Morning, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's 2022 Montney Webcast and Conference Call. As a reminder, today's call is being recorded. At this time, all participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Members of the investment community will have the opportunity to ask questions and can join the queue at any time by pressing star one. You may also submit your questions through the Q&A box on the webcast page. For members of the media attending in a listen-only mode today, you may quote statements made by any of the Ovintiv representatives. However, members of the media who wish to quote others who are speaking on this call today, we advise you to contact those individuals directly to obtain their consent.
Please be advised that this conference call may not be recorded or rebroadcast without the expressed consent of Ovintiv. I would now like to turn the conference over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.
Thank you, Operator. Good morning, everyone, and welcome to our 2022 Montney Webcast. This call is being webcast, and the slides are available on our website at ovintiv.com. Please take note of the advisory regarding forward-looking statements at the end of our slides and in our disclosure documents filed on SEDAR and EDGAR. We're excited to spend some time with you today describing our tremendous Montney asset. Today, you will hear from our senior executive team as well as a few of the folks responsible for the excellent day-to-day operational and marketing execution that you see in our materials. After our prepared remarks, we'd be pleased to take your questions. Please limit your time to one question and one follow-up. If you have further questions, please feel free to rejoin the queue. In addition, for this webcast, we have provided a written Q&A option.
Please follow the instructions on the webcast to submit a question, and we will get to those questions as well. I will now turn the call over to our President and CEO, Brendan McCracken.
Thanks, Jason. We are continuing to execute on our returns-based strategy. We're pleased that you've chosen to join us today to shine a light on a world-class asset we think is underappreciated in our portfolio. We know from talking to our investors that many of our current shareholders know our Montney asset quite well, but we also know that many investors don't follow the play as closely. We designed this material and presentation to give all investors a better understanding of just how impressive this asset is for us. As you'll see, our Montney is one of the highest return oil and gas plays in North America. The quality and depth of our resource, our scale, and our innovative approach to development differentiate us as a leader in the basin.
One of the most important takeaways from today is that we've taken concrete steps to transform our Montney market access so we will realize premium prices for both our condensate and our gas. Investors have long understood that our Montney condensate gets premium pricing, and now we've also managed to effectively move the sales point for our Montney gas to premium markets as well. Our marketing team has a proven track record of managing our exposure through both physical and financial arrangements that help to maximize the margins we receive for our products. We spent the past year building a long-term market access position that sets us up to maximize the value of our Montney production going forward. Today, you'll hear from several of our leaders on how we're achieving basin- leading performance and how that's translating into our corporate results.
I'm always impressed that our Montney team continues to innovate and deliver step changes in productivity and efficiency even after 15 years of continuous improvement in the asset. Our resulting capital efficiency is delivering substantial free cash flow and reflects our proven culture of innovation. The team will highlight some of our recent successes stacking multiple innovative ideas together to continue to drive efficiencies and performance. Across our portfolio, we're generating superior return on invested capital, and that is translating into direct cash returns to shareholders. We've increased our base dividend by over 250% in the past year, and we have just recently doubled our incremental cash returns. These returns are set to double again as we head into next year at flat prices. We're also rapidly driving down debt, and we're on track to see $3 billion of net debt by the end of the year.
We believe that over the long term, the most valuable E&Ps will be the companies that can deliver durable cash returns. The ingredients for delivering durable returns are a deep premium inventory, the culture and expertise to convert that inventory to free cash flow, and disciplined capital allocation to ensure capital stays focused on high return uses. We are well-positioned on all three ingredients. With respect to the first ingredient, corporately, we've assembled a deep premium inventory of both oil and gas, and the Montney is a unique basin since it has both. If we take a step back in time for a moment, the past 10 years clearly favored oil over gas. We identified that this would be the case a decade ago.
This was deeply inconvenient since at the time we were almost 100% natural gas, and a lot of that was gas in rocks today that struggled to compete for capital. As a result, we had to significantly pivot our portfolio. When we look forward at the macro landscape today, it is much less clear which product will be the winner. There are reasons to be optimistic on both oil and natural gas, and in that scenario, we believe the best strategy is to have options to invest into either. In contrast to 10 years ago, this is now deeply convenient for us. We have a balanced production mix already, and we have a deep premium inventory in both oil and gas. The second key ingredient is our culture and expertise, which unlocks our ability to convert premium inventory to free cash flow at a superior return on invested capital.
Our culture of innovation and the people driving the day-to-day execution of our business are truly differentiating. Our team can take credit for a number of industry records, efficiency standards, and creative solutions. We create this culture by sticking to four differentiating values. One, agile, innovative, and driven have guided our organization for the past few years. These pillars are lived out every day on our job sites and in our offices. We combine our premium inventory and leading efficiency with disciplined allocation to ensure we're generating both superior returns on the capital we invest and return of cash to our shareholders.
Throughout the rest of the webcast, you will hear a detailed overview of our Montney resource, our differentiated market access and price diversification strategy, and the key development practices which have led to industry-leading well-performance, lower costs, and superior returns, all of which unlock our Montney and make us very excited about the future of the play. I'll now hand it off to Corey to cover some of our key corporate update items.
Thanks, Brendan. We're coming off a strong second quarter where we achieved several key corporate objectives. We set a cash flow and free cash flow record that has stood for over a decade, and we increased our shareholder return percentage from 25%-50% of post-base dividend free cash flow. This increase will result in $389 million return to shareholders through base dividends and buybacks in the third quarter. This quarter, we've repurchased approximately 6.7 million shares. This almost doubles the shares we had repurchased up to the end of the second quarter, bringing the total to over 14 million, or about 5% of our shares outstanding since we launched our buyback program about a year ago. The significant step change in cash going back to our shareholders can be seen in the chart on the right of the slide.
Our fortified capital structure and lower long-term debt have led to a revised benchmark hedging strategy. This drives another potential step change in cash flow and cash returns to shareholders in 2023. Our volumes hedged are much lower than 2022, and our upside participation on those structures is significantly higher. This reduced hedge profile has the ability to drive incremental free cash flow to distribute to our shareholders through our return framework. We're on track to deliver $1 billion to shareholders in 2022. With our recent shift to 50% shareholder returns and the upcoming hedge roll-off next year, we expect returns to more than double in 2023. We're also committed to growing our base dividend over time. We see this as a core component of our value proposition for shareholders. We currently have a base dividend yield of about 2%, which is very competitive across industry and the broader market.
In addition to the significant progress we've made with our shareholder return offerings, we've also made substantial strides in deleveraging our balance sheet. At the end of the second quarter, our net debt sat at $3.9 billion, almost $3.5 billion below where it was just two years ago. Our weighted average long-term debt maturity stands at about 10 years today, and we recently redeemed the entire $1 billion principal value of our 2024 notes, generating approximately $55 million per year of annualized interest expense savings. Finally, we're attacking our debt stack in the open market today. We've taken out approximately $340 million of long-term notes through open market repurchases since the beginning of the year, with $279 million of that coming in the third quarter alone. I'll now turn the call over to Greg to start to dig into the details of the Montney.
Thanks, Corey. I'm excited we get to highlight our Montney asset today. As you will hear from members of the team, the asset plays a crucial role in our business, and we continue to make the play better every year. Our Montney is set to generate over $2 billion of upstream operating free cash flow this year. This is the highest among all our assets and allows us to execute a number of key corporate objectives. This strong asset-level free cash flow is underpinned by our leading capital efficiency in the basin. Today, we see outstanding individual well returns at Strip of over 200% in both the condensate and gas windows. As I just alluded to, our operations cover two distinct areas. We have multiple pay windows and a substantial product optionality across our position.
We like to think of this as a one-stop shop where we can deliver impressive natural gas rates or highly productive condensate wells. We have captured a deep premium inventory across our Montney acreage with more than 10 years of premium inventory in the condensate window and more than 30 years of premium inventory in the gas window. Finally, these strong well results and performance don't mean much if we can't sell or move our product. We are leaning on our multi-decade history of operations in the basin here. We are receiving strong prices for our products with our condensate volumes realizing 100% of WTI and more than 90% of our natural gas volumes priced outside of AECO going forward.
We have already highlighted the robust upstream operating free cash flow generated by the Montney, but I want to take a minute to outline what the asset looks like going forward. In the near term, we have the option for modest growth depending on our capital allocation outlook. We also continue to drive efficiency gains and improve well results. In fact, we drilled some of our most efficient and prolific wells in the asset's history in just the past few months. Over the medium and long term, the basin as a whole benefits from substantial LNG capacity currently under construction on the west coast of Canada.
Jim will cover this more later in the call, but there is two BCF a day of LNG that is already under construction and set to come online in 2025, and an additional four BCF a day of projects under various phases of assessment that could be online not long after. Today, we are the largest operator in the Montney. Our multi-decade history and operational scale in the play create development advantages that drive our efficient performance and understanding of the basin. While we have over 750,000 net acres across the Montney, our current focus is on our 260,000 premium net acres in the core. Our premium net acreage is split relatively evenly between British Columbia and Alberta, providing substantial development optionality across the position. As you can see on the map, our acreage position consists of large consolidated blocks.
This sets up extremely well for our proven cube development approach, which maximizes returns and resource recovery. The Montney truly is a world-class resource, and it is worth highlighting that the basin boasts one of the largest stacked pay windows across leading North American shale plays. With up to 1,000 feet of stacked pay, the subsurface is primed for effective cube development, one of our core strengths. Today, we are focused on maximizing value out of the upper, middle, and lower Montney formations. On average, we are developing the resource with about 12 wells per section. This density varies depending on where you are on our land base, and we ultimately engage in a full field development at density from anywhere from 8 to 27 wells per section. We are delivering strong wells and great returns at these spacing ranges and continue to optimize every development to maximize resource recovery.
While the Montney may traditionally be known for its strong gas wells and resource, the play also has prolific condensate potential if your acreage is in the right spot. We have over a decade of condensate inventory in the asset today. As you can see by the phase windows on the map, the majority of our 115,000 premium condensate acres sits on the Alberta side of the border. The returns from these wells are outstanding, and our tight curve for this area achieves a payout in less than six months at current Strip pricing and approximately 16 months when using a modest mid-cycle price deck of $55 WTI and $2.75 NYMEX. These results are as strong as any oil play in North America and reflect our approximately $550 per foot 2023 DCF&T cost structure.
We are confident in our running room in this phase window and continue to assess and appraise our condensate acreage to determine if we can convert additional inventory to premium in the future. As I just noted, I don't think there is confusion about the gas availability in the Montney. However, I do think the well quality, returns, and inventory life are underappreciated. Our gas wells compete with some of the best in North America. In fact, our stacked innovation development approach helped us achieve over 200 million cubic feet per day from a recent seven well pad. It is also worth noting our gas window wells are not entirely dry and provide a 10% liquids cut.
Our tight curve for this area has strong economics and realizes payout in less than six months at Strip and 16 months at mid-cycle prices, which stacks up well against even the best gas plays. Again, these metrics reflect our 2023 capital cost structure. With over 30 years of premium inventory in this window, we are well positioned to capitalize on long-term natural gas price strength and evolving global energy trends. I'd like to take a moment to talk about our capital efficiency compared to our Montney peers. Here we are showing 2022 CapEx divided by second quarter 2022 production, adjusting for some reporting differences. There is a wide variety of development approaches being deployed in the Montney. Some operators pursue a strategy to minimize cost, which risks having completion intensities below optimal levels, while others pursue only a portion of the stacked pay package.
Our cube development approach optimizes both the returns and the NPV of each acre we develop. The result is that our capital efficiency screens as a clear winner in the basin. Another way to think about it is if our Montney capital efficiency matched that of other Montney peers, we would have to spend more than double the annual capital to achieve our production. This efficiency, combined with holding 13 of the top 15 spots for well results over the past 12 months based on public data, reinforces our position as not only a leading Montney operator but also a leading industry-wide operator. We highlighted our tight curve performance a minute ago, and now I want to highlight a few of our recent results that demonstrate we are continuing to drive even better productivity.
The performance you are seeing is driven by technical, operational, and commercial teams across the company working together to maximize every cube we bring online. On our 16 of 27 pad, we had condensate wells that achieved over 1,000 barrels per day, an outstanding achievement for a basin that has been pegged by some as a gas play. On the natural gas side, we also have a number of recent eye-popping results. Our 13 of 33 pad had multiple wells realize gas production of over 30 million cubic feet per day per well. Both of these OVV results reinforce the world-class resource potential of the Montney, the true commodity optionality that exists within the basin, and the ability of our team to continue to maximize returns and resource recovery in a play we have been in since the early 2000s.
I would now like to introduce Tony Baffa, our Senior Manager of Canadian Development. Tony and his team do a great job of maximizing value of the asset. Tony is going to cover royalties and permitting.
Thanks, Greg, and happy to be on the call today. One unique aspect of shale development in Canada is a sliding scale royalty structure. As the name suggests, the percentage royalty that you pay slides up and down based on prevailing commodity prices. On the slide, we've provided royalty rates across a range of prices to provide a simple model for our investors. This is unlike most of the basins in the U.S. where royalties are fixed, typically somewhere around 20%-25%, regardless of where commodity prices move. We have provided a few examples on the slide to outline how these royalties slide up and down depending on various price scenarios. I think one thing worth highlighting is the strong returns across our condensate and natural gas development windows at the higher pricing sensitivities like Strip today. The royalties at Strip are in the mid-teens across all products.
This is a little higher than our lower sensitivities on the page, but still below the average U.S. basin royalty range and more than offset by the incremental returns from the higher commodity prices. On the flip side, when commodity prices drop, the royalty rates drop, which helps make returns more resilient to lower prices. There are incentives that work to reduce actual royalties paid by the operator. In the end, the sliding scale royalty framework, while different from traditional U.S. basins, is beneficial to Montney competitiveness. Moving on to the current permitting and regulatory landscape on the British Columbia side of our acreage, the key takeaway is that Ovintiv is well positioned to execute our 2023 program in the BC Montney. While there's no official agreement to report on, we continue to see permits being issued.
In the last month, we have received 19 new well permits, and combined with the permits in hand, we have the majority of our 2023 permits secured and are highly confident in our ability to execute on our BC acreage. Regardless, we continue to maintain the ability to move capital to Alberta or other assets, just like we did in 2022 to achieve our business plan. With that said, I would like to introduce Aaron Felton, our Chief of Operations Engineering. Aaron and I, along with our respective teams, work closely to execute our development plan.
Thanks, Tony. I want to cover a key aspect of our business, which both defines and differentiates Ovintiv as an operator in the Montney. This section is called the Ovintiv Edge for a reason, and I think our outstanding operational performance is clearly seen in our results. We take great pride in our completions execution, drilling performance, prudent development approach, and finally, our ability to stack multiple innovations together to create needle-moving results. First and simply put, we are drilling longer laterals in less time than our peers. Our drilling cycle times have remained a step ahead of peers for a number of years, and so far in 2022, we are executing 35% faster than the peer average. We also continue to lead industry in longer lateral development. Our 2019 lateral length in the Montney was not matched by peers until 2021, two years later.
This story continues on the completion front. We are completing wells faster and with more profit than our peers, which translates to better wells and higher overall returns. We are pumping 90% more profit per day than peers so far in 2022 and have maintained this level of leadership for years. In addition to more profit per day, we are completing more lateral feet per day than peers. This is despite our larger and more complex completion designs that lead to higher recovery and returns. Our Montney operations deliver leading results through our stacked innovation approach. I will cover some of these initiatives in detail later during our 14 of 13 case study. Here, I want to highlight our proven record of lateral length extension. While this may sound easy, it is actually quite challenging and involves a multi-pronged attack between our technical, operational, and commercial teams.
You can clearly see our methodical lateral length progression here, where we have been able to increase wells by over 2,000 feet since 2019. We have done this through continuous innovation and setting new performance standards for the equipment and providers we use in our wells. Increasing lateral lengths has helped us manage our costs in an inflationary environment like we are in today. This year alone, we have drilled several wells with our lengths exceeding 15,000 feet. In 2023, we see our average Montney well costing $550 per foot across drilling completions and facilities. Not to be outdone, our completion team has been setting an efficiency frontier of its own. Not only are we completing 60% more lateral feet per day on average in 2022 versus 2019, but if you look at our pace setter performance, we have almost tripled our 2019 performance.
Our completion team has been breaking down barriers and driving performance records we previously thought wouldn't be possible. Part of our success in the Montney is driven off the use of simul-frac operations for a large portion of our completions. This is a technology and approach that was piloted in the Permian and quickly distributed to the rest of the Ovintiv portfolio once it was proven to work. This technology was also the driving force behind our record sand pace setter of 19 million pounds pumped in one day, a three and a half times increase versus our 2019 performance. These completion pace setters were both set on our recent 14 of 13 pad in the Alberta Montney, which saw the benefit of our leading stacked innovation approach. As I mentioned, our recent 14 of 13 pads set a number of operational records for our Montney asset.
We wanted to provide a case study into our stacked innovation approach and some of the key drivers of this performance. On the drilling side, we utilized three top spec rigs along with highly coordinated logistics, a redesigned drill bit, and optimized motor to set an Ovintiv Montney drilling record of over 2,400 feet per day. This record speed resulted in sub-10 days spud to rig release for the wells on this pad, which is 20% below our 2022 Montney average. We continue to stack our innovations on the completions front with our real-time frac optimization approach and our proven simul frac operations. Collectively, these innovations, along with a number of other smaller initiatives, set an OVV Montney 24-hour completion record of 10,375 feet and a single-day proppant record of over 19 million pounds.
Finally, we use multiple coiled tubing units and integrated service rigs to tie in 15 wells and set an Ovintiv Montney pad production record of approximately 12,000 barrels per day of oil and condensate, plus associated gas and NGLs. This case study clearly shows the power of the culture and stacked innovation approach we have here at Ovintiv. What I may be most excited about is the fact that this pad just came online in the third quarter, paving the way for additional performance progress in other areas and going forward. For example, Greg mentioned earlier the incredible gas rates achieved on our recent 7 well 13 of 33 pad. This is a testament to the repeatability of our stacked innovation approach. Last but not least, this performance is something we will transfer to our other assets through our proven multi-basin learning approach.
I'm now going to turn the call back over to Tony to cover a few of the other initiatives and operational proof points.
Thanks, Aaron. Another area where our Montney is paving the way for the basin is the introduction of the first 100% natural gas frac spread in Canada. We are rolling this crew out in the coming quarters and see this approach achieving a number of operational and strategic objectives. Not only will we realize an 80% reduction in fuel costs by utilizing natural gas, but we will also forgo over three million gallons of diesel usage per year, which will reduce emissions and logistical complexity. This crew also provides a reduction in required manpower and equipment, a crucial benefit in today's supply chain and labor constrained environment. While we'd love to boast about our outstanding well results and drilling and completion efficiencies, we are also very proud of our safety performance.
Safety is one of our core values, and we take pride in operating the right way, taking the time to advance and ingrain a safety culture top to bottom throughout the workforce. 2021 was our eighth consecutive safest year in a row as a company, and our entire Montney team is proud that our total recordable injury frequency is approximately 85% lower than the Montney peer average. As a leader of this asset, I take it upon myself to live out our safety culture every day and cannot be more proud of the Montney team and the broader Ovintiv organization for its performance in this area. In addition to safety, we also take pride in looking after our emissions performance at both the corporate and Montney asset team level.
In 2021, we achieved a Scope 1 and Scope 2 GHG emissions intensity that was 60% below that of our Montney peers.
We have taken a proactive approach throughout the organization to be a leader in this space, and the Montney plays a key role in this initiative. I mentioned the rollout of our 100% natural gas fleet a minute ago, but the Montney also benefits from numerous other approaches to lower emissions. For instance, substantially all of our production operations today run on hydroelectric, natural gas, or renewable power. We have also implemented a number of proactive emission reduction projects to date to improve performance. We continue to be thoughtful in this area and strive towards our corporate-wide scope one and two GHG emissions intensity reduction goal. With that said, I want to introduce Jim Zbierajewski, our Vice President of Marketing, to cover how this team takes the production we bring online and maximizes its value.
Thanks, Tony. We've gotten a lot of questions about what's going on at AECO recently, so we wanted to start by talking about the overall market before turning to our advantage position. AECO is one of the most liquid and transparent natural gas trading hubs in the world. As a key North American supply basin, about 40% of production is consumed within the basin, and about 60% is exported to demand centers in the U.S. and Canada on five long-haul export pipelines, which together have more than 10 BCF per day of total capacity. Intra-basin demand is growing, supported by oil sands and power generation, and the market is anticipating substantial LNG exports off the West Coast of Canada beginning around mid-decade. Although there are reasons for optimism, especially once LNG comes online, prices have been weak lately on a combination of high supply and pipeline maintenance.
Fortunately, and this is the most important thing you will hear from me today, Ovintiv's Montney asset can continue to deliver highly competitive returns even in a very weak AECO price environment. We have been very intentional in moving our price exposure away from AECO to downstream markets in the U.S. and Canada, and we have done that both physically by acquiring firm transportation out of the basin and financially with basis hedges. During the prior AECO downturn in the 2017-2019 period, Ovintiv was essentially unexposed to the AECO weakness, and likewise in the 2023-2025 period, more than 90% of our Montney gas will continue to be priced outside of AECO. Before I get into the details of our Montney marketing advantage, I want to describe the gas market in Western Canada.
Demand growth and pipeline capacity additions have generally aligned with production growth, but there are periods of tightness, including today, where production comes close to or even exceeds in-basin demand and export capacity that causes AECO to weaken. We expect in-basin demand will continue to grow, supported by oil sands and power generation, with additional demand growth coming from expanded export pipelines. But the biggest supporting factor in the supply-demand balance is waterborne exports, which we anticipate ramping up beginning with phase one of LNG Canada in 2025, which is currently about 60% complete. Combined, this represents about 3.5 BCF a day of demand growth from 2021 through 2025 across in-basin demand growth, expanded pipeline exports, and phase one of LNG Canada, with nearly 5 BCF a day of additional upside from 2025 through 2030 across LNG Canada phase one and two and other proposed projects.
The chart on the right compares a decade of AECO market pricing to the Permian and Marcellus, which, like AECO, are export-reliant basins with more in-market supply than demand. Although recent AECO dislocations are notable, this is typical of other growth basins. So the real key question is not whether AECO or any other supply basin will be volatile. The question is, what can we do about that volatility? We've been watching and managing our AECO exposure for decades and are proactive in both physical and financial markets. We hold substantial capacity on four of the five major egress pipelines exiting AECO. In the second quarter, we announced additional firm transportation capacity on the Alliance Pipeline beginning this November. This capacity provides both Montney intra-basin egress and AECO price diversification.
Beginning in 2023, we will sell approximately 65% of our Montney gas at points outside of AECO, including at Dawn, Malin, Sumas, and Chicago. These are firm transportation agreements that last well beyond 2025. An additional 20%-25% of our Montney price exposure is covered by financial AECO basis or ratio basis swaps. These convert our natural AECO exposure to NYMEX. So while the gas will be physically sold at AECO, we effectively receive a NYMEX-based price for those sales. If you recall, in the second quarter, we had 15%-20% of our Montney production financially hedged for 2023 to 2025. We've added to those positions since our second quarter release. The upshot is that more than 90% of our Montney production is protected from a weaker AECO from 2023 to 2025. Let's take a look at how this protection works.
In the third quarter of this year, NYMEX was about $8 per million BTU, and AECO was about half of that. Suppose we run a sensitivity that this weakness continues from 2023 to 2025. If our Montney gas were fully exposed to AECO without any physical transport or financial hedges, our post-Montney realizations would be 50% of NYMEX and 100% of AECO. We'd simply be receiving an AECO price for our gas. But if we run this extremely weak and prolonged scenario through the physical sales and financial hedges we have in place, the results are very different. At an AECO market that trades 50% of NYMEX from 2023 to 2025, we'd receive 90% of NYMEX post-hedge due to our portfolio risk mitigation.
So when you think about our Montney, think about our industry-leading operations and our advantage cost structure, but do not think about AECO because we simply do not have significant AECO exposure. The underlying gas supply and demand fundamentals in Western Canada should continue to improve in 2025 as LNG comes online. The market anticipates phase one of LNG Canada will be in service in 2025, with the related Coastal GasLink pipeline in service well ahead of the LNG facility. Coastal GasLink is initially compressed for approximately 2 BCF per day, with the capability of reaching 5 BCF a day of delivery capacity. Phase one of LNG Canada will be the first, but not the only LNG export terminal likely to come online in Western Canada this decade.
We see potential for more than 6 BCF per day of LNG export demand split across four different projects, including LNG Canada phases one and two. Our substantial gas resource is connected to both a key LNG feeder pipeline and to the NGTL system, which represents an expandable secondary access point to Coastal GasLink. We believe Western Canada and the Montney can be an important solution to the world's increasing demand for natural gas, supporting economic development and environmental solutions across the globe. The resource is enormous and the cost structure compelling. We spent most of our time today on the gas markets and AECO, but we wanted to also provide an update on Canadian condensate. Unlike AECO, which is an export market, condensate in Western Canada is an import market, with demand for condensate being driven by oil sands diluent requirements.
Condensate is blended with oil sands production to enable the resulting product to flow via pipeline or rail car. Condensate production in Western Canada has grown, and although we anticipate that growth will continue, Western Canada will remain net short condensate for the foreseeable future. As a result, we believe the marginal Western Canadian condensate barrel will price off the import alternative and will remain closely tied to WTI prices. So although the production is condensate by API definition, and while there have been temporary market dislocations over the years, our condensate realizes a price very close to WTI. To sum up our market discussion, on the gas side, we've moved our exposure away from AECO and to higher net back downstream markets and to NYMEX, in essence insulating our Montney from AECO price exposure.
On the oil and condensate side, Western Canada is in a structural condensate deficit, supporting prices at or near WTI. With that, I'll turn it back to Brendan for closing remarks.
Thanks, Jim. We're ending today's webcast where we started. We're actively delivering on our durable return strategy. Our portfolio is uniquely well-positioned for the coming decade. We're investing to generate substantial free cash flow and using that to rapidly pay down debt and return cash to our shareholders today. Our Montney asset generates amongst the very highest returns available anywhere. We have a deep premium inventory of both condensate and gas locations. We are the most capital-efficient operator by a wide margin. We are the safest and have the lowest emissions of any operator in the play, and we've ensured that we'll realize premium prices for our production going forward. Before we get to your questions, I want to make one final point. We're in a world today that has many uncertainties. We are seeing volatility throughout the world and in all markets.
We're navigating an era of strong commodity prices, but also inflation and supply chain disruptions. With all of that said, I just want to highlight how proud I am of the team we have here at Ovintiv. It is clear in both the materials we presented today and on the results across the company that we're meeting these challenges head-on and using our unique culture and tremendously talented staff to come out ahead. We'd now like to open the line for your questions.
Thank you, sir. Ladies and gentlemen of the investment community, we will now begin the question and answer session. As a reminder, you can join the queue to ask a question by pressing star one. Your first question will come from Neal Dingmann of Truist Securities. Please go ahead.
Morning all. Thanks for all the details. My question may be great for your team around slide 14, where you talked about spacing. Could you just talk a little bit more, maybe in detail, where do you have the prospect for maybe a little bit more detail on the upper, middle, and lower? When you guys now are tackling this and kind of in the plan, can you kind of talk about, is it multi-formational across most of your play, or how are you targeting that, and where do you have perspective for all three of these areas?
Yes, Neil, thanks for the question. Yeah, I think one of our challenges when we talk about the Montney is it's such a vast play. And even in our core position, we're expanding over such a large area that we do have variations in the pay thickness that we see from Alberta up into British Columbia. I think the thing that's most important for everyone to know is that we approach our development on a pad-by-pad basis, and we optimize our stacking and spacing for that particular pad. So on the earlier zones, we're going to have maybe a few less wells, or excuse me, more wells per foot, but depending on the thickness of the zones, you may have fewer wells. And it just really varies by where you are in the play. We're gassier over on the BC side, but we're also thicker.
And then on the Alberta side, we both got oil and gas. So it's going to vary by area, and we're going to optimize for whatever is the best to maximize returns and ultimately the NPV per acre.
And then, Greg, just to follow up, the only other one I had was just on the amount of sand. You guys said on that slide that you are sort of leading the industry on that. Is that across for all the type of wells, and whether it's a bit gassier or not, are you finding that you're just seeing results that more than make up for that higher cost of sand that you just talked about? Thank you.
No, that's a good question and a good point. We do find that we're being quite a bit more aggressive than average in the basin. We're pumping anywhere from 1,600-1,800 lbs per foot on our wells and around 800 gal per foot. Those higher sand concentrations are in the oilier parts of the play that have the higher condensate yields because we find that just due to the mobility of the fluids that you don't need quite as much sand on some of the gassier parts of the play. But again, we customize every design for every frac and every spacing and stacking for whatever we believe is going to maximize value for us in that part of the acreage.
Awesome. Thank you so much.
Neil, Brendan here. I'll just add to that. I think what's fascinating is you really see that differentiation in completion design show up in the capital efficiency numbers. And while you can find operators in the Montney, it's probably the play across our portfolio is the play that has the most dispersion between completion design approach, operator to operator. And you can see operators in some cases optimizing for well cost, so pumping a relatively small, low-complexity completion design and getting a lower well cost. But then the flip side of that is they miss out on the recovery factor. And so I think as you were alluding to in your question, the way we approach it is from an NPV per section and return on capital perspective and try and optimize for those two outcomes.
That's why you see the higher completion intensity and then the ultimate proof points in that capital efficiency, which is why we wanted to display it.
Okay. Thanks for that , Brendan.
Yeah, thank you.
Your next question will come from Doug Leggate of Bank of America. Please go ahead.
Thanks. Good morning, everyone. Thanks for all the information. I want to pick up on a couple of subtleties in the presentation, it seems, in the last summary you gave with second quarter results. And there's a couple of data points here, so forgive me running through these before I get to my question. Your gas inventory has now been talked about as more than 30 years. Previously, you said more than 20 years. Your type curve is clearly running ahead of the curve you've given us before. And I guess my question is, what are the implications for capital allocation? You've obviously touched on growth optionality.
It's a very capital-efficient asset, obviously, but I'm really trying to get to the nub of the question, which is, how would the free cash flow evolve in the Montney if the capital allocation shifted more towards gas away from liquids, which with a 10-year inventory presumably would decline? So it's really more of a capital allocation question within the Montney. What are you signaling to us today? That's my first, and I've got a quick follow-up on free cash flow.
Yeah, Doug, thanks for the question. A lot of good stuff to dig in there. I think I'll maybe just start with how we think about capital allocation and then come to how that's translating specifically to the Montney. So really, when we're thinking about allocating capital in the portfolio, what we're doing is trying to find the most effective, most efficient way to generate returns and free cash flow. And so along with that, of course, is a desire over time to grow the cash flow per share of the company. And so today, one of the things that we're doing is we're allocating capital to buybacks because we see that as the most efficient way to grow that cash flow per share. And so in that maintenance mode, we think that continues to make sense. We've talked about looking out into 2023.
That's probably our bias as we see the landscape setting up into 2023. Within the portfolio, we're doing exactly what you described, which is trying to find the optimal allocation within the assets to drive that efficient result, and so I think year over year on the Montney, looking out into 2023, you should expect to see some more capital spent there. Part of that's just because we didn't have a front-half program on the BC side of the play while we waited for the permitting to catch up, and so there'll be a bit of capital catch-up that'll happen in 2023 there, and the returns are very strong, and they'll be maybe kick it to Greg in a moment to talk about the well performance exceeding expectations on or exceeding type curve on the gas side, but just pick up your 30-year comment.
Obviously, we knew we had this day coming, so we wanted to start to prep the market for directionally what we were seeing for that gas inventory, and so what you're seeing today is us get the precise numbers out to the market, so pleased to be able to do that and show the depth and value that's in that acreage position for us, but maybe, Greg, you want to comment on the well performance this year?
Yeah, sure, Brendan. Yeah, we're really pleased with the results of this year's program. We've seen really impressive gas rates as well as impressive oil weight rates in the condensate window. Some of these advancements we've seen are due to these modern completions that we're pumping, this continuous improvement approach that we've been applying, trying more aggressive jobs, adjusting the way we stimulate the rock, and we just recently gone back to the gas window with some of these really new and modern completions. So we've been very impressed with the results, but we're also cautious in that this is a 30-year time horizon we're talking about with a significant number of wells.
And so we thought it was prudent to have maybe a little conservatism early days since we have a small data set of these new really high-performing wells, but really encouraged with what we're seeing in gas rates out of the Montney right now.
Guys, thanks for the color there. I guess my follow-up, and this is not necessarily related to the Montney, and I'll use consensus rather than be selfish in my own numbers, but if you look at 2023, to your point about the hedges rolling off and the shifting dynamics of the gas market, you're doing north of $4 billion of free cash flow as a company, as street, admittedly. Is it reasonable or is it unreasonable to consider that you guys could have a $3 billion buyback in 2023?
Yeah, I mean, Doug, love the flow through and the point to how the things are setting up in 2023 because it's the story we see as well. I think what we pointed to this year is a buyback of $1 billion, and we're on track for that and then we're seeing that more than double in 2023. So obviously, there's a commodity price assumption that has to go into the 2023 expectation, but without the benefit of seeing the numbers, the price deck you've got in front of you there, I think it's not an unreasonable dynamic to say we're going to meaningfully grow cash returns through buybacks next year.
Just applying the 75%, Brendan. Thanks very much indeed for taking my questions.
You bet, Doug. Thank you.
Your next question comes from Menno Hulshof of TD Securities. Please go ahead.
Thanks. And good morning, everyone. Brendan, you mentioned a growth option of somewhere between 0% and 5% for the Montney. So I guess my question is, what conditions would you need to see to get to the top end of that range over the next several years?
Yeah, thanks, man. I appreciate it. And we're careful to present it as a growth option. And so maybe if I zoom back out for a moment, talk about how we think about growth generally, and then we can apply those principles to the Montney here. Again, it's all about generating value and maximizing free cash flow and returns. So when we look at how to allocate capital in 2023, or even when we come to years out past that, I think what you'll see us do is optimize for that free cash flow generation and how can we drive cash flow per share at the company level. And so today, there's kind of really three big ingredients going into that decision-making. And first one is obviously the macro. What are we seeing set up for the supply and demand fundamentals for the products we produce?
The second big factor today is inflationary pressures and how is that eroding returns? Because, of course, adding incremental activity over and above the maintenance level in today's environment would be return eroding because you've got to pull that equipment in a competitive market. And then the final one for us is we've got to compare that growth allocation decision relative to buybacks because we can get the same cash flow per share benefit out of the buybacks that we could with investing for growth. And so those are the three factors that we're closely following. And we've been clear that if you run them through today's lens, it would bias us to another year of maintenance level at the company perspective.
But what we did want to highlight with the Montney is that we've got the building blocks to have that growth option if either it made sense to contribute to the company growth or if it just made sense to be reallocating capital within the company maintenance construct. And so we've got the processing capacity, we've got the market access, and we've got the rock and inventory to be able to execute on that 0%-5% growth option if it is the right value case to pursue.
Got it. Thanks, Brendan. Maybe I'll follow up with a question on LNG, and you did a great job of outlining the growth potential for Canadian export capacity through 2030. So how involved would you like to get as a potential supplier? What are the options or structures that you would consider? And then maybe you could just walk us through your advantage from an infrastructure perspective as well. Thank you.
For sure, Menno. Yeah. The great news for the basin is that there is an LNG pathway underway today. And Jim did a good job outlining between the in-basin demand growth that we're seeing and the LNG that's on track and in construction today. It's 3 bcf a day of incremental demand for Western Canada by mid-decade and then 8.5 bcf a day potentially by the end of decade. So it's great to see some of those tailwinds for Western Canadian gas. As far as our participation in LNG, it's the next logical extension of market diversification for us. Clearly, we've spent the last little while building a diversified market outside of AECO, both physically, but also through the basis hedges. And the next logical place to get some physical price exposure would be global LNG. Obviously, the arbitrage is very attractive today.
I think we're going to be very thoughtful and disciplined about this. We're not going to take an equity position in an export terminal, but we do think there's the potential to continue to explore commercial supply deals. That's what our team's focused on today: evaluating those, both either West Coast or Gulf Coast. The good news about our portfolio is we can supply gas to either of those two egress points off of North America. In discussion today, nothing imminent, but something we'd love to be able to do in the coming little while.
Thanks, Brendan.
Yeah, thanks, man.
Your next question comes from Neil Mehta of Goldman Sachs. Please go ahead.
Yeah, good morning, Brendan and team. Thank you for this very, very helpful. The first question is just around how are you thinking about inflation in the Montney relative to the rest of the portfolio? Is this a region where the inflationary dynamics are favorable? And now you've guided to $1.7-$1.8 billion in CapEx this year. Is that still a good number for us to be thinking about and any early thoughts on 2023? So there's a lot in there, so that is my one question, but just your thoughts on CapEx.
Thanks, Neil. Yeah, we're for sure happy to address all of those. Maybe just start with the inflation in the Montney. This is a relative answer. Let's recognize this first. So we're seeing inflation in the Montney for sure, but it is relatively better than the U.S. basins that we operate in. I would say on a year-over-year inflation basis perspective, it's several percentage points lower than what we've seen in places like the Permian and Oklahoma and North Dakota. So it has been relatively better for us, and that trend seems to be continuing if we look out into 2023. So that's another tailwind for returns and free cash flow generation in the Montney.
On your question on capital, for this year, for 2022, yeah, we're set up to be able to stick in the 1.7-1.8 capital guidance, but it's been a challenge to the point you're making on inflation. One of the things that we're very much thinking about as we run through the back half of this year is we're trying to make 2023 more ratable for our business, more ratable on a CapEx per quarter, but also more ratable on a production profile through the year, so that's just a spot that we're paying a lot of attention to. We're continuing to see market price increases for that 2023 work, and that's something we're going to just keep managing through and do good supply chain work. A lot of that is wheels in motion today, so.
Brendan, appreciate the call.
Yeah, thank you.
I think we'll shift to a couple of questions from the webcast, and then we'll jump back into the queue. There's a number of questions that have common themes, so I'll try to summarize them into specific questions. Maybe start with one here. You've shown a significant edge on Montney capital efficiency in the slide deck. How are you outperforming your peers by such a wide margin? And how do you calculate the capital efficiency?
Yeah, thanks, Jason. I'll take that one on. I guess first we should talk about why we think our capital efficiency is as strong as it is. And it really comes down to, as we showed on slide 23, we just operate differently from our peers. We're continuing to push the leading edge on lateral link, on speed at which we drill and complete our wells. We're really focused on completion intensity. As the team highlighted, I mean, we're the only operator out there that can talk about 19 million pounds of sand in one day. So these larger jobs we're completing, and we're doing them faster than our peers. And this is all part of what Aaron talked about with our stacking innovation. We've got this continuous improvement approach that we're continuing to get better.
And as we showed in the deck, we feel like we're several years ahead of our peers. And that's both on an efficiency side, but also on a productivity side. We're yielding really impressive gas and condensate rates. And we showed there's 13 of the top 15 wells are Ovintiv wells, and all of that's being done at a competitive cost basis. So when you put all that together, it's no surprise that we're going to have a really good capital efficiency. But as far as how we actually calculate the number, it's fairly straightforward. We're just taking total capital divided by total production for our Montney asset and for our peers.
We do a slight adjustment for royalties since we report on an NRI basis while many of our Montney peers report on an NBR and that before royalty basis, whereas we're using more of a standard measure like we use here in the U.S., but with all of that taken into account, no matter whether you look at it on a crude and condensate basis or several different ways you can calculate BOE, no matter how you stack it up, we've got significantly better capital efficiency than our peers, and really, that's one of the key ingredients in us being able to deliver these durable cash returns, and that's why we talk so much about capital efficiency. We just believe that that's a competitive advantage for us in the Montney and across all of our plays.
Yeah, just to jump in there and close, I mean, Greg mentioned it, but it really is the connectivity to this durable return strategy that is why we're so focused on that capital efficiency. And it adds up to hundreds or billions of dollars a year of incremental free cash flow as a result of that efficiency edge relative to others. And we all know in our industry, there is no intellectual property. So this really is a capability and know-how and culture story where we're able to take very premium rocks and convert them into superior returns. And that's been the formula we've been working really hard on.
Thanks, guys. We'll do one more before we go back to the queue. This one, thanks for Greg as well. Greg, where would activity need to be to reach the high end of the 0%-5% growth rate?
Thanks, Jason. Currently in the play, we're running three rigs and one and a half or so frac crews, which is allowing us to keep at a maintenance production level. The team's executing really well with that. If we were to choose to grow, you're only talking about another rig or two and another half of a frac crew. We're not talking about significant activity increases to get to that 5% growth. As we think about where would we prefer to grow liquids versus gas, it really comes back to the conversation Brendan was having earlier around it's the whole question around growth at all and whether that is going to be something that's going to drive us to improve our efficiency, improve our returns, or is our money better spent putting it into buybacks or other places.
So we'll continue to think about it in that way.
Operator, we'll turn it back to you for more questions.
Thank you, sir. Your next question will come from Jeanine Wai of Barclays. Please go ahead.
Hi, good morning, everyone. Thanks for taking our questions, and thanks for all the time today.
For sure.
Our first question, maybe just hitting back on the firm transport. We know you recently signed up for that 10-year agreement for 245 million a day to Chicago. What does your Montney FT portfolio look like beyond 2024 in particular? We're just trying to do some risk analysis here on if some of the Canadian LNG projects are delayed. And I think in your prepared remarks, you mentioned that some of your other FT extends beyond 2025. So any additional color on which ones those are and for how long would be really helpful.
Yeah, Jeanine, no, appreciate it. So today we sell physical gas into the West Coast, into Chicago, and into Dawn in Ontario. And you're quite right. The biggest incremental increase most recently was an additional almost quarter of a B into Chicago on Alliance. And that one's at a greater than 10-year term. And so the good news, which to get to the point you're trying to get us on, is that physical firm service is all very long-dated deals. So they do persist with renewal rights well beyond the 2025 projected first tranche of LNG Canada. So we've got the ability to, with renewal rights, flex that over the long term or ramp it down if cap allocation changes markedly. So it is a really great historical footprint to have those transportation deals in our portfolio.
It gives us a huge edge in terms of being able to then layer on the basis position on top of that and get to this over 90% ex-AECO position. But to your point, yeah, they're all long-dated deals on each of those pipes. And in some cases, like I said, with renewal rights, it would let us flex them down if we needed to.
Okay, great. Thank you for that. And then maybe just circling back on the prior LNG question, just wondering if you're able to say anything about how advanced any conversations are between Ovintiv and some of the LNG project partners. And is there anything you can say about any of the contract structures? So for example, does Ovintiv have any non-negotiables? You already said that you're not taking any equity stakes in these projects, but are you willing to do an AECO Plus or a Henry Hub Plus type structure, or are you really looking for something else there? Thank you.
Yeah, Jeanine, no, appreciate it. Team's working through it. Like I said, nothing imminent. And so this is something we're just exploring in reasonable detail on both the Gulf Coast and the West Coast. As far as non-negotiables, I think you mentioned the AECO link. Clearly, our strategy is to get ex-AECO. So obviously, if it was AECO Plus enough a margin, we'd consider it. But really, what we're trying to do here is continue the strategy of price diversification outside of an export basin. And that's what you see us do in Waha, and that's what you see us do here. It just makes sense to us when you've got a basin where there's a product that's in greater supply than the in-basin demand. There's always going to be this pricing risk, and that's what we're addressing.
The only other thing I'd say on a kind of LNG commercial arrangement principles front is what we don't want to do is take a massive take-or-pay commitment, which is effectively like debt with one of these deals. So that's really the work that we're doing today to figure out, okay, how do we with access to this great supply, how do we put a deal together that makes sense for us, gives us that price diversification, but doesn't create a balance sheet risk go forward like an equity interest or like a massive take-or-pay commitment would.
Great. Thank you.
Thank you.
Your next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt. Please go ahead.
Good morning, everyone, and thanks for taking my question. This call's been really helpful, and I've run through a lot already. So just one for me on the hedging strategy and I guess the fluidity around it all. Obviously, since Q2 earnings, you've added a lot more on the AECO basis hedge protection front for the 2023, 2025 timeframe, as y'all talked about. And more broadly speaking, you've talked about structures that would allow y'all to benefit from the upside in the commodity. But overall, just being relatively less hedged versus, I think, historical norms for you all. So just wanted to get your overall thoughts on the appetite to revisit increasing hedge protection next year to lock in cash flows ahead of what looks to be shaping up as a year of pretty strong gas volume growth coming out of the U.S.
Yeah, Jeff, no, appreciate the question. It's obviously something we watch closely all the time. Maybe just one detailed point before I get to your broader hedging question. The increase in AECO hedges since our last disclosure, you've got that nailed. That's what took us to the over 90%. Previously, we had talked about being sort of 80%-85%. So that's all on the basis of that additional basis hedges. And then your question on, hey, shaping up to be a lot of gas growth coming out, that's nothing we hadn't anticipated. Our fundamentals team, if anything, was a bit surprised that it's taken this long for North American natural gas to show up on supply. And really, our hedging strategy is a pure risk management strategy.
So what we're doing with our hedges is protecting the business against a prolonged period of low prices and ensuring that even in that prolonged period of very low prices, we can be free cash flow neutral or better after the base dividend. That's the sort of principle of our hedging approach. And what we're avoiding is sort of a speculative hedging program that tries to anticipate on WTI or NYMEX a different outcome than where the market is. And we think that's the right approach, especially as our balance sheet has improved dramatically, and we've created resilience within the business with that balance sheet. And maybe one last consideration on that front. Part of what we're protecting against with that approach is a dynamic where you get very hedged and you have an inflationary environment.
That's kind of like the spot we find ourselves in today, where we're capped on our revenues, but we're realizing these increasing costs because of the sort of economy-wide inflation, a lot of which is being driven by the high commodity prices. I think we're just going to be quite cautious about putting the business in that spot where you're getting pinched between those two hard spots, so.
Makes sense. Thank you.
Yeah.
A few more questions from the webcast. There's a number of questions that are on the theme of growth. I think we've addressed those ones through Mel's questions. And the LNG questions, I think, have all been addressed with Jeanine's questions as well. But there are a few more here, a couple more here to cover anyways. This one, I'll ask either Tony or Aaron to talk to you. On your natural gas-powered frac spread in the Montney, are you consuming infield gas or purchasing third-party? And who's responsible for laying lines to source the gas?
Thanks for the question, Jason. The advantage that we have with this arrangement is the ability to utilize our existing fuel gas infrastructure and our own gas to supply the frac fleet. So the service provider does not have to lay any lines or source gas. We do have the flexibility or the ability to purchase gas from third-party should we require. But the advantage we have is utilizing our own infrastructure to make this more effective for us. And the big win there is the 80% cost reduction on the fuel side. So that's the net of that diesel elimination and then the cost, like Tony said, of our own fuel gas. So it's a good winner economically as well as on emissions.
Thanks, guys. One more question. This one's, I think, directed to Corey. What is the next debt target that could officially unlock more free cash flow going to return of capital?
Yeah, thanks, Jay. So I guess for us, we have set the current debt target at $3 billion, and we're still planning to get there. I think the significance of that $3 billion target's maybe a little bit lower than it used to be since we've already flipped from 25% to 50%. This question is often phrased around, "When does the payout ratio go up?" I think if you look at it from a balance sheet strength perspective, we'd like to keep the debt number coming down. We don't have a specific number beyond that, but as we get below $3 billion, and even Doug's comments about the free cash flow next year potentially being north of $4 billion, there's capacity to further strengthen that below our $3 billion target. So we don't have an official new debt target beyond that.
In the way we've talked about this with investors is we've really got two major objectives with the business today. We want to close the relative valuation gap that we see with peers, and then we also want to reduce debt further. And so that's why today you see us in that 50/50 mode. But clearly, we're conscious one of the most effective ways to be closing that valuation gap is through the share buybacks. And so we love the profile that we have coming with the hedges rolling off, where that cash return is going to mechanically increase even if we stay at the 50/50. But clearly, we have the option if we choose to go higher than that on the allocation, so.
Okay. And one more write-in question. What is the current status of the negotiations with the province of BC and the Blueberry River First Nation?
Yeah. So I'll maybe kick it to Greg, but I think the short answer here is we're in good shape for 2023. It's one of the things we have been talking to investors about over the last few months is we wanted to kind of get into the fall with permits in hand for a full year 2023 program. So Greg, over to you on that.
Yeah, thanks, Brendan. I think probably the two big takeaways on this are one, the conversations are still happening between the Treaty 8 nations and the province, and they're going quite well, but we don't have a deal in hand. But despite that, we are continuing to get permits. As Tony mentioned in his prepared remarks, we've got essentially all of our permits we need for this year and most of the permits we need for next year. So we're in a good place as long as conversations continue to progress. But the second point is really if for some reason those conversations were to stall, we could do exactly what we did this year, and that's shift activity to one of our other plays, either in Canada or elsewhere.
That's the real benefit of our multi-basin portfolio is that if we do run into headwinds in one part of the business, we can always shift activities to other very economic plays in other parts of our portfolio, so we feel pretty good about how things are going there.
One thing we didn't cover in a lot of detail. It's in the slide material, but just to make sure folks caught it, the reason we're receiving permits at a good pace here is all of our Montney acreage is in the part of the play where the surface rights are all privately held, and the surface has been developed as farmland for over 100 years. So from an incremental disturbance perspective, there's essentially zero incremental disturbance associated with our activity. And so that's why we're seeing those permits and why we feel we've got an advantage on this piece because we don't have acreage that's in sort of the undisturbed crown surface rights portion of the play.
Ladies and gentlemen, at this time, we have completed the question and answer session. I would now like to turn the call back to Mr. Verhaest for closing remarks.
Thank you, operator. I'd like to thank everyone for taking the time today to join us for our Montney discussion. If you do have any further questions, please feel free to reach out to the IR team. Our call today is now complete.
Ladies and gentlemen, this does conclude your conference call for today. We would like to thank everybody for their participation and ask you to please disconnect your lines.