Morning. My name is Sylvie, and I will be your conference operator today. At this time, I would like to welcome everyone to Whitecap Resources' Third Quarter 2026 Results and 2027 Budget 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 number two. I would like to turn the conference over to Whitecap's CEO, Mr. Grant Fagerheim . You may begin.
Thanks very much, Sylvie. Good morning, everyone, and thank you for joining us today. There are five members of our management team here with me today. Our president, Joey Wong; our senior vice president and CFO, Thanh Kang; our senior vice president, Asset Development and Information Technology, Dave Mombourquette; our chief operating officer, Travis Tweit; and our vice president, Conventional Division, Reserves and Reservoir Development, Chris Bullin. Before we get started today, I would like to remind everybody that all statements made by the company during this call are subject to the same forward-looking disclaimer and advisory that we set forth in our news release issued yesterday afternoon. We are once again pleased to report very strong operational and financial results for the third quarter of 2026. Our technical and operations teams continue to execute efficiently with our asset productivity once again exceeding our expectations.
Third quarter production averaged 390,720 BOE per day, comprised of 237,252 barrels per day of condensate light oil and natural gas liquids, and approximately 920 million cubic feet per day of natural gas. Production was well above our internal forecast, driven by strong base production and new well performance at Gold Creek, new wells at Kaybob, and better than anticipated base production in our conventional division. Our per-share basis production increased 5% relative to our third quarter of 2025. Elevated light oil and condensate prices, coupled with strong operational performance, resulted in funds flow of CAD 1.2 billion, or CAD 0.96 per share, an increase of 32% per share compared to the third quarter of last year.
After capital investments of CAD 533 million, we generated CAD 640 million of free funds flow in the quarter, bringing free funds flow to CAD 1.9 billion, or CAD 1.57 per share for the first nine months of 2026. From an activity perspective, we drilled 84 wells in the third quarter, 35 in our unconventional division across our Montney and Duvernay assets, and 49 in our conventional division in Alberta and Saskatchewan. With quicker cycle times, we are executing our 2026 capital program ahead of schedule. Rather than slow activity into year-end, we will maintain our current activity levels through the fourth quarter and take advantage of the elevated crude oil and condensate pricing environment. As a result, we are increasing our 2026 capital budget by approximately CAD 100 million - CAD 2.2 billion.
These quicker cycle times, along with strong performance from our assets, is prompting us to raise our 2026 average production guidance for the third time this year to 392,000 BOE per day, which equates to the fourth quarter production of 395,000 - 400,000 BOE per day. This represents a total increase of approximately 19,500 BOE per day, or 5% from our original budget guidance. The incremental activity is focused on our highest return programs at Kaybob, Lator, and our Saskatchewan light oil assets, and it carries additional momentum into 2027. Increasing returns to our shareholders is a priority for Whitecap. Reflecting the strength of our business, our board of directors has approved an increase to our monthly dividend of approximately 1.5% to 6.17 cents per share or 74 cents per share annually, effective with the November dividend payable in December.
The increase equates to approximately CAD 13 million on an annual basis and follows the substantial improvements to our cost structure and our overall highly economic growth we have delivered to date. Beyond our base dividend, we continue to prioritize the balance sheet. For the first nine months of 2026, our free funds flow of approximately CAD 1.9 billion funded CAD 665 million of base dividends, with the remainder directed to debt reduction. Net debt decreased by approximately CAD 1.3 billion since year-end 2025, now being CAD 2.1 billion at the end of the third quarter, or 0.4 x net to annualized funds flow. Our balance sheet is in excellent condition, and Thanh will talk through more details shortly.
Moving to our 2027 budget, we are excited to announce our CAD 2.4 billion - CAD 2.6 billion of capital program includes the drilling of 332 total wells, comprised of 127 unconventional Montney and Duvernay wells and 205 conventional wells, delivering average production, as I said before, 400,000 - 410,000 BOE per day. On a per-share basis, the budget delivers approximately 3% annual growth or approximately 5% excluding the planned major turnarounds at Kaybob in the third quarter of 2027. Our forecast for 2027 will continue the operational momentum achieved to date in 2026 and builds on recent results we've managed to achieve on our asset base. Our 2027 average production forecast includes 140,000 BOE per day from our conventional division, which is more normalized level after a strong 2026, designed to generate significant free cash flow in the current commodity price environment.
Our unconventional division forecast is to grow by 8% to 265,000 BOE per day, and more importantly, to grow condensate production, our base of 60,000 to over 70,000 BOE per day, as we anticipate demand and condensate continuing to be most topical. At strip prices, our forecast will generate CAD 4.6 billion of funds flow and free funds flow of CAD 2.1 billion. It is important to note that the free funds flow will increase by approximately CAD 400 million - CAD 2.5 billion in 2027 if the recently announced Productivity Mega Deduction is enacted as proposed. Beyond our base dividend of CAD 900 million, this would leave CAD 1.2 billion - CAD 1.6 billion of unallocated free funds flow. We will continue to be prudent and patient with respect to our unallocated funds flow and will look for opportunities to redeploy the excess funds flow through 2027.
We remain diligent on looking to drive further shareholder value for the longer term. Until we feel the time is appropriate, we are comfortable parking the excess free funds flow on our balance sheet in the short to medium term. I will now pass the call on to Thanh to further discuss our third-quarter financial results. Thanh?
Thanks, Grant. Petroleum and natural gas revenues increased 45% to CAD 2.4 billion compared to the third quarter of 2025. Third quarter WTI averaged $85.79 per barrel, up $0.32 from last year, as the conflict in the Middle East continued to disrupt global crude oil supply. Edmonton MSW and condensate differentials, which averaged $0.62 per barrel and $3.42 per barrel, respectively, in the third quarter, were much tighter than the headline WCS heavy oil differentials, which averaged about $14 per barrel in the third quarter. As a result, our realized crude oil and condensate price was CAD 113.89 per barrel in the third quarter, an increase of 35% relative to the third quarter of 2025. Our realized NGL price increased 56% to CAD 36.84 per barrel, driven by a higher weighting of NGL sales price on the Far East Index, which strengthened on global NGL supply constraints.
In total, liquids accounted for approximately 92% of our revenue during the quarter, despite being only 61% of total production. AECO prices averaged CAD 1.57 per Mcf in the third quarter, up from CAD 0.63 last year, as export pipeline maintenance restrictions were lower than in the third quarter of 2025. The benefit of our natural gas price diversification was again evident with our realized natural gas price averaging CAD 2.32 per Mcf, which is 77% higher than a year ago and a CAD 0.75 premium to AECO. Approximately 30% of our third quarter natural gas revenue came from sales into U.S. markets. Beginning in 2028, approximately 5% of our natural gas production will be exposed to European TTF pricing. We continue to see the benefits of our lower cost structure. Operating costs were CAD 10.22 per BOE in the quarter.
I do want to highlight that the third quarter includes one-time favorable cost adjustments. Excluding those adjustments, operating expenses would be CAD 11.70 per BOE, which is still below both the second quarter and the third quarter of last year, reflecting lower fixed costs and higher production volumes. For 2027, we forecast operating costs in the CAD 12-CAD 12.50 per BOE range, which as compared to 2026, include higher power and fuel cost expectations and the costs associated with the Kaybob turnaround in the third quarter. Transportation expenses increased 10% to CAD 3.76 per BOE, reflecting the growing weighting of our unconventional production, which is further from sales points, including the U.S. markets where we receive higher realized prices. Our transportation costs are expected to remain in the range of CAD 3.50-CAD 3.75 per BOE for 2027.
Royalties were 14.5% of revenue, or CAD 9.70 per BOE, compared to 12.2% last year, primarily on higher commodity prices. Funds flow was CAD 1.2 billion, or CAD 0.96 per share, up 32% per share compared to the third quarter of 2025. Through the first nine months of the year, funds flow was CAD 3.6 billion, or CAD 2.91 per share, an increase of CAD 0.73 in total and 30% on a per share basis. Net income was CAD 326 million, or CAD 0.27 per share, compared to CAD 204 million, or CAD 0.17 per share in the third quarter of last year.
During the quarter, we recorded an unrealized loss on commodity contracts of CAD 333 million. This is a non-cash mark-to-market movement that will fluctuate with changes in forward commodity prices. Capital expenditures were CAD 533 million in the quarter, below our internal forecast, as continued cycle time compression and operational execution are improving efficiencies.
This resulted in free funds flow of CAD 640 million, bringing year-to-date funds flow to CAD 1.9 billion. Year -to -date, free funds flow funded CAD 665 million of base dividends, with the remainder directed to debt reduction. As a result, net debt at September 30th was CAD 2.1 billion, down approximately CAD 450 million from the end of the second quarter and approximately CAD 1.3 billion since year-end 2025. That represents a net debt to annualized funds flow ratio of 0.4x . We ended the quarter with no draws on our CAD 2.5 billion credit facility and CAD 1.7 billion of investment-grade senior notes at a weighted average interest rate of 4.76%. Our remaining CAD 195 million of senior notes that mature in December of this year, we will anticipate using cash on hand to fund that payment. We expect to exit 2026 with net debt of less than CAD 2 billion.
Turning back to 2027, at our price deck of CAD 80 WTI, CAD 2 per GJ AECO, and a 71-cent Canadian/US exchange rate, we forecast funds flow of approximately CAD 4.1 billion or CAD 3.34 per share, which generates approximately CAD 1.6 billion of free funds flow after capital investments of CAD 2.5 billion at the midpoint. Our guidance reflects a current tax rate of 10%-12% on pre-tax funds flow. This does not include the impact of the Productivity Mega Deduction. If enacted as proposed, the mega deduction would increase our 2027 free funds flow to approximately CAD 2 billion. On current strip pricing, that would be closer to CAD 2.5 billion of free funds flow in 2027. Free funds flow beyond this level provides flexibility for additional shareholder returns, which we will assess in 2027.
As Grant mentioned, we take a countercyclical approach to capital allocation and have been prudently allocating excess free funds flow to our balance sheet to provide maximum flexibility to increase shareholder returns. The opportunities that are in front of us today, whether they be additional growth, share repurchases, further dividend growth, or tuck-in acquisitions, will be thoughtfully considered, and we will not rush into anything. I'll now pass it off to Joey for remarks on our unconventional results.
Yeah, thanks, Thanh. Our unconventional division delivered another strong quarter, drilling 35 wells in the quarter and 90 year-to-date across the Montney and Duvernay. Third quarter outperformance was led by strong base and new well performance at Gold Creek, along with new wells at Kaybob. At Lator, we completed construction of our 04-13 battery during the third quarter and successfully commissioned and introduced production into the facility early in the fourth quarter, which was within our expected timeframe and on budget. We have redirected existing area volumes and brought on our recently drilled five-well Montney pad through the facility with throughput and runtimes meeting expectations.
Our 2027 plan at Lator includes a two-rig program to spud 22 wells and bring on 17 wells, and the ramp-up to the 04-13 facility capacity of 35,000-40,000 BOE per day is expected to take 12-18 months as we incorporate learnings from our first development pads and continue to apply our established development workflows to area development. At Kaybob, our Duvernay assets have been producing at the existing productive capacity of 120,000 BOE per day since mid-year. During the third quarter, our technical teams identified numerous projects to increase the productive capacity of the asset to approximately 130,000 BOE per day in the near term and approximately 135,000-140,000 BOE per day by the end of 2027. These projects are a combination of targeted compression additions and optimization, along with process optimization that allowed for increased utilization of existing infrastructure.
The realized and planned capacity improvements involve nominal capital spend as debottlenecking and targeted optimization projects often do. Our facility and production teams are constantly looking for ways to adjust our infrastructure portfolio to match the characteristics of our production, and this is a great showcase of that. We will look across the balance of our portfolio for similar opportunities as well as the next material facility project. Our upcoming capital programs at Kaybob will utilize this capacity to further take advantage of the increased profitability we are experiencing in our development there. That profitability reflects better well performance driven by improvements in both design and execution. Inventory enhancement initiatives such as wine racking and our ongoing downspacing pilots are further extending inventory life at Kaybob. Drilling operations on two downspacing pilot pads are done, with completion and early time flowback operations now underway.
Upon success of the downspacing pilots, along with the successful wine racking initiative, the estimated value generated through our development on these lands increases by 20%-25%, and we anticipate adding up to two years of additional inventory in the heart of our Kaybob asset. These improvements are being further strengthened through operational execution. With improvements to frac design and the application of our real-time frac optimization, we have increased our frac effectiveness by 14% on legacy Veren lands, which is contributing to stronger production results and better capital efficiency. Gains in both design and execution are a product of our integrated development workflow, which is built to carry concepts from identification through application and to evaluation. How far our learning then transfers across our portfolio depends on the demonstrated results and how well each concept fits the asset.
Each pad feeds the next, and over time, that loop has helped us identify the approach that delivers increasing risk-adjusted returns in each area. The improvements we have demonstrated in our operator results are evidence that it is working. Turning now to 2027, our unconventional division will invest approximately CAD 1.9 billion, or about 75% of our capital budget, to drill 127 wells consisting of 77 Montney wells and 50 Duvernay wells. Unconventional production is forecast to average approximately 265,000 BOE per day at 51% liquids, representing a growth of approximately 8% relative to 2026 and about 10% growth on an exit-to-exit basis. That growth is led by the ramp-up of our Lator 4-13 facility and by Gold Creek, Karr, and Kaybob continuing to grow into available infrastructure capacity.
One item to flag for 2027 is a planned turnaround at our 15-07 gas plant and a third-party processing facility, both at Kaybob, in the third quarter. We expect it to impact third quarter production by approximately 32,000 BOE per day and annual average production by approximately 8,000 BOE per day. Condensate is a key driver of the economics of our liquids-rich Montney and Duvernay assets. In 2027, we anticipate condensate growth to 70,000 barrels per day. Condensate often trades at a premium to local light oil prices due to its required use as a diluent to transport heavy oil production, and Whitecap is well-positioned to capture this incremental growth and pricing opportunity. The successful execution of our 2026 capital program has now been well-documented, with demonstrated improvements on our capital efficiencies visible on both acquired and legacy Whitecap lands.
Cycle time compression has played a key role in these improvements, along with optimization of our cost structure. For the compressed cycle times, we are building on the gains we have seen from well-designed features such as lateral length, landing depth, casing configuration, and completion design. In 2027, we are also implementing new initiatives, including dual rigs and dual frac crews on multiple pad sites. We are also scaling our data-driven execution, building on the real-time frac optimization we discussed earlier to improve the accuracy and efficiency of our frac and drilling programs. With our large proprietary and public well data set, we expect these tools to keep getting stronger as every new well feeds back into them. Lastly, our size and scale are benefiting our cost structure and supply certainty. Our consistent rig lines and strong operating practices make us a preferred operator, and those benefits are showing through.
With that, I will now turn it over to Chris to discuss our conventional assets.
Thanks, Joey. Our conventional division continued to deliver in the third quarter with strong base production contributing to corporate production outperformance. Our third quarter program was active, drilling 49 gross, 39.1 net wells in the quarter, up from 36, 25.3 net in the third quarter of 2025. Base production outperformed expectations, driven mainly by proactive optimization in our central Alberta Glauconite assets, including a more aggressive drawdown strategy. Developed from our observation of reservoir response to drawdown, this strategy applies the methodologies and learnings from our extensive analysis of the unconventional asset base. We are pleased with the subsequent reservoir response and have adjusted our development plans accordingly, lowering the near-term capital requirement of the asset. This is a good example of the strength of our diversified asset base, where we can scale and transfer learnings quickly and consistently to deliver incremental value.
The conventional division has outperformed expectations for the first nine months of 2026, averaging approximately 147,000 BOE per day. Looking ahead to 2027, we plan to invest approximately CAD 600 million or about 25% of our total capital budget and forecast a more normalized level of production at 140,000 BOE per day. Stronger than expected 2026 production has been incorporated into our 2027 forecast, which allows us to moderate activity levels and generate higher free cash flow. In the Peace River Arch area of northern Alberta, our recent light oil-focused Charlie Lake wells have continued to perform above our expectations and offset wells. With nine months of production history now behind them, these wells we completed with our higher intensity design have outperformed wells completed with our previous design.
We are carrying forward the learnings from that frac design, along with an optimized landing depth into an expanded Charlie Lake program of 10 gross, 7.8 net wells in 2027. This program will incorporate updated drilling and completion design inputs that we expect will improve productivity and enhance capital efficiency. In Saskatchewan, our short cycle light oil-weighted assets in the Bakken, Frobisher, and Viking will represent over 80% of our Saskatchewan drilling activity in 2027 with 141 gross, 132.6 net wells planned. These are plays where our technical progress is evident. Over 40% of our 2027 Saskatchewan drilling capital will be focused on open hole multilaterals across our Frobisher, Bakken, and Weyburn assets. The use of this technology is repeatable, high-confidence design for us, ranging from two to four-leg wells in the Frobisher and up to 10 legs in the Bakken.
Open hole multilateral drilling is core to how we develop our Saskatchewan assets, and our confidence comes from a deep understanding of the subsurface and technical rigor. When we are drilling up to three miles out and threading each leg through the target zone, success depends on reservoir characterization, geo-steering, and precision in operational execution. We continue to look for more opportunities to deploy open hole multilateral technology across our portfolio. The division is further supported by approximately 50,000 barrels per day of aggregate waterflood and EOR volumes that have an average decline of approximately 12%. Waterflood and EOR initiatives are ongoing, and we continue to advance projects within our portfolio that strengthen our base. Since the beginning of 2026, we have increased production from existing assets under waterflood by approximately 2,000 barrels per day through our rigorous technical workflows, providing greater long-term sustainability of our asset base.
On an overall basis, our conventional assets are approximately 80% oil-weighted, and the economics of these assets are extremely strong in the current commodity price environment. Continuous improvement in operational execution and well performance, along with inventory enhancements such as drilling design, lateral placement, one to two mile inventory consolidation, and additional lateral length extensions, are further improving the long-term profitability of these assets. With that, I will turn it back over to Grant for his closing remarks.
Thanks very much, Thanh, Joey, and Chris, for your comments. Before we close, I want to summarize our outlook for 2027. Our 2027 budget invests CAD 2.4 billion-CAD 2.6 billion, with approximately 75% allocated to our unconventional division and 25% to our conventional division to deliver average production growth to 400,000-410,000 BOE per day. That translates into approximately 3% production per share growth, or approximately 5% excluding the planned turnaround at Kaybob in the third quarter. At current strip pricing, WTI pricing, the budget generates approximately CAD 2.1 billion of free funds flow and up to CAD 2.5 billion if the Productivity Mega Deduction is enacted as proposed. Whitecap's ongoing improvements in operational execution, lower cost structure, and production growth are becoming at a time when elevated light oil and condensate prices are further increasing the profitability.
Beyond the current price environment, Canada is increasingly well-positioned to grow its share of global energy supply. Additional pipeline egress is opening new markets for Western Canadian crude oil, and the federal government's recently announced Productivity Mega Deduction is expected to materially improve the competitiveness of the investment in the Canadian energy sector. At the same time, oil sands growth, LNG exports, and power demand from data centers are expected to drive demand for each of Whitecap's three core products: light oil, condensate, and natural gas. Whitecap is fortunate to have scale in all three. We are the fifth-largest oil and condensate producer in Canada and over 90% of our oil and condensate production exposed to light oil and condensate pricing, which has strengthened relative to WTI.
As the fourth-largest condensate producer in Canada, we are positioned to supply the diluent needed to transport growing oil sands volumes at approximately 75% of our 4,700 Montney and Duvernay drilling locations are liquids rich, providing the inventory to support further demand-driven growth into the future. Approximately 30% of our third quarter natural gas revenue came from sales into U.S. markets. Beginning in 2028, approximately 5% of our natural gas production will be exposed to European TTF pricing. Longer term, the Resthaven area provides significant natural gas optionality with over 1,000 undeveloped locations under management. With deep inventory across all three products, available infrastructure capacity, and exceptionally strong balance sheet, Whitecap has the flexibility to direct the highest return for opportunities as these markets develop. We also have the track record to back up our approach.
Since we closed the Veren transaction in mid-2025, we have executed on our strategy, delivering annualized production growth of over 5%, reducing our debt by CAD 1.2 billion, and returned CAD 1.5 billion of free funds flow to our shareholders through the base dividend and share repurchases. We are extremely excited to finish off the balance of a great 2026 and deliver on our stated goals for 2027. On behalf of our employees, our management team, and our board of directors, I want to thank you, our shareholders, for our continued support and confidence. With that, I will now turn the call over to the operator, Sylvie, for questions. Thank you.
Thank you, sir. Ladies and gentlemen, as stated, if you do have a question, please press star followed by one on your touch-tone phone. You will then hear a prompt acknowledging your request. Should you wish to withdraw your question, simply press star followed by two. We do ask that if you're using a speakerphone, to please lift the handset first before pressing any keys. Please go ahead and press star one now if you have any questions. Thank you. First question will be from Travis Wood at National Bank. Please go ahead.
Yeah. Good morning. You mentioned some comments around the Q3 turnaround. Would you be able to provide any kind of incremental commentary if you could? Do you see some opportunity to redirect some of those volumes during that downtime, given some maybe capacity flex in the area?
Hey, Travis. Thanks for the question. Yeah, first and foremost, like we said, there are two facilities in the area, one operated by us, one operated by a third party. Again, both coinciding in the third quarter there. You see the volumes back up in the quarter itself. With respect to some background behind it, I think most will be aware, but worth highlighting that planned maintenance, and that's what a turnaround is a core part of our business. We plan around these things. They come in predictable cycles, and we optimize all things around it being the cost it takes to do them, the time associated with it, and therefore the lost productivity. Then to your question there, the back part of your question, Travis, our ability to mitigate those downtime events.
What we've included in the 32,000 BOE per day of downtime in the quarter or 8,000 on the year actually is net of our efforts to do that. Our anticipated efforts, I should say. With that said, will we seek further opportunities to further either offload or mitigate those impacts through, like I say, offload or compressing the time associated with doing it? Of course we will, but at this stage, that's our best estimate for the impact.
Okay, thanks. I might have missed it. Did you guys disclose the days during the quarter in terms of downtime?
We didn't, Travis. Again, we decided it's a better perspective to give to the world the impact of the net barrels, because effectively that's what's going to be impacting, of course, production and therefore cash flow in the quarter. The days themselves, we'll again be looking to work not just with our own teams and associated contractors, but of course the third party as well to make sure that we've optimized around that and we've brought it down to as few days as possible, as you might imagine, Travis.
Okay. No, that's fair. I was trying to figure out if there was, or rather how much upside would be associated with that if it was ahead of schedule. No, I'll leave that there. Last question, probably for Thanh. You shared color in the opening remarks around the debt reduction. I think that was probably ahead of forecast as we think back to the start of the year in terms of debt, the pace of debt reduction. You've commented that the return profile for next year might lean more to a return of capital, but could you help us with some guardrails with respect to debt levels, how you're thinking about buybacks in this commodity price environment, given where we're sitting, and just help us understand how we could look at the pace of an NCIB through 2027?
Yeah, thanks for that question there, Travis. As we think about free cash flow allocation in 2027, as you know, we take a countercyclical approach. Which means in an elevated pricing environment there, we do prioritize delivering on the strength of the balance sheet, and then looking for opportunities to redeploy that in 2027. You are right, our leverage is quite low at this particular time. At the end of this year here, we are expecting our debt to be CAD 1.8 billion, which is 0.4 x debt to cash flow there. As we look out into 2027, on strip pricing and including the impact of the Productivity Mega Deduction there, our free cash flow will be about CAD 2.5 billion. So there is CAD 900 million that we would be allocating to the dividend, including the increase that we recently announced here, effective with the November dividend.
So there is a lot of optionality that is remaining for us to allocate that excess cash, whether that is towards additional growth projects, specifically around improving our long-term sustainability, being able to mitigate our decline rate, dividend enhancements, share repurchases, or even smaller tuck-in acquisitions, as well as continuing to put cash on the balance sheet there. So those are all the options that are available to us. I would say specifically around the share buybacks, they remain very compelling for us, and there are a few different reasons for that. Number one, as we look at reducing our share count, it is a permanent improvement to our capital structure. Not only does it enhance our per-share growth metric, but it also improves the sustainability of the dividend longer term as well there.
Y ou have to keep in mind that when we look at the inventory set that is in front of us, only 30% of our inventory is currently booked. So there is a huge opportunity for us to continue to increase our net asset value as we move through time. So we will continue to remain very disciplined and patient with deploying that excess cash. So we will look at those opportunities as we move through 2027.
Okay. Not to hold you to it, but there is a scenario, given if commodity prices continue to stay at these levels through at least the first half of the year. There is a scenario, I am reading between the lines, that debt repayment will continue to be the priority to leave more flexibility if there is a pullback in the commodity, and then lean into the buyback at better parts of the cycle?
Yeah, I think there's opportunities to, certainly in the short to medium term, to park that excess cash on our balance sheet. Our objective is in 2027 there to redeploy it to enhance returns for our shareholders.
Okay. That's all for me. I'll turn it back. Thanks.
Thanks, Travis.
Next question is from Dennis Fong at CIBC. Please go ahead.
Hi, good morning, and thanks for taking my questions. My first one follows a little bit along the lines of what Travis was discussing here, but a shift of the focus a little bit. I am just curious, in terms of the PMD, you have mentioned it a few times. How does the potential implementation of this Productivity Mega Deduction influence, we will call it investment opportunities, as well as how do you guys think about balancing, we will call it short-term quick payback projects like those seen in the unconventional, versus the longer-term opportunities like waterflood or EOR?
Yeah. It is Thanh here. With respect to the PMD, the way that it works is it needs to pass second reading, because we are in a majority government currently here, before we start reporting the benefits on our financial statements. Just a bit of a quick refresh. What that allows us to do effectively is on our drill complete equipment tie-in costs there, specifically on the CDE, instead of being 30% deductible on a declining basis, it is 100% deductible in year one. So really, that improves the economics on our capital program quite significantly, especially from an NPV perspective. I think where that becomes more important as we think about our conventional division is we have a big opportunity set in front of us in terms of enhanced oil recovery, which really helps the long-term sustainability of the business.
Low decline generates a ton of free cash flow and low capital investment ratios there. The PMD really accelerates the payout of those type of projects. So there will be opportunities for us, and it is an internal process that we are going through right now, looking at those projects that we could potentially accelerate in this pricing environment, but also taking into context the fact that for every dollar that we spend, it is 100% deductible now.
Just to further on that, Dennis, when we are talking about the Productivity Mega Deduction, at this particular time, we did not work it into our capital program or our budget for the year. We are growing production 5% from fourth quarter to fourth quarter, 2026 to 2027, already at the high end. And that is including the average that we have at 3%, includes that 32,000 BOE per day of downtime in the third quarter that we will try, as Joey said, to try and eliminate. But when we look at the conventional portion of our assets, our base plan, we will look to enhance that.
If we do get final reading on that, we will enhance per share growth as we have done in 2026 with operational performance. But stability and long-term sustainability of the conventional assets has put us in a wonderful position at this particular time with the excess free cash flow. We'll continue to look forward on that into 2027. Certainly, we're not completed, and this is a budget outlook that we provided at this particular time.
Great. Thanks for the commentary from both of you. My second question here is just on Lator. I appreciate the comments in the prepared remarks there, Joey. I was actually hoping you could elaborate a little bit more on opportunities or how you would observe seeing a 12-month ramp-up versus an 18-month ramp-up. Is there commodity price-related decisions that could be made there, or is this more driven by execution of the development program and/or productivity from the individual wells as being the more guiding factor?
Yeah. Dennis, I appreciate that. It might sound like a cop-out, but it's not. It's kind of all of the above, right? You look at the way that the asset is responding to our development, and if things are going better than expected, you might see us allocate incremental capital there, or you may see us also leave it how it is, and we just experience an accelerated ramp-up to that capacity there. When you look at general development, whether that's in Lator or some of the development we've talked about throughout the rest of the corporation, we're always trying to take those most recent results and feed them back in and understand, go forward, what is the optimal way of deploying that capital? And like you've suggested there, one of the influences to that could be also an increase to commodity prices.
The nice part about not just Lator, but the balance of the asset base is we do have the opportunity and the optionality to grow into a number of those assets. Spoke to it in the call there, or in the prepared remarks, I should say, but we do have capacity in Gold Creek and Karr that we can grow into. We're building out a little bit more in Kaybob, like we spoke to. And when you look at the amount of capital versus the amount of inventory associated with these assets as well as the conventional assets, it is an option to us that, again, we can lean into that strength.
Rather than trying to focus just on the asset targets in Lator or just on the specific ramp of that asset, what we're actually looking at is what is the overall balance of capital throughout the corporation, and ultimately, how do we turn out the most amount of free cash flow that we can?
Great. Thanks for that, Joey. Last question here. Shifting over to Charlie Lake. You've seen a planned uptick in activity driven from, we'll call it better than expected performance and opportunity set there. Can you talk a little bit more about, A, what some of the adjustments happen to be, whether it be completion or development techniques, as well as what the running room you have there in the Charlie Lake, in the Peace River Arch area to keep this incremental pace going? Thanks.
Yeah. Thanks for that, Dennis. It's Chris here. The two key adjustments, and we spoke about this in some of the prior quarters, is really just shared learnings from the unconventional workflow as it relates to improved frac design and efficiencies there. We did make some modifications on frac intensities and tonnage. That's one of the key things to take away from that. Along with, most recently, our teams have done such a great job digging apart the technical, and we do have a new design from a drilling perspective, more so from a landing perspective. So we're going to be targeting a different landing zone in the Charlie Lake. So those two key technical initiatives for us are part of the reasons that we're seeing a more robust go-forward appetite for the Charlie Lake and along with the results, of course.
With respect to running room, it's an area that we keep expanding upon and building on. Currently, right now, the running room for us is in that seven-year range, and we feel pretty comfortable with that at our accelerated pace, and we'll continue to endeavor to find more ways. As we've always talked about, nothing stays static with our inventory and our portfolio. Our teams do such a great job continuing to find those organic opportunities to enhance and continue to build on that for the Charlie.
Great. Thanks, Chris. I'll turn it back.
Okay. Next question will be from Aaron Bilkoski at TD Cowen. Please go ahead.
Thanks, Sylvie. My question is on the conventional division. You guys are talking about better base performance combined with improved drilling and completion designs. But if I look at this on a year-over-year basis, it seems like you're spending CAD 50 million-CAD 100 million more, drilling roughly 50 more wells year-over-year. While guidance seems to imply about a 4% production decline within the conventional business. I guess, can you help me reconcile higher activity with the production outlook? What I'm trying to get to is, why doesn't the stronger base and higher activity translate into at least flat conventional production?
Hey, Aaron, it's Chris here. Thanks for that question. We did set the bar pretty high with our base oil performance and technical improvements throughout the year, which you've hinted at there. I think the way we look at this here is really at the end of the day, we're building our budgets from the bottoms up. We're selecting projects based on technical merit, economics. We're factoring in risk or risk-adjusted projects, of course, the pace of development, along with strategy and infrastructure. Really, the goal here is how do we generate the strongest free cash flow program or profile, rather than a production target for us. So the 2027 production level is really an output of that, and when we think about the conventional division, the normalized production level is probably around that 135,000-145,000 BOE per day range.
Again, really the takeaway here is that we are optimizing for free cash flow with what we put together for 2027 with the framed activity levels.
Maybe I will add on to that, Chris. Just from the overall, you look at the growth that we have delivered, Grant said it at the outset there, that the 5% growth as measured Q4 - Q4, it is on the higher end of our range. Importantly as well, you look at the capital efficiencies of the corporation at CAD 18,500 per flowing BOE, which is equivalent to what we saw in 2026, in spite of a little bit of inflationary pressure. There are some pretty healthy overall capital efficiency numbers in the corporation. Again, to Chris's point there, maximizing free cash flow at this time, this is an opportunity for us to do exactly that in 2027.
Thank you.
Ladies and gentlemen, a reminder to please press star one should you have any questions. Thank you. Next, we will hear from Patrick O'Rourke at ATB Cormark. Please go ahead.
Hey, guys. Good morning, and thanks for taking my questions. Maybe just to go back to Lator and in terms of the ramp up. I know you talked about sort of applying learnings. You've got up to 12 - 18 months. If we think about the guidance that you've put in place corporately for 2027 here, how would that sort of gravitate between the 12 and 18 months and what sort of risking have you done in those numbers that are embedded in the guidance?
Yeah. Thanks, Patrick. Oops, sorry, getting a bit of feedback from you there. There you go. Yeah, like I said there, the range that we provide there is going to be dictated by a little bit of results and a little bit of input, so a little bit of output as well as input there. What we've worked into the overall forecast is, like I say, it'll be somewhere in that range. Again, hesitating to provide specific asset level details on that one when we're establishing that it's not the output that we're targeting. We're not targeting an exact date at an exact volume. We're targeting the maximization of the results of the totality of our capital program. Again, the output would be somewhere in that range. So recognize that there's probably a bit of a desire to hear an exact number.
Is it closer to the 12, or is it closer to the 18? But at this time, again, we're comfortable that with the range of expectations we can expect from the asset and the range of inputs that we might put to work there being on the capital side, that it'll be in between those two there, Patrick.
Okay, thanks. You guys have touched on a couple of times, a little bit of inflation in the industry. Obviously, we can see inputs like diesel would naturally be up in this pricing environment. But maybe if you could point to sort of what the key pressure points that you're seeing are in terms of inflationary pressures and sort of what mitigations or efficiencies you're thinking about to sort of manage this in 2027.
Yeah, thanks for that question. This is Travis Tweit. For the back half of 2026, we are really comfortable with our existing guidance, given that we have locked in much of our pricing. As we look ahead to 2027, on the OpEx side, we are forecasting about 3% inflation, driven largely by fuel and power costs.
Just general service inflation. On the capital side, we expect a very modest increase overall of about 2%. This is really an offset of inflationary pressures on diesel casing and labor. We are offsetting that with a lot of our improvements to our completions cost structure as well as our overall D&C efficiencies. As we go forward, the longer the diesel prices remain elevated, definitely the greater the downstream cost pressure will be across the supply chain. We are just focusing on what we can control, which is displacing our diesel with self-supplied natural gas on the majority of our D&C operations in the unconventional. Going forward, about 2% on the capital.
Are you seeing any pressure, inflationary pressure, tightness in terms of the rig market or frac spreads?
The market is definitely tightening up, but we have long-term contracts in place with all of our key rigs, and we have just locked in our key suppliers for frac as well. We are feeling really good about that over the next few years here.
Okay. Thank you.
Thank you. At this time, gentlemen, we have no other questions registered. Please proceed.
Thank you, Sylvie, and thanks to each of you online today who continue to support us. From our entire management team, I want to once again thank our Whitecap staff, our contractors, for your relentless and focused efforts on delivering a very strong third quarter and year-to-date performance. We look forward to updating you on our progress through the remainder of the year and into the 2027 year. Wishing everyone all the best for the remainder of this year and 2027. Back to you, Sylvie.
Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending, and at this time, we do ask that you please disconnect your lines. Enjoy the rest of your day.