Good day, ladies and gentlemen, and thank you for standing by. Welcome to Ovintiv's First Quarter 2026 Results 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 *1. For members of the media attending in a listen-only mode today, you may quote statements made by any of 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 call over to Jason Verhaest from Investor Relations. Please go ahead, Mr. Verhaest.

Thanks, Joanna, and welcome, everyone, to our first quarter 2026 conference call. 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 beginning of our slides and in our disclosure documents filed on EDGAR and SEDAR+. Following prepared remarks, we will be available to take your questions. I will now turn the call over to our President and CEO, Brendan McCracken.

Thanks, Jason. Good morning, everybody, and thank you for joining us. We believe the strategic steps for an E&P company to generate differentiated value creation are to build a portfolio with best-in-class assets and inventory depth, create a competitive advantage with stacked innovation and execution, demonstrate a proven track record of capital allocation to deliver superior and durable returns, and combine all of that with a clean balance sheet. We are very excited to have put Ovintiv into the valuable position of delivering on all fronts. Since 2023, we have increased our Permian and Montney drilling inventory by more than 3.2 thousand locations. This inventory-like expansion has been unmatched by our peers and leaves us with one of the most valuable inventory positions in the industry. We did it without diluting our shareholders, while increasing ROCE and substantially reducing debt. All along, our team has continued to build on their track record of operational and commercial excellence. The evidence of which is observable in public data. We make the highest productivity oil wells in the Midland Basin and in the Montney. We do that as the undisputed cost leader in the Montney and among the top two lowest-cost operators in the Midland Basin. We have also boosted profitability by strategically marketing our volumes to deliver high realized prices, lowered our cash costs, and reduced our interest expense and overhead. I am extremely proud of our team. They have shown tremendous resolve to build our business into a leading E&P. We are pleased to see the value of what we have built start to become recognized in the market, and we are excited because there is still a lot of room to run. We have had a productive start to the year, with the successful integration of the recently acquired NuVista assets, the sale of our Anadarko assets, and the significant deleveraging of our balance sheet. We accomplished all this while maintaining our focus on execution excellence and delivering another strong quarter of operational and financial results. We believe stability has real value for our shareholders. We have fundamentally de-risked our business and positioned ourselves to deliver durable returns for many years to come. Since the inception of our shareholder return framework in 2021, we have returned $3.7 billion to our shareholders through $2.4 billion of share buybacks and $1.3 billion of base dividends. In early March, we introduced the next logical progression of our framework, designed to deliver substantial value to our shareholders while allowing greater flexibility. We committed to returning 50% to 100% of our free cash flow via dividends and share buybacks. In 2026, we began the year planning to allocate at least 75% of our free cash flow to shareholder returns. The market has shifted dramatically since then with substantially higher oil prices than we expected. Even with our shares up strongly year to date, we continue to see a substantial gap between our share price and the intrinsic value of our business at mid-cycle prices. That said, with the higher prices and higher free cash flow, we believe it makes sense to avoid over-indexing on procyclical buybacks. We also believe it makes sense to take the opportunity to further accelerate net debt reduction. So if oil prices continue to stay elevated, we would expect to be in the 50% to 75% range. But even then, we will still allocate more absolute dollars to share buybacks than we had anticipated in March. If oil prices retreat, we will have capacity to be opportunistic with incremental buybacks, and we would expect to be back into the 75% or above range in that scenario. Again, regardless of price movements from here, our returns to shareholders this year are now anticipated to exceed our original plan on an absolute dollar basis. I will now turn the call over to Corey to discuss our financial results.

In addition to our best-in-class asset portfolio, our balance sheet is now stronger than it has been in a decade. With the proceeds from the Anadarko sale, we were able to significantly reduce debt, and as of April 30, our net debt was less than $3.3 billion or less than 0.8x leverage. Our remaining long-term debt profile has no maturities before 2030. We expect to realize over $80 million of annualized interest savings from the debt we have repaid since the start of the year. This includes the repayment of the 2026 and 2028 notes as well as the balance on our credit facility. We also have significant liquidity of $4 billion which enhances our resiliency and allows us to be flexible and opportunistic through the commodity cycle. We remain committed to our investment-grade credit rating, and our recent transactions were viewed positively by the rating agencies. Our capital structure has been rightsized. Our leverage compares favorably to our peers, and going forward, we are operating from a position of strength. Our first-quarter results demonstrate our continued focus on execution excellence and strong financial performance. Our cash flow per share at $4.62 beat consensus estimates by about 6% and our free cash flow totaled $634 million. We delivered volumes at the high end of our guidance ranges for each product, including oil and condensate production of approximately 225 thousand barrels per day. Our capital investment of $605 million came in at the low end of our guidance range as did our total per unit costs. We recorded a $1.2 billion after-tax non-cash ceiling test impairment that resulted in a loss in the quarter. The impairment was driven by weaker oil prices in the first quarter bringing down the SEC 12-month trailing price. At current strip pricing, we do not expect to incur further impairments. Maximizing capital efficiency and free cash flow generation is a top priority this year. As Brendan noted, recent global events have increased near-term pricing; however, the impact on the fundamental supply and demand dynamics remains unclear. Our portfolio now has significant duration and capability to grow production; however, we believe it is still prudent to maintain our stay-flat program with level-loaded activity in both the Permian and Montney, so that higher oil prices accrete to free cash flow. We are not currently seeing significant inflationary pressure on our 2026 capital program, outside of higher diesel costs. For the rest of the year, we expect to largely offset any additional cost inflation with operational efficiencies. As such, our capital guidance remains unchanged. Despite the higher royalty rates resulting from higher oil and condensate prices in our Canadian operations, which Gregory will touch on more, we are maintaining our full-year production guidance, including 205 thousand to 212 thousand barrels per day of oil and condensate. Strong performance in both the Permian and Montney is expected to offset volumes lost to higher royalties. In the second quarter, we expect production to average 623 thousand BOEs per day, including about 203 thousand barrels per day of oil and condensate. Our capital spend is expected to come in at around $575 million. Activity cadence in both assets is expected to be fairly ratable for the rest of the year. I will now turn the call over to Gregory, who will speak to our operational highlights.

I am really proud of the efforts made by our operating teams this quarter. Through the integration of the NuVista assets and the sale process for the Anadarko, they never lost focus on safety and efficient execution. Our team is committed to continually improving our capital efficiency and our outstanding operational performance through the first quarter gives us confidence in what we can achieve through the rest of the year. In the Montney, our first-quarter well productivity was very strong and is tracking above our 2026 type curve. We hit our 85 thousand-barrel-per-day target in the first month after closing the acquisition, and we have been very pleased with the results across our acreage. With the new NuVista assets now fully integrated into our Montney operations, we are focused on running a level-load program and offsetting the impact of higher royalty rates. The sliding-scale royalty structure is a unique aspect of shale development in Canada. As the name suggests, the percentage royalty that we pay slides up and down based on prevailing commodity prices. So while gross volumes are unchanged, higher royalty rates mean our reported net volumes are reduced. On slide 10, we provided a simplified illustration of the production and revenue impacts across a range of oil prices. The key takeaway is that although higher royalties result in lower net volumes, we are benefiting from higher prices where it counts — in revenue. If condensate prices were to average $90 per barrel for the year, we would see a 5 thousand-barrel-per-day increase and a 40% increase in revenues. Although we do not like losing the volumes, this is a trade-off we are willing to make. It is also worth noting condensate prices would have to reach approximately $135 per barrel before royalties would be in line with the rates paid south of the border, which are around 20% to 25% regardless of commodity prices. Due to royalty impacts and planned plant turnarounds, Montney production in the second quarter is expected to be at the low end of our full-year guidance range. While these turnarounds and royalty changes put pressure on our reported volumes, we continue to be very pleased with our well performance from both our legacy and the new NuVista asset. Our 15-to-16 well increased-density test continues to meet or exceed our expectations, and we plan to test additional upside locations later this year. Without the larger royalty take due to higher commodity prices, our total company oil and condensate volumes would be trending toward the high end of the guidance range for the year. Although the economics of our Montney wells are driven by condensate, it is important to note that our natural gas price diversification strategy continues to yield attractive results. In the first quarter, our Montney gas price realization was 175% of AECO. We continue to look for opportunities to secure both physical sales out of the basin and financial arrangements to price our gas away from AECO. We are exposed to AECO pricing on less than 20% of our 2026 Canadian gas volumes. We also have a JKM-linked contract for 100 million cubic feet per day that began during the quarter. That contract is essentially in the money when AECO trades at less than 20% of JKM. The cash flow contribution from the arrangement was minimal in the first quarter, but at current strip pricing for the remainder of the year, it would be worth roughly $60 million. Overall, our Montney asset is performing very well. We are maintaining a repeatable program type curve, and despite some royalty noise, the program is delivering fantastic results. Our team hit the ground running on day one of taking ownership of the NuVista assets, and they have not looked back. We spotted our first pad on the NuVista acreage, the Wapiti 6-OF-2, just two days after closing the deal, and are already achieving our cost target of $1 million in per-well savings. This brings the wells on the NuVista acreage in line with our existing Montney cost structure and sets us up to achieve the $100 million in annualized cost synergies that we promised with the transaction. We are delivering faster cycle times, extending lateral length on wells that were otherwise constrained by lease lines, realizing savings on completions through the use of cheaper domestic sand, and reducing wellsite facility cost by half compared to NuVista's design. We have also fully integrated the acquired producing wells with our operations control center. This allows us to remotely operate the wells and apply the same digital workflows used across our Montney operations. The result is minimized downtime and lower production cost. We also see the potential for significant future savings from the ability to optimize our development plans given more available processing capacity and the opportunity to further optimize our base production with more integrated infrastructure. I am very proud of the team and the efforts they have made to integrate the new assets into our portfolio. Our Permian team continued their track record of outperformance in the first quarter, with average oil and condensate volumes of 126 thousand barrels per day. Our most recent wells are exceeding the 2026 type curve. These results continue to support durable return generation across our 12 to 15 years of premium inventory in the play. We take great pride in our development approach and our ability to stack multiple innovations to create industry-leading results that defy the broader U.S. shale trend of well performance degradation. As a result, we are consistently one of the highest-productivity, lowest-cost operators in the Permian. Last quarter, we discussed the productivity uplift we have observed stacking innovations like surfactants in our completion designs. We have pumped them in over 300 Permian wells since 2019 so our dataset is robust. Compared to a similar group of non-surfactant-treated wells, we see a 9% improvement in oil productivity. We believe surfactants account for roughly half of the type-curve improvement we have observed in our Permian assets since 2022. At a cost of only about $100 thousand per well, these custom chemical additives are highly economic. But surfactants are only part of the story. Several other factors have contributed to our improvement in well productivity, including our cube development and reoccupation approaches, stage architecture, as well as the use of AI in our operations trained on our proprietary dataset. The result has been greater than 10% improvement in our Permian oil productivity per foot since 2023, while the broader basin is fighting a 2% annual decline. Using public data, you can see that in 2025 our Midland Basin peers were delivering average well productivity in line with our 2023 results, while our 2025 wells continue to perform significantly better. A recent report highlighted our repeated annual improvements in type-curve performance and ranked Ovintiv's oil productivity per well as the highest in the basin. We continue to see our culture of innovation as a real competitive advantage; it is not something you can buy, it must be cultivated over time, and we are seeing it deliver tangible results. I will now turn the call back to Brendan.

Thanks, Gregory. I would like to take a moment to recognize our team for the safe and strong first quarter results they achieved and acknowledge their focus and drive to make our business more profitable for our shareholders. We delivered another strong quarter, meeting or beating our targets and delivering cash flow per share and free cash flow per share above consensus estimates. Our integration of the NuVista assets is complete, and we are generating free cash flow well in excess of our expectations at the start of the year. Our track record of skating to where the puck is going is proving to be very valuable for our shareholders. Over the last few years, we have worked hard to high-grade and focus our portfolio, build extensive inventory depth, drive capital efficiency, and reduce our leverage. Along the way, we demonstrated that we are disciplined stewards of our shareholders' capital. Now we are entering a period of stability where we can focus on maximizing the profitability and efficiency of our business. We are excited to unlock the full value of what we have built. This concludes our prepared remarks. Joanna, we are now ready to open the line for questions.

Thank you. Ladies and gentlemen, as a reminder, you can join the queue to ask a question by pressing *1. We will now begin the question-and-answer session and go to the first caller. The first question comes from Greg Pardy with RBC Capital Markets. Please go ahead.

Yes, thanks. Good morning. Maybe just a question for Corey to start: with the action on reducing that debt here on the balance sheet, are you moving the goalpost in terms of your optimal financial leverage, or is this just being thoughtful around windfall cash flows versus purchasing stock right now?

Yes, Greg, thanks for the question. We are trying not to set a new long-term debt target. Obviously, we have been carrying that $4 billion target for some time now. This is really more a choice of allocating capital and just letting cash build on the balance sheet. Over time, we will look at opportunities to take out further debt, but we do not have much cash at this point — at the April month-end number it was about $400 million of cash on hand right now.

Thanks for that. Brendan, for the last few years you emphasized the market's not looking for additional barrels beyond the oil price escalation which may hang around longer than we think. Your increased focus in the Montney changes things because Canada is short condensate. As you look forward, is there now a more compelling case to grow condensate in Canada? Or is what you are looking at just more temporary from an oil price and strategic perspective?

Greg, I think it is indisputable that there is a more constructive condensate supply and demand dynamic that has unfolded. A few things have happened at once. On the condensate side, we are seeing strong growth coming out of the oil sands and prospects for more egress projects being contemplated in Western Canada. That is fantastic for Canada and for our business, and it is putting pressure on condensate supply and driving that premium higher. We have moved from a market where condensate traded a few dollars back to a market that looks more like parity to WTI. As dynamics unfold and more oil sands growth comes, we expect more constructive condensate fundamentals. On the macro side, we are watching a number of signals closely to assess the duration of the constructive oil market. We are watching when the Strait reopens in a real way, the impact of barrels currently behind pipe or in storage once that happens, the level of demand destruction with higher oil prices, the North American supply response, OPEC dynamics, and demand trends in major consumer markets, principally China. There are many factors to monitor. Overall, this is more constructive than we expected coming into the year, and what we are looking for now is duration in that signal.

Thanks, Greg.

Thank you. The next question comes from Douglas Leggate with Wolfe Research. Please go ahead.

Good morning, everyone. Thanks for having me on. Gregory, a question on the productivity comments you made — all very impressive. We all see the data. What we are trying to figure out is whether this is higher recovery or bringing forward production to the extent you have enough data to make that call at this point? And my follow-up, Brendan: when you talk about share buybacks justified on value, you said you are still seeing a substantial gap up mid-cycle. What do you see as your mid-cycle free cash flow that stands behind that statement?

Thanks, Douglas. On productivity, generally we are very pleased with the strong well performance in both the Permian and the Montney. Regarding the surfactant uplift in the Permian, there are several factors that cause us to believe this is higher recovery, not just acceleration. First, we have observed this phenomenon over the last five to six years, so the uplift has persisted over a longer period. Second, as part of our surfactant diagnostic program, we have done extensive geochemistry and fingerprinted the oil. In wells where we pump surfactants, the oil that comes back has a different composition. That tells us the wells treated with surfactant are not only performing better, but the oil is different, which points to additional oil rather than just timing differences. All of this together gives us confidence that this is real increased recovery and that the effect has been sustained.

Douglas, on intrinsic value and mid-cycle pricing: when we look at the intrinsic value of the company on a per-share basis, we run that at what has been our conservative mid-cycle price of $55 WTI. That discipline has been in place for quite a number of years. Even though today the supply and demand fundamentals would imply a price probably more in the mid-sixties, using $55 WTI is a good discipline. That implies about a $4 billion cash flow number for the business, and that is how we look at intrinsic value and our trading relative to that benchmark.

Thank you. The next question comes from Arun Jayaram with JPMorgan. Please go ahead.

Hi, Brendan. You and the team have spent a lot of time making portfolio moves to clean up and improve the portfolio with a core focus on the Montney and Permian. How should we think about portfolio management moves from here given where the balance sheet will be and that you are long inventory at this point?

Arun, great question. We think about the business entering a period of stability where we can sustain the inventory depth we have created. Larger M&A moves are not our focus today. We are pleased to have reached this milestone with the portfolio and our focus now will be on driving incremental profitability. Stability has real value for investors and allows us to operate from a position of strength with duration. We have also shown with our organic ground game that we can replace inventory on a cost-effective basis. With the first quarter behind us, we have already replaced our 2026 full-year inventory consumption with density conversions of about 130 locations in the Montney that we announced last quarter, and the Barnett position in the Permian effectively replaces a year of Permian consumption at least. We are already playing with a full deck for 2026.

Maybe a housekeeping question for Corey. On slide 16 you highlight guidance items including updated views on current taxes in a higher commodity price environment. You still show being a minimal U.S. cash taxpayer in 2026. If we assume strip pricing today, how could U.S. cash taxes trend in calendar 2027?

Arun, great question. If you took 2026 and replicated it in 2027, we would expect a similar minimal level of cash tax in the U.S. Going into 2028, we expect to become more of a full cash taxpayer on the U.S. side.

Thanks, Arun.

Thank you. Next question comes from Lloyd Borne with Jefferies. Please go ahead.

Hi, good morning. Brendan, can you start with the concept of stacked innovation and why Ovintiv feels differentiated in that? Also, what does it mean for capital efficiency going forward? I know you talked about surfactants, AI, and other items.

Stacked innovation is one of the critical strategic steps for an E&P to deliver differentiated value creation, and it is increasingly important as North American shale matures. Companies that can demonstrate the capability to innovate and learn will show outsized returns, implying a lower cost of capital and higher valuation. The method takes years to build: it requires data, causal understanding of inputs to outputs, and a culture of continuous learning. We have built a unique private dataset and a culture that learns from both our own work and the broader industry. Our tagline is the only infinite rate of return is learning from somebody else's capital. We have been aggressive about importing learnings and building predictive models and workflows that let us lead in capital efficiency. Indicators of this include well performance results, cost results, our innovation pipeline, and the predictive models we deploy. We make the highest oil productivity wells in the Midland Basin and the Montney while being among the lowest-cost operators. This is the result of years of institutional learning and disciplined execution.

Is there one technology or change you are most excited about from here?

In the rearview mirror, surfactants yielded a lot and have received a lot of attention. If you look at our well-performance data in the Permian, we are up roughly 20% on a per-foot basis for oil productivity, and about half of that is coming from surfactants. Going forward, our innovation pipeline remains full. One big frontier is pairing AI with our private dataset: developing in-house algorithms to deploy in production operations centers for uptime and artificial lift optimization, and to tune frac designs with dozens of inputs in real time. We are excited to continue deploying and testing innovations from the pipeline.

It is a combination of improving well results and improving costs. On the cost side, we continue to pump more than one well at a time, pump more hours per day, and pump more sand than our peers but at lower cost because it is local wet sand in many cases. Replicating our performance would be challenging without having walked the path we have over the last five to ten years. Lots of contributing factors have added up, and there are still things in the hopper. We are not done yet.

Thank you. The next question comes from Neil Mehta with Goldman Sachs. Please go ahead.

Brendan and team, last time we did a call there was a large deal in the Montney at a significant premium. Without commenting on specifics, what does that mean for the way you think about the value of your Canada business?

Neil, that transaction highlights the growing global capital allocation to the Montney and the recognition we have been pointing to regarding the value of the Montney oil window. We were not involved in that transaction; we had already advanced our strategy in the Montney with the two larger transactions we completed to build a premier position. We welcome the flow of capital and the recognition. It underscores the valuation gap we see between intrinsic value and where our equity trades today. Combining that read-through with how the Permian trades would produce a much higher value than the current market price for Ovintiv.

A follow-up on NuVista integration: slide 11 is helpful. Can you explain the optimization of the pad and how changes in design translate into results?

Great question. Starting with the map at the top right, by combining the two acreage positions, we were able to extend laterals from the NuVista lands into our position and vice versa. Longer laterals yield better cost per foot. We tied the wells into our drive center, our real-time drilling optimization center, and were able to drill those wells a couple of days faster than NuVista was planning at similar lengths. We were then able to incorporate techniques we've used for a long time: local domestic sand in completions and simultaneous fracturing to pump wells faster. All of these actions add to savings. Finally, we implemented a simpler facilities design than NuVista's, saving about half of the facilities cost. On this first pad, we are delivering at or below the well cost we planned for. It is strong execution by the team to hit the ground running just days after the acquisition closed.

Thanks, Neil.

Thank you. The next question comes from Gabe Daoud with Truist. Please go ahead.

Thanks. Good morning. Can we go back to the Permian, Brendan and Gregory? Specifically, how much of the program this year is using the surfactants you highlighted? Also, given the outperformance with your curve this year, would it be premature to think that the 2026 oil and condensate guide could be tightened or biased higher, noting some headwinds with the Montney royalty sliding scale?

I will start with the guidance question. The early wells of the 2026 program are really strong in both the Montney and the Permian, and we are not changing how we are planning the business at this point. The 2026 type curve still holds, but it's encouraging to see positive signals. The team has done a great job in the first quarter, and we will watch results through the year. We haven't changed the long-term type curve plan for the Permian.

On surfactant application, we have advanced our approach over the last several years. Initially we were only pumping a small number of wells and were working to bring costs down. We have honed the right formulas for the right zones and gotten our cost down to roughly $100 thousand a well. To walk through recent years: in 2024 about half of our wells received surfactant treatment; in 2025 about 75% did; and this year almost all of our wells will be treated with surfactant. We are still working on a few zones — the Barnett, for example, is not exactly where we'd pump yet when we test later this year — but effectively almost all the program will receive surfactants this year at a very low incremental cost and we are seeing solid uplift.

Got it. Thanks. One follow-up: your D&C per foot is attractive in both plays. Historically you highlighted pacesetter numbers in both plays. What might those pacesetter wells look like on a D&C per foot basis today, and when might the pacesetter become the play average?

We are always watching these metrics. We continue to drill and complete faster than before, trimming days on drilling and completions. There is a bit of inflation right now, mainly driven by diesel costs, which are largely pass-through. Today, we remain below $600 per foot in the Permian and $500 per foot in the Montney. If we continue to achieve faster cycle times and inflation eases a little over time, that will translate into lower well costs. Right now, we feel very comfortable with the guidance we have out there today.

Thanks, Gabe.

Thank you. The next question comes from Phillip Jungwirth with BMO Capital Markets. Please go ahead.

Good morning. How do you see production growth optionality in the Permian? It is an asset with low-to-mid-teens inventory life, a good runway though not quite at Montney levels. With the ability to grow the Montney 5%+, what scenario would lead you to also grow the Permian? Could a higher plateau than 120 thousand barrels per day of condensate make sense, noting you were at 125 thousand in the quarter?

Phillip, the option to grow exists in both assets. If we chose to grow, we would likely do so in both the Permian and the Montney because the return proposition is similar and we have inventory in both. For now, we are being patient and watching the macro unfold, but the option to grow is real in both places. In the meantime, we will continue to lean into performance to organically generate upside barrels and watch the macro dynamics.

One more: S&P is considering adding companies not domiciled in Canada to the S&P/TSX indices at a reduced 50% weighting. Have you looked at this or have thoughts about how it might expand your investor base in Canada?

Phillip, the combination of our fundamental improvements and potential index inclusion would be constructive. We have seen S&P reach out to investors for comment on that concept and we are supportive of it. More importantly, the fundamental appetite to own our shares is strong in both markets and we are seeing increasing investor interest.

Thank you. The next question comes from Kevin McCarthy with Pickering Energy Partners. Please go ahead.

Apologies for staying on growth and shareholder returns. In the past you saw value in buying back stock versus growing production. Any update to how you calculate when you choose between those two uses of cash? Are you using the strip or mid-cycle prices? How do you calculate that?

Kevin, we evaluate across a range of prices. The fundamental intention is cash flow per share growth and achieving the most efficient cash flow per share growth. Historically, the calculations kept telling us buybacks were more efficient. Today that relationship has moved more toward balance, even at more modest oil prices. That opens the door for a more balanced allocation between buybacks, dividends, and debt reduction.

Follow-up on OpEx: upstream T&P was much lower than the guide in Q1. You've kept Q2 to Q4 guide largely intact. Can you explain the moving pieces in that line, given the transactions that happened in the first half of the year?

Kevin, Q1 was a bit noisy on T&P. The quarter included Anadarko volumes, which have a lower T&P rate, and we did not have NuVista for the whole quarter, which will be at a higher Canadian T&P rate similar to our other Canadian assets. We also had some one-time adjustments in the quarter that were in our favor, which pushed T&P lower than our normal run rate. Going forward, our T&P is in line with expectations. Canadian assets typically have more cost in T&P, whereas U.S. assets have more cost in LOE. So you should expect LOE to come down and T&P to be up slightly relative to Q1, but this is in line with our expectations.

Thanks, Kevin.

Thank you. Next question comes from Neal Dingmann with William Blair. Please go ahead.

Good morning. Gregory, on the Permian plan this year, you target around 125 to 135 wells. Will most of this continue to target Wolfcamp and Spraberry? Are you targeting some deeper zones as well like the Barnett?

Thanks, Neal. It is a straightforward program. We have one Barnett well in the program. The rest of the zones will be the normal stack, going from Spraberry, Dean, Jomel down to the Wolfcamp. We find our Barnett acreage interesting but we do not have the same drivers as some peers because our Barnett acreage is held by production, so we will take a slower approach. We like the productivity of the zone, but the cost question remains. Over time, as we and others learn more, we expect to get faster and bring costs down. This is a great opportunity to learn from peers without spending large dollars.

Makes sense. Second: on marketing, are you seeing near-term power opportunities or anything you are considering there?

We constantly look for ways to lower OpEx. Engaging in power generation as a large new line of business feels beyond our scope today, though we are exploring ways to lower costs for powering activities such as our electric frac fleet. We are evaluating interesting ideas, but the scope is narrower than what you might be referring to.

Thank you. The last question comes from Christopher Baker with Evercore. Please go ahead.

Hey, guys. I thought I had put my hand down — all my questions have been answered. Appreciate the time today.

Thanks, Christopher. No problem.

At this time, we have completed the question-and-answer session, and we will turn the call back over to Mr. Verhaest.

Thanks, Joanna. Thank you, everyone, for joining us today. The call is now complete. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating, and we ask that you please disconnect your lines.