interested to hear your thoughts on, a, your interest in non-oil and gas royalties, and b, what the market potentially looks like?
Yes, for sure. One of the added benefits of us increasing our fee exposure through reserve royalty and Keystone have been some of the ancillary leasing that we've seen on that acreage. Potash has been one of those products that we've seen some leasing activity on, lithium and helium being the other one. So although smaller in scale, it's been an added benefit one that we didn't pay for when we were evaluating or purchasing these companies. And so a nice win for us alongside. Still some activity that needs to happen in its early stages, I think, from the lithium and helium side, in particular, in Southeast Saskatchewan. We're not looking to expand that business in any significant way.
I think we're sticking to what we know best, and that's natural gas and oil. Although from time to time, we do explore opportunities in that part of the system, it just hasn't [offered] something that we've been willing to invest in because have not been able to realize true returns there. Keep in mind, we do have one of the biggest CO2 [indiscernible] projects were attached to. That's a carbon-negative gross overwriting royalty with White Cap in Southeast Saskatchewan that it is kind of outside the box, and we do like the revenue that we're able to achieve from what we call that carbon negative gross revenue royalty.
The next question comes from Luke Davis, RBC.
Provided some good commentary on the gas side of the business. Just wondering if you can also speak to the organic growth profile on the oil side? And whether there's any remaining capital commitments that would continue to drive that higher?
Yes. We've got about $40 million of capital commitments left in the Clearwater, which we're still seeing a lot of activity in there and when we talk about the 27 to 29 rigs, 13 to 14 of those rigs are with Tourmaline and then the others would be kind of Tamarac, Headwater and some other operators through Southeast Saskatchewan and West Central Alberta. So quite active there. We know the capital commitments. They should be completed by next spring of 2024. So in good position there to keep activity kind of rolling, and we do see growth inside the Clearwater.
One of the big upsides we've seen inside the Clearwater is the waterflood. We were on Project 5, I think we're now going to Project 6. And those are not all on our royalty lands, a couple belong to spud, the other ones belong to Tamarac Valley and Headwater. But Headwaters had some big strides made forward and pretty flat production overall. So doing exactly what they thought it was going to do. So we're really pleased with kind of the state flat curve that these waterflood projects have kind of been able to achieve. Anything else, Cheree, you'd like to mention there? .
Sure. So for 2023 in total, we would expect about $500 million to be spent on our lens kind of via our key heavy oil operators with about 25% of that having been spent, so about $400 million for the balance of the year. And so that's not a formal capital commitment, but we do see the attractiveness of the asset market dynamics that being pretty resilient to any changes in capital spending. And then through Q1, we saw roughly $40 million allocated to sort of other areas of our fee mineral title acreage. So those dollars are maybe more a bit susceptible to changing commodity prices or volatility, but we kind of see somewhere north of $20 million after the $40 million on that type of acreage as kind of a nice to have not -- we're not counting on it type of capital. So the key operators, we don't see any of those capital budgets changing. So it kind of just shows the strength of those key operators on our acreage.
There are no further questions. I will turn the call back to Scott Kirker for closing remarks.
Thanks, Michelle. On behalf of Marty and Cheree. Thanks, everyone, for listening, and we look forward to speaking with you in the next quarter and at the AGM on June 14.
Ladies and gentlemen, this does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.