Good morning. My name is Amy, and I will be your conference operator today. I would like to welcome everyone to the Kiwetinohk Energy 2025 second quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer session. If you would like to ask a question during this time, simply press star, then the number one on your telephone keypad. If you would like to withdraw your question, please press star, then the number two. Thank you. Mr. Nielsen, you may begin your conference.
Thank you, Amy, and good morning, everyone. Thank you for joining us for the second quarter 2025 Kiwetinohk Energy Investor Call. On behalf of Pat Carlson, CEO, my name is Kevin Nielsen, Vice President, Corporate Controller and Investor Relations, and I'll be leading you through the call this morning. I'll ask Janet Annesley, our Chief Sustainability Officer, to do an Indigenous Land Recognition. Please go ahead, Janet.
Thank you, Kevin. Kiwetinohk Energy's conference call today is coming from Calgary, the traditional territories of the people of Treaty Seven, which includes the Blackfoot Confederacy, comprised of the Siksika, the Piikani, and the Kainai First Nations, the Tsuut'ina First Nation, and the Stoney Nakoda, which includes the Chiniki, Bearspaw, and Wesley First Nations. Calgary is also home to the Métis Nation of Alberta, Districts Five and Six. We have operations across Alberta through Districts Six, Seven, and Eight, and we recognize the diversity of First Nations and Métis people in all these places that we call home. Before I turn it back to Kevin, a brief update from the Sustainability Department. We got news this week that Kiwetinohk received Level Five, the "gold standard" reporting from the United Nations Environment Programme’s Oil and Gas Methane Partnership.
Level Five is OGMP's highest level of reporting, achieved a year ahead of the required timeline. I want to say congratulations and thank you to the Upstream team for demonstrating such a high degree of rigor on operational methane measurement and reporting. Back to you, Kevin.
Thank you, Janet. Joining me today, in addition to Janet, are Jakub Brogowski, Chief Financial Officer, Mike Backus, Chief Operating Officer, Upstream, Craig Carlson, Vice President, Finance, Power Division, and Lisa Wong, Senior Vice President, Business Systems. We would like to use the first part of the call to provide you with a summation regarding our second quarter release on ESG. The telephone line will then be opened to allow participants to ask questions. Before going through the results, I'll remind everyone the conference call includes forward-looking information and non-GAAP financial measures with the associated risks and disclosures detailed in our news release and MD&A. The news release, financial statements, and MD&A, along with all of the company's official disclosures, are available on our website and SEDAR+ . I'm extremely pleased with the team's performance in the second quarter.
In our Upstream division, we continue to deliver strong operational and financial results, posting record quarterly production and generating free cash flow with controllable costs ahead of plan, and building on the momentum from the first quarter of 2025. Following a strong performance through the first half of the year, and with the 2025 outlook underpinned by high liquids content production, low operating costs, and critical access to the Chicago natural gas market, which continues to offer premium pricing compared to ACO, we are in a position to make positive revisions to our full year's 2025 Upstream guidance. This will be expanded upon later in the call. The results continue to highlight the quality of our asset and the key differentiators that we have spoken about in the past.
With our strong netbacks, the company is well positioned to generate free cash flow, pin down debt, and move to a return on capital framework later in the year. On June 23, 2025, we launched a formal business strategy review to evaluate a range of potential value enhancement opportunities with a focus on the company's upstream assets and an orderly exit from its power business. This process is ongoing, and we have no updates to share at this time. I would like to thank our shareholders on behalf of the board and our team for their continued support, and I will now ask Jakub to provide some more information from the CFO's perspective.
Thanks, Kevin, and good morning, everybody. We had an exceptional second quarter with our Duvernet Mountain platform delivering across the board: robust operational and financial results, record production levels, continued reduction in operating and transportation costs, extending access to premium natural gas markets with declining transportation tolls, on track for record annual cash flow, growing levels of free cash flow, debt repayment ahead of schedule, reinstated share purchases at a discount to NAV, and positive revisions to our 2025 annual guidance. Let me walk through a few highlights from the quarter. We delivered record quarterly production, averaging 33,217 BOE in Q2, with liquids comprising 45% of that total. We remain confident in our development program, which now reflects our Simonette plant turnaround and associated downtime shifting to Q3. Based on strong performance, we are increasing the low end of annual production guidance by 1,000 BOE a day.
Operating costs remain below expectations and continue to improve as we filled more capacity at our owned and operated Simonette facilities. This helped spread fixed costs and brought Q2 operating costs down to $6.02 a BOE. We are reducing full-year guidance by $0.50 a BOE to reflect these gains and the reliability of our assets. Transportation costs also declined this quarter, driven by reduced expenses to move flaccid NGLs, combined with an anticipated 23% toll reduction on the Alliance Pipeline effective November 1, 2025. We're lowering our transportation guidance by $0.25 a BOE. Our access to Alliance continues to deliver outsized value. For the six months ended June 30, our realized natural gas price was $5.08 an MCF, approximately 164% higher than ACO daily pricing of about $1.94 an MCF for the comparable period.
At current strip pricing, this differential is forecast to deliver $100 million in net value in 2025. Our press release includes further detail on the pending pipeline settlement and revised toll. Bottom line, we've secured critical market access for the next decade, with the Alliance toll dropping to approximately $0.98 an MCF. We expect this contract alone to add approximately $600 million or over $13 per share of undiscounted cash flow over that 10-year term. Q2 delivered top-tier cash flow per BOE. We generated $88.4 million in funds flow from operations and $37.2 million in free cash flow. This builds on our strong Q1 momentum, driven by scale, infrastructure, efficiency, and cost discipline, while growing production over 20% year over year. After full funding capital expenditures of $51.2 million, free cash flow was directed towards debt reduction.
Our debt to annualized free funds flow ratio has now declined to 0.6 times, down from 1.1 times at the end of 2024, a 40% improvement. Following our strong performance in the first half, we've made the following positive adjustments to 2025 guidance. We've increased the low end of production by 1,000 BOE a day. We reduced the expected royalty rate by 1% of revenue. We lowered operating cost guidance by $0.50 a BOE. We lowered transportation expense by $0.25 a BOE, and we've reduced the high end of our capital cost guidance by $10 million. Kiwetinohk Energy is in a position of strength. Our high netback asset, infrastructure ownership, and market access enable us to generate free cash flow across a wide range of commodity prices. At current strip pricing, we forecast approximately $95 million of free cash flow this year.
Even at $50 WTI and $2 Henry Hub for the remainder of the year, with the support of our strong hedge book, we would still expect to generate over $50 million of free cash flow. To close, I'm extremely proud of what our team has delivered in the first half of the year and energized by the opportunities ahead. Thanks again for your time this morning. I'll now turn over things to Mike to walk you through our Upstream accomplishments.
Yeah, thanks, Jakub, and good morning, everyone. I'm pleased to provide you with an update on the progress in the Upstream business for the first half of the year. In Q1, we posted record quarterly production and have now posted another record quarter. I'm very proud of the team for delivering this milestone. We did this safely with great performance across all aspects of the business. The strong first half of the year and the confidence we have in our program looking forward has allowed us to tighten our guidance strings by lowering the bottom end, as you've seen in our announcement and just mentioned here by Jakub. Just adding a bit of color on some of our recent wells' performance, we continue to see strong performance from our Simonette Mountain filter.
Our first turbidite well, the 1233, has remained relatively flat over its first 11 months of production, far exceeding our expectations. It's now produced over 2.2 BCF and 105,000 bbl of condensate during that time. The second turbidite well, at 1516, has been on production for approximately five months and is on a similar trend as the first well. Three Toney Creek Duvernay wells at our 933 pad came on stream in May and are performing in line with our expectations. We also executed three Mountain wells that are on the 18 pad in Placid. Two of these wells will be flowed back later in August or late September once the processing capacity is available after third-party K3 outages are completed, with the third well requiring a little bit of remedial work at a later date and was left uncompleted at this time.
On both the Toney Creek and Placid pad, we continue to optimize our designs and build efficiency learnings, which are helping to drive our capital costs down, as reported in our press release. We see opportunities to continue this trend through economies of scale, well design choices, and innovative technology deployment that we've been trying. It's been mentioned already, and you have noted another very strong quarter for operating cost levels at just over $6 a BOE. Now, our strong production and efficient spending levels drove this performance despite having third-party outage impacts on our Placid volume for approximately half of the quarter. You've also noticed that for the second quarter in a row, we've reduced our guidance for operating costs, as Jakub walked through. We continue to see these costs trend in a positive direction, really driven by the quality of our assets and the team who operate them.
A quick update on our current and remaining activity for the year: here is what's going on. We're currently completing two Duvernay and one Mountain well at our Simonette area on the 127 pad. This is the location where we've returned to after we had a very exciting first Mountain well, and it's also the location where we drilled our record-length 9,023 m well. This is one of the wells we're completing now. These are expected to come on later in August. The drilling rig is back in our Simonette area, drilling three new Duvernay wells in the northwest part of the core development area at the 911 pad, which is also a second occupation of that pad.
After this, and given the success of our recent Simonette Mountain wells, we've actually just decided and got approval from our board to move to another two Duvernay and one Mountain well pad at a 314 location situated near the southwest part of our core development area. Here we'll drill an additional Duvernay development well and further delineate the Mountain turbidite play that we are having strong success with. In addition to this well capital, we're also looking to complete the final stages of our 531 gas Placid expansion in Simonette, which is adding 15 million cu ft per day of capacity for this facility, and this will complete the expansion activities that we've been executing over the past couple of years.
Looking forward, I'm expecting the third quarter to see some planned interruptions with the continuation of the K3 syndrome and outages planned at our 531 plant for this expansion. With new wells ready to come on at 118 in Placid and 127 in Simonette, we are expecting a very strong fourth quarter and exit for the year. Safe, reliable operations is our mantra, and the team is delivering that while always looking for a marginal gain along the way. This has helped us deliver a very strong first half of the year. Thanks for your time today, and I hope everyone enjoys the rest of your summer. I'll turn it back to Kevin.
Thank you, Mike. This concludes our second quarter conference call, and I'll now pass it back to Amy for any questions.
Sorry about that. Thank you, ladies and gentlemen. We will now begin the question and answer session. Should you have a question, just a reminder, please press the star followed by the one on your touchtone phone, and you will hear a prompt that your hand has been raised. Should you wish to withdraw your question, please press the star followed by the Q. If you are using a speakerphone, please flip the handset before pressing any Qs. Our first question today comes from Amir Arif from ATB Capital. Please go ahead.
Good morning, guys. Congrats on a great quarter. I just wanted to follow up on your comment there, Mike, about the 314, the new three-well pad you're talking about. Is that reflected in the current capital guidance, or should we think of that as additional capital coming in just based on your comments about just recent approval from the board?
Yeah. Hi, Amir. Thanks for the question. Good one. No, I would, within the capital guidance, what we've done is accelerated that pad just based on some of the results, and we've actually just decided to defer one of our core area pads, which had at the 8 or 23 locations, was really just swapping out a very similar pad, just given some of the excitement we've had around that area. We like the prospect of that Simonette Mountain turbidite play, down in that FF314 pad. It's within the capital guidance, just a swap.
Got it. Okay. On the Simonette Mountain area, I guess that goes well to Holigan Marine Well. Did you see who was the music show with us? Is it more just a landing zone in the lower part of Simonette Mountain, or is it just a certain area that's better charged than other parts of the mountain in that area?
Yeah. Good question. Without getting into the detailed geological explanation, the quick answer would be like this. It's the turbidite play, which is a deeper, slightly higher quality reservoir that we've identified through the first couple of wells. It exists. There's about 69 or 70 locations we've identified, and it's basically a lower target from most of the current Simonette Mountain development. We've got two benches to look at there, and this lower bench is what's been proving up to be a much higher quality, higher productivity, higher gas drive zone. That's what we're following up with. I think that we have a separate lower bench.
Okay. Sounds good. Just a question for you, Jakub. On the return of the NCIB, I know previously the NCIB was never really, it was more ad hoc. There was no formal structured approach in terms of how much dollars would be allocated on that front relative to your free cash flow generation. Is there any change in that philosophy today, or are we not there yet?
Yeah, it's a good question, Amir. Look, I think we're just ahead of budget, I think, as you heard on the call here. With that excess capital, our debt reduction is moving faster than we had budgeted, which is great news. We've just turned the NCIB on just to do a kind of regular purchasing in the market when that's available. I think as we approach the end of the year, as we've been guiding in prior years, there's probably a more substantial return of capital planned, as we prepare for budget in 2026. We'll have those details as we approach the year. I think just given current prices and ship levels, production where our production is and the free cash flow generation, that's going to provide a lot of opportunity to have a more substantial return of capital program in the next year.
Stay tuned for more details as we approach budget.
Okay. I'll give you just as a final follow-up on that. With the additional debt reduction, any thought of allocating some of that excess free cash to potentially accelerating or growing the three more wells, just given the well results you're already achieving?
Yeah, I'll ask Mike to comment on that, Amir.
Yeah, Amir, we haven't. That's always an option for us. We've got ready pads and wells to drill. We kind of like the cadence we're on right now. We haven't really exercised that option or had that debate necessarily, but we've always reserved that option, and we can go pretty quickly and move to that. No definitive plans at this point, but inventory available.
I think the other thing, Amir, given the additional financial capacity, probably sets us up for more of a 20% growth profile in the coming year, along with free cash flow generation. Similar total return, like right now we're, I think, at consensus estimates we're 30% + on total return. I think we're just setting up, assuming similar commodity conditions, for a similar situation in 2026.
Sounds good. Takes a look at the time.
Thank you. Our second question today comes from Joseph Schlachter from Schlachter Energy Research. Please go ahead.
Joseph .
Thanks, Amir. I'm going to go ahead and go to Greg Kohr. The first one for me is, ACO prices in Q4 $2.47 versus $2.39. Anything special in there that gave you that big bump up from a year ago? To me, it looks like it's more than just the NYMEX price.
Yeah, Joseph, it's a good question. Look, I think certainly from the perspective, I think there's two things. One, we definitely have differentiated access across the platform to that Chicago market. We are the fifth largest shipper on Alliance Pipeline, and I think we're continuing to see 150+% premiums for access to that market. Overall, a gas macro environment, I think, has certainly improved from where we were last year. Last year there was quite a bit of production and maybe a little bit of a different weather forecast and storage levels, whereas this year, certainly there's production, but there's also a lot of additional demand. There's additional LNG capacity. There's also power draw. When we look at Chicago, all those things are very strongly represented. In Chicago, it's got a huge industrial base, which draws on that gas. The power demand there is two-thirds industrial.
You've got 24/7 power from that huge industrial base, which draws on the natural gas. You've got LNG egress opportunity to Henry Hub, and you've got winter weather there. We're getting all those great things in Chicago, and we think that's what's driving the higher gas prices this year and in the forward strip as well.
Going to the Alliance Pipeline announcement as well, you have a chrome year deal, as you mentioned, and you're going to get the higher volume. What volumes have you contracted? Of that amount that's going through right now, how much is your volume, and how much is the volume that you're doing on a marketing basis because you have this great contract in Chicago?
Yeah, that's a great question, Joseph. We have 120 million cu ft per day contracted online. We're the fifth largest shipper that will service our production dates up to about 40,000 BOEs a day. We're still very well positioned into the end of next year if we look at that level. We've been filling that capacity as we've been growing our asset over the last three years. At any one day, we're probably about 80% coming up to closer to 90% full, depending on when wells come on. You would have seen in the quarter we made $4 million of marketing revenue. We always consistently, like right now, if you look at the basis, the basis is high 2s, $3 an MCF.
What we'll do is we'll forecast any shortfall in the coming quarter, and we'll lock that basis in, and that just guarantees us profits when we're filling that capacity. It's becoming less and less and less. You will see us pretty much going to 100% of that capacity by early next year in terms of our own production.
Where do you go from there? You guys still have a lot of growth ahead of you in terms of the asset-based drilling inventory. Do you need to do another contract? Do you need to find more space on it? How about using it, or are you going to be part of, if Alliance Pipeline starts going around asking to see if people will support an expansion? Would you be part of that? What do you do once you're at $40,000, and how do you get the next phase of growth to $50,000 to $60,000?
Yeah, absolutely. It's a great question. A couple of things. We do have 30 million cu ft a day on the NDTL system here in Alberta. We were pretty excited to see LNG Canada get started, and we'd like to see that get to full capacity. Just with that volume alone, and you mentioned that 50,000 - 60,000 BOEs. With our Alliance Pipeline capacity and the additional 30 million cu ft a day, we're probably pretty well serviced to that 50,000 to 60,000 BOEs. We've looked at the market and some of the forecasts that a lot of yourselves and other analysts have put on the street. To us, from the planned LNG additions that are coming to the West Coast of Canada, it looks like by 2029, 2030, there could be a shortfall of 5 to 6 BCF a day in Canada.
We think there's going to be ample opportunity if we want to go beyond that 50,000 - 60,000 BOEs in the future to acquire additional capacity in Alberta. Certainly, if an Alliance Pipeline expansion was put on the table, that would be positive for the basin here as well. I think we would definitely look at what that kind of opportunity would cost and how it would compare to what we could do with our additional Alberta capacity that we own today. I think we're in a really good position, even beyond that 40,000, Joseph, and I think the market should be developing well. We'll have strong Chicago, and hopefully, in the next couple of years, we see Alberta prices continue to move up.
Super. One last one, Courtney. As mentioned earlier, you're looking for a big uptick in volumes in Q4 and a good exit rate. Are you giving any guidance to what kind of numbers you're looking at there?
We don't typically give quarterly guidance, Joseph. If you look at our production, we've upset to 32,000- 34,000 BOEs on the year. I think if you take a couple of quarters and then average it out, that'll give you kind of a bit of a perspective. I think Mike can share a little bit of where he thinks volumes are coming in towards the end of the year.
Yeah, maybe just to give you a little sense, I think I mentioned, Joseph, in my comments, Q3 is going to be a little bit lower. We've got an outage at our one Simonette facility, and the K3 has continued their turnaround activities probably into the latter part of August here. We're expecting those two shortfalls to kind of give us a little bit of a lull in Q3, but I'd expect to be up in the kind of mid to, you know, kind of 35,000 - 38,000 sort of for Q4. We'll be exiting quite strong.
Super. That kind of covers it for me. Thank you so much for answering our questions. Some of that question sounded good. I'll get a quarter of.
Thanks, Joseph. Yeah, thanks for dialing in.
There are no further questions at this time. I will now turn the call over to Kevin. Please continue.
Okay. Thanks, Amy. Thanks, everybody, for participating. We wish you a very great summer and stay well. We'll catch up in the call.
Thank you, ladies and gentlemen. This concludes today's conference call. Thank you for your participation. You may now disconnect.