Good morning, ladies and gentlemen, and welcome to the Murphy Oil Corporation second quarter 2021 earnings conference call. If at any time during this call you need assistance, please press star zero for the operator. I would now like to turn the conference over to Kelly Whitley, Vice President, Investor Relations and Communications. Please go ahead. Thank you, operator. Good morning, everyone, and thank you for joining us on our second quarter earnings call today. Joining us is Roger Jenkins, President and Chief Executive Officer, along with David Looney, Executive Vice President, Chief Financial Officer, Eric Hambly, Executive Vice President, Operations, and Tom Mireles, Senior Vice President, Technical Services. Please refer to the informational slides we placed on the investor relations section of our website as you follow along with our webcast today. Throughout today's call, production numbers, reserves, and financial amounts are adjusted to exclude non-controlling interests in the Gulf of Mexico. Slide one. Please keep in mind that some of the comments made during this call will be considered forward-looking statements as defined in the Private Securities Litigation Reform Act of 1995. As such, no assurances can be given that these events will occur or that the projections will be attained. A variety of factors exist that may actually cause results to differ. For further discussion of risk factors, see Murphy's 2020 annual report on Form 10-K on file with the SEC. Murphy takes no duty to publicly update or revise any forward-looking statements. I would now like to turn the call over to Roger Jenkins. Thank you, Kelly. Good morning, everyone, and thank you for listening to our call today. On slide two, as we kick off our quarterly call and investor meetings, we would like to remind our investors of our story. We're pleased to do so briefly again this morning, as each tenet of this slide remains in effect this quarter and in the future. Our ongoing execution in our three producing areas continues to show outstanding results while progressing our offshore long-term projects and the expansion of the Tupper Montney. Our competitive advantage of executing in offshore again is illustrated by the outstanding progress on our Calliope, Beaumont, Samurai, and Kings Quay projects. We've also maintained a strong cash flow that easily covers our planned spending for 2021 and supports shareholders through our longstanding dividend. Further, we were able to increase our cash position this quarter by nearly $190 million, which allows us to accelerate our de-levering plans. Our ongoing meaningful level board and management ownership highlights our personal interest in the company's long-term success. Slide three. Our three priorities are simply to de-lever, execute, and explore, and I'm pleased with the progress we've made on all fronts in the second quarter and this year. After our initial de-levering event, we repaid our revolver in full in quarter one. We stated our goal of reducing long-term debt by $200 million by year-end 2021. We've recently announced the redemption of $150 million of 6.875% senior notes due in 2024. Now today, we're able to increase our de-levering goal to $300 million, assuming a $65 oil price for the remainder of 2021. The additional cash flow has been accomplished not only through stronger oil prices, but also ongoing operational excellence as we've achieved less operated downtime offshore while experiencing the benefits of our optimization efforts and upgrades completed over the previous 18 months, along with continuing to bring on our onshore wells online below budget and ahead of schedule. As a result of this work, production from every single asset was above the midpoint of guidance for this quarter, with all onshore operations exceeding the high end of the guidance range. Additionally, we produced 100,000 bbl of oil per day in the second quarter, topping our guide by 5%. Offshore, our Gulf of Mexico projects remain on budget and on schedule. We also remain focused on advancing our exploration program. We participated in the drilling in Brunei in the second quarter with the Jagus Sub-thrust 1X exploration well, along with the spudding of the non-operated Silverback well in the Gulf of Mexico. In the fourth quarter, we will participate in the drilling of the Cutthroat exploration well in Brazil. On our sustainability report on slide four, our report has been published on our website and includes expanded disclosures to share our sustainability efforts and further align us with multiple international standards, such as the UN Sustainable Development Goals and five reporting principles outlined in sustainability reporting guidance for our industry. We've now established a goal of zero routine flaring by 2030 and obtained third-party assurance of our 2020 Scope 1 and Scope 2 greenhouse gas emissions. Additionally, we've revised and strengthened our climate change position, instituted a human rights policy, advanced our diversity, equity, and inclusion efforts. Statistical highlights include receiving a 47% reduction in Scope 1 and Scope 2 greenhouse gas emissions since 2016, and a 10% decrease in greenhouse gas emissions from 2019-2020. Building upon our current top quartile low carbon emission intensity for oil-weighted peers, we are continuing the internal work to reduce our environmental footprint and advance the energy transition while protecting and supporting our people and the communities in which we work. On slide five, our second quarter production volumes of 171,000 bbl oil equivalent per day were 4% above our guidance midpoint for the quarter. Accrued CapEx for the quarter was $198 million. Revenue of nearly $700 million, which was the highest in a year, was achieved through strong realized pricing of $65.53 per bbl for oil. I'd now like to turn the call over to our CFO, David Looney, to give his financial update. Thank you. Thank you, Roger, and good morning, everyone. I'll start with slide six. In the second quarter, we reported a net loss of $63 million or $0.41 per diluted share. After adjusting for certain after-tax items, such as $103 million non-cash mark-to-market loss on crude oil derivatives and a $49 million non-cash mark-to-market loss on contingent consideration, we reported adjusted net income of $91 million or $0.59 per diluted share. Cash from operations for the quarter totaled $449 million, including the non-controlling interest. After accounting for net property additions of $203 million, we achieved a positive adjusted cash flow of $246 million. On the hedging front, Murphy continues to protect its future cash flow in the Tupper Montney with additional fixed price forward sales contracts for a portion of production through 2024. Slide seven. Our 2021 CapEx plan is heavily weighted towards the first half of the year, with $198 million total accrued CapEx in the second quarter. While slightly above our previous guide, this was due to timing adjustments of non-operated activity and has no impact on our annual CapEx. Overall, our ongoing disciplined spending has led us to tighten our CapEx guidance for the year, now ranging from $685 million-$715 million, with $700 million maintained as the midpoint. As we established on our last earnings call, CapEx will step down for the remainder of the year. With the shift in Eagle Ford Shale spending, our fourth quarter CapEx is forecast lower than previously. Approximately 63% has already been spent in the Eagle Ford Shale as of June 30th, and 66% has been spent in the Gulf of Mexico, while 76% of onshore Canada CapEx has been spent by that date. We continue to proactively manage our supply chain exposure, particularly with our long lead items. Since 60% of our 2021 capital plan is complete and key contracts are in place for the remaining plan, we have minimal near-term supply chain risk to our capital spending. Our third quarter production guidance range of 162,000 bbl to 170,000 bbl of oil equivalent per day includes 4,100 bbl of oil equivalent per day of assumed Gulf of Mexico storm downtime. Additionally, we are adjusting our full- year production guidance range to 157,500 bbl of oil equivalent per day to 165,500 bbl of oil equivalent per day, which includes fourth quarter impacts of 1,300 bbl of oil equivalent per day for assumed Gulf of Mexico storm downtime and 7,900 bbl of oil equivalent per day for net planned offshore downtime. With that, I'll turn it back over to Roger. Thank you, David. In slide nine, in the second quarter, we brought online three operated and 29 gross non-operated wells in the Eagle Ford Shale. 10 wells were brought online in the Tupper Montney. That wraps up our activity in onshore Canada for the year. Our U.S. onshore drilling program is nearly complete, with just four operated Eagle Ford wells planned to come online in the fourth quarter. Slide 10. Our Eagle Ford Shale wells produced 42,000 bbl equivalent per day in the second quarter, comprised of 75% oil and 88% liquids. For the remainder of the year, we plan to drill and complete four wells in the fourth quarter, I just mentioned, in our Catarina acreage, all within our planned annual CapEx of $170 million. The team continues to execute and generate efficiencies as evidenced by our 25% improvement in our rate of penetration and completion cost per lateral foot since 2019. Overall, we've achieved a 40% reduction in completion costs in four years through strict focus on non-productive time and making operational improvements. Our average per- well drilling and completion cost has improved to $4.7 million from $6.3 million in 2018. As a result, we are now achieving well payouts of approximately nine months on our 2021 program at oil prices averaging nearly $62 per barrel in the first half of this year. On slide 11, as to Austin Chalk, one of our four Eagle Ford wells that we plan to drill and bring online in the fourth quarter is targeted for the Austin Chalk formation. Overall, our recent Karnes Austin Chalk wells have nicely outperformed our average type curve. Other public operators near our Catarina acreage in the western portion of our Eagle Ford Shale acreage have reported strong Austin Chalk results from their recent wells. We're excited to drill this well and highlight potential de-risk another 100+ Austin Chalk locations in our portfolio in that area. On slide 12, in the Tupper Montney, we produced 248 million cu ft per day in the second quarter. 10 wells were brought online, which completes all well activity for the year. Costs continue to decrease here as well. We've seen a 24% reduction in drilling and completion costs since 2017, while achieving a total well cost of just $4.4 million in 2021 compared to $5.5 million in 2019. In particular, our completion costs per lateral foot have improved 25% since 2019, through lower non-productive time, optimized waterline operations, enhanced water handling, and natural gas-powered frac pumps. Further, our average pumping hours per day has increased more than 50% since 2017, from almost 12 hours to 18 hours per day. The ability to lower our cost per well by nearly $1 million will add significant value to our Tupper Montney project and represents the tremendous work of our drilling and completions team in that area. As to our Gulf of Mexico projects, doing extremely well. On slide 14, Murphy continues to progress as scheduled. With major Gulf of Mexico projects, the Samurai Number 3 well was drilled in the quarter. We're now drilling the Khaleesi-3 well. Our next well is Samurai-4, which is planned for later in the third quarter, before we begin completions work on all seven wells that make up the Khaleesi/Mormont Samurai development. The team's been able to maintain the schedule and capital plans for this project, and we still anticipate flowing first oil in the Kings Quay in the first half of next year. Completions work on the final producing well of our non-operated St. Malo waterflood project is set to wrap up within the week, and thereby completing rig activity on this project for the remainder of the year. We're pleased that a project this size has remained on schedule and highlight that completing the rig work for the remainder of 2021 provides further certainty on our capital spending. As to Kings Quay, the second quarter saw the completion of the construction of the Kings Quay floating production system. The FPS has now sailed away from Korea and is headed to the Texas coast, where final work will be accomplished at the shore base prior to its placement in the Gulf in early 2022. This team's done an incredible job on this project, not only remaining on schedule, but also keeping everyone safe and healthy through the pandemic. We're excited to see this come to fruition. This is yet another example of our industry-leading offshore execution ability. In Brunei, on slide 17, in the quarter, we participated in the drilling of a discovery well in Block CA-1 in Brunei with the Jagus Sub-thrust 1X well for a total cost of Murphy of just $2.8 million at approximately an 8% working interest. Post this well, where we classified our working interest in Block CA-1 of Brunei as not held for sale any longer. Partners are assessing development appraisal plans. We're evaluating seismic data and further prospectivity. As to exploration in the Gulf of Mexico in the second quarter, on page 18, drilling was commenced at the Chevron-operated Silverback prospect in the Gulf, which we anticipate finishing this month. Our participation provides access to 12 blocks with potential for an attractive play opening trend and is adjacent to the large position Murphy holds with our partners. On slide 19, in Brazil, excited about our non-operated exploration position in Sergipe-Alagoas Basin, and the additional optionality and resource potential it provides our company. Murphy, along with operator ExxonMobil and partners, plans to spud the Cutthroat-1 well in the fourth quarter of 2021 at an approximate net cost to Murphy of just $15 million. On slide 21, onto our capital program. I'm pleased with our excellent production results this quarter. Our oil production exceeded by 5% as we remain consistent in our ever-improving operations in operated offshore and in the Eagle Ford Shale. We remain on track with our full-year production at our midpoint of 161,500 bbl equivalent per day with 55% oil weighting. We remain very disciplined on our capital spending, with no intention to change our plans for the remainder of the year. As such, we affirm the $700 million midpoint of CapEx for 2021. We announced today that we are tightening the range around this midpoint. On slide 22, as we remain focused on our strategy of de-levering, executing, and exploring. We note that our long-term plan remains unchanged. Our continued execution and capital discipline laid in maintaining our capital spend of $600 million from 2021 through 2024, with a production CAGR of approximately 6% through that period. Of course, we're trending well in our current oil weighting and are above the plan for 2021 at 55%. Assuming an average long-term WTI price of $60 per barrel, Murphy Oil will be able to cut its debt in half to less than $1.4 billion by the end of 2024, while maintaining a quarterly dividend payment to shareholders. We note that this plan accelerates using an average price of $70 for oil in 2023, enabling us to reach the debt reduction by just mid-2023. Beyond de-levering, we remain focused on our exploration program and portfolio of over 1 billion barrels of oil equivalent in net risk resource potential. Long-term, once our major Gulf projects are complete, we'll have significant optionality when making capital allocation decisions, and we'll look to what's best for Murphy and our shareholders and stakeholders at that time. While we have many options, we'll seek to balance increased asset development with funding exploration success and potential A&D and execute additional debt repurchases and return more cash to shareholders. On slide 23. Throughout the remainder of 2021 and longer term, we are steadfast and focused on our priorities of de-levering, executing, and exploring. We've decided to accelerate our long-term debt reduction goal for 2021 to $300 million from $200 million, assuming an oil price of $65 the rest of the year, and look forward to achieving our goal of $1.4 billion in long-term debt reduction by 2024, with a long-term average price of $60 per barrel. We're able to accomplish this in part by disciplined spending, but also continued execution of our major Gulf of Mexico projects ahead of first oil next year, as well as keeping everyone safe and healthy while protecting the environment in which we're operating. Lastly, we're excited with the recent exploration success in Brunei. I look forward to drilling wells with operating partners in the Gulf and Brazil this year, while planning for next year's exploration campaign. Murphy could not have achieved this successful second quarter without the effort of all of our employees, who continue operating with excellence in every single department. I'd like to personally thank each and every one of them, maintaining their individual focus on our strategic priorities and the long-term vision for our company. With that, we'd be glad to take your questions this morning. Thank you. Ladies and gentlemen, we will now begin the question- and- answer session. Your first question comes from Arun Jayaram of JP Morgan. Please go ahead. Good morning, Roger. Some nice results. Thank you, Arun. I appreciate that. Yep. Well, I know Chevron operates, I was just wondering if you could just give us a progress report on Silverback, and just maybe also talk a little bit about the Brunei discovery, and if this could be a needle mover for Murphy? Thank you for that question, Arun, about our exploration program. The way this is really shaking out as to Silverback in your report this week, I'm glad you asked that question, so we can clarify any confusion around that. There was a mechanical issue very early days of drilling in the well, what we would call the top hole section of the well. Well had to be re-spudded, if you will, and drilled adjacent. That has no, at all, any implication as to the prospectivity of the well. Remain the same. Chevron, I'm partnered with both. Chevron has done a very good well in drilling here and also at St. Malo. Due to their operational teams and their ability, they were able to catch back up on the cost of that re-spud, and we anticipate our capital will be identical to our original plan. It was just an operational matter that was handled and moved on. It happened two or three months ago. I'm not sure where that filing came from at that late date. There's no impact to our company nor Chevron on that matter due to their performance. Great. Just on the exploration program in Brunei? Yes. We've had those blocks for a very long time; there's been a really nice well to drill. It's a sub-thrust type well underneath the major Kakap Gumusut field, if you will, on the Brunei side of the field. We're a little over 8% working interest owner there. There was a time when we were exiting Malaysia, we were going to sell Brunei, and had that held for sale. Through COVID and other matters, we reassessed. This is a very nice-looking well that was successfully drilled by our partner group. Done very well there. We've pulled that out of held for sale. They're, of course, the major Kikeh field that we discovered and operated for many years, very near there. Of course, the major Kakap Gumusut field, with many successful partners, operated by Shell. Through this region, we're going to hang on here and hopefully build a long-term East Coast Canada kind of business here. 2,000 bbl- 3,000 bbl a day long-term for us. It's very profitable, very high oil quality, and we're very happy about it. Great. My follow-up, Roger, is just talking about the Austin Chalk opportunity at Catarina. You had a nice map in your update. You're going to be testing one well. Set the stage. I know SM is near you. Give us some thoughts on the potential of the Austin Chalk. I'm going to have Eric comment on that, Arun. He's managing that. We're glad to get down there and try something new in that area. Go ahead, Eric. Okay, great. Thanks, Arun. Just a couple of points to emphasize there on the Austin Chalk. As you know, we've had some really nice results in our Karnes County position. We have had limited appraisal effort or development effort in the Austin Chalk in our Dimmit County. Lots of nearby operators have had quite a bit of success. We've done a bunch of work to assess and optimize the landing zone in the Austin Chalk, and we think it has some nice potential. We are sort of stepping our toe into that with one well in the Austin Chalk in a four-well pad. We think it has some nice potential to be sort of top-tier performing. We'd like to go out and prove that it really looks very attractive on our acreage. If it is successful, we think we have 100+ Austin Chalk locations that would be top-tier performance, which would really help us continue to execute and de-lever. Great. Roger, thanks for letting us into your conference. I'll hand it back. No problem, Arun. Appreciate your help, and we'll be talking to you soon. Your next question comes from Neal Dingmann with Truist Securities. Please go ahead. Morning, Neal. How are you doing? Good, how are you doing? Nice report, Roger. My first question is just on development activities, or I should say development opportunities. You've got that great slide 40 that really spells out the spend and production around Khaleesi, and Mormont, and Samurai, et cetera. I'm just wondering, any thoughts or your thoughts there on anything potentially coming a bit early, or are those going to be just really right as you've been expecting on those? I'm just wondering, Roger, any further comments you can make on any other potential development opportunities. Thanks, Neal, for that question. The way we're looking at this today is that we're doing extremely well. We're doing extremely well in the flow line installation, the mooring installation, the permitting, the obvious build and tow of this major facility, which is now around the Cape of Good Hope, headed up toward, almost going over our Sergipe-Alagoas Basin in Brazil on its way to the Gulf, which is ironic. We're very happy about it. All systems are go, possibly to be sooner, but we're staying with our mid-2022 and are very happy with how the permit's going. My team's doing a great job, very happy about that. We are bringing on another well called Calliope in the region this year as to offshore execution. That's our plan now, all within our budget, holding our budget, doing very well, and I appreciate you asking that question because it's leading to our execution, which is leading to the de-levering, which is our major thing for us. Hitting these major projects on budget is super critical in the de-levering plan. Yes, it does seem like running just like clockwork, which is great to see. Just one quick follow-up. Non-op activity was a little, again, I don't mind to see it, good non-op activity on some good wells. It was a little higher in 2Q. Could you just talk about your thoughts for the remainder of the year, how you see that going forward, and what opportunities you will continue to have for the non-op side? I'll let Eric handle that question. That was primarily an advancement of some wells by BPX in the Eagle Ford, and I'll let Eric go ahead with that. Yeah. That's right. In our Eagle Ford position, we had a number of non-operated wells that we thought would come online in the third quarter, which actually progressed faster and came online in the second quarter. That acceleration contributed about 2,100 bbl oil equivalent to the second quarter, which we're really happy to have. It's important to note that even if those wells had not moved faster, our Eagle Ford business still would've exceeded guidance and been toward the high end of guidance. Our operated business performed strongly, both our new wells this year and our base performance from wells that are brought online in prior years, on the back of strong operated well performance exceeding expectations and lower downtime. Really happy with our Eagle Ford position, operated, non-operated, happy to see production come online sooner as well. Great details. Thanks, guys. Thank you, Neal. Your next question comes from Neil Mehta of Goldman Sachs. Please go ahead. Good morning. Our second Neil in a row. Yeah. Double trouble here. Look, the first question is just on Brazil. Again, Exxon does seem to be pretty excited about the opportunity set down there with Cutthroat. Can you just give us the lay of the land? Sounds like we're going to get an update in Q4. How are you just thinking about the opportunity set in Brazil? Thank you Nei l, for that question. That really leads to one of our key tenets of our strategy of not only de-levering and executing, which are tied together, but of course, exploring. This is a series of acreage we built with Exxon and another, ANP, a partner down in Rio. This goes back several years and has built a very large position here. The key to this exploration opportunity is outboard of some very successful fields that have been for sale, if you will, which have information available on those fields. Of course, it is very adjacent to those in the same geologic setting. We're very excited about the opportunity, very excited to work with ExxonMobil here in Houston, as to seismic and the work and the selection of the wells. We have many opportunities to drill there over the next few years. Very excited. These are very large prospects. We've disclosed our view of those here in our slide 19, and very excited about it. They, being ExxonMobil, have another rig working elsewhere in the country on something we're not a part of. When they finish that work, they'll be mobilizing up here early in the fourth quarter, and we're very excited about it. That's right. The follow-up is just on the cadence of capital spending. First half, as you indicated, was a little bit higher. It sounds like the second half is a little bit lower. How do you feel about the cost inflation side in terms of your confidence to see that step down in CapEx in the back half of the year, if that makes sense, as we are seeing signs of inflation in different parts of the ecosystem? I'm going to have Tom in a second handle the procurement part of that. Let me frame the early part of it. We're very confident in our capital program because our work is ending. St. Malo, where we're a 20% player, will be stopping the drilling. The Silverback well is about to be completed. We've stopped all our drilling in the Montney for the year, just harvesting free cash flow. We are about to drill just four wells in Catarina, our most inexpensive place, with 1,000s of wells that we've drilled in the Eagle Ford. We're very confident about the CapEx because we are stopping our program, and our program is front-end loaded, and our non-op work is completing. That really sets the tone for most of the CapExs. We don't have anything to inflate in the U.S. this year. Tom Mireles runs technical services here, including procurement, and I'll have him provide you a bit more color. I appreciate your question. Yeah, Neil, as Roger said, we've got the majority of our capital behind us now. Even the remaining that's in front of us, it's pretty much fixed. We've got contracts in place just through our strategic sourcing with the supply chain that's given us good visibility. The operations from Eric's organization has continued to drive down the overall costs. Yeah, as Roger said, we're in pretty good shape with what we expect in 2021. Yeah. To follow on that, Neil, to me, I had it in my remarks, I think is real important. We're a big player in the Eagle Ford and a big player in the Montney for us; we lowered our wells $1 million a well. $1 million a well, with hundreds and hundreds of wells to go. Today we're trying to get off the cost per foot and talk about the pumping time during the day, and the time that we complete wells, and how much our rate of penetration. Because if the time is improved and you're $1 million a well less, it's going to be hard for service to take that away from us. Very hard. Thanks, Roger and team. Thank you. Your next question comes from Gail Nicholson with Stephens. Please go ahead. Good morning. Morning, Gail. Good morning, Roger. You guys posted really good LOE in both the Eagle Ford and the Gulf of Mexico this quarter. I was just curious, was the Eagle Ford LOE lower quarter-over-quarter driven by the higher volumes, or was there something else that you guys did that improved LOE in both those areas this quarter? I'm going to let Eric handle that for you and let him have the glory on it today, Gail. Thanks, Gail. I don't often get glory, so I'll take it when I can. We're really happy with our operating cost performance in the Eagle Ford, of course. In the second quarter, we did have high volumes, which helped. We had continued work from our team to lower cost. Our remote operations center and our operations team and engineering teams have been working diligently over the last year+ to enhance our operations to lower costs, lower downtime, which leads to better production, steady operations. We did have, in the second quarter, $3 million of a prior period adjustment that was related to gas that we purchased periodically at one of our facilities that we realized, through an allocation error, that we had been paying royalty on gas that we were purchasing, which we should not have. We made a correction for that. That's a $3 million impact to the quarter that will not repeat going forward. We expect in the last half of the year, Eagle Ford operating expenses will be a little bit higher due to declining production, not repeating of the prior period adjustment, as I mentioned. If you look at the whole company, we expect operating expenses to be in the $8-$9 range. It's still quite a strong performance for us across the globe. It was really great to see. Excellent work there. I was just also wondering if you guys could provide us any incremental details in regards to Terra Nova. Do you think that those volumes will be back online in 2022, or is that more of a 2023 situation? Thank you, Gail, for that question. The way we're sharing information about Terra Nova today is as follows. It's still being executed by all the partners. I can tell you that our board sanctioned it yesterday in the idea that everyone else will also sanction. We're going to move forward with it if everyone else does. When all that is complete with all of our partners, we will disclose more. It is a late 2022 flow back at Terra Nova, very late, so practically in early 2023. Would make no difference in that regard. The way the deal is structured, it makes no change to our guided capital of average capital that I just discussed in our remarks. It's a really good project. We're very happy to be in it, and I look forward to working with Suncor and Cenovus long-term on that project. Great. Thank you, and excellent quarter, guys. Thank you so much. Your next question comes from Leo Mariani with KeyBank. Please go ahead. Morning, Leo. Morning. I want to follow up a little bit on some of the exploration comments that you guys made here. You talked about success in Brunei. You mentioned 2,000 bbl-3,000 bbl a day of oil here. Would that be gross or net to Murphy? Just any kind of high-level timeframe on when that might come online. Is that going to take two years to get to production, or what do you see there? Thank you, Leo, for that question on our exploration program, which is key of our strategy here. What I meant is that's just a type of net production it could be for the long term. Of course, the operator, Shell, and of course the government of Brunei and our other partners have to go through, assess a delineation of the wells, a very successful well, and then we will go and determine all that down the road. I don't really have an idea of that timing. That's not immediate to us at this time. It's just a discovery well. It's a nice project. We pulled it out of hold for sale, and we're glad with our position there and glad we kept it. Okay. Just on Brazil, I think you guys have always characterized it as a very large prospect that you guys are drilling down there. I guess I just wanted to kind of get a sense of the probability of success. Is this kind of your typical 1: 4 type of offshore exploration well in terms of how you view the chances here? Thank you, Leo, for that question on our program there. It's a key part of our strategy this year. Yes, I would think a one in four typical big deepwater opportunity would be clear. This is offsetting major fields that are discovered. Operated by Petrobras in the region, offsetting, of course, shelf production, historic shelf production, in a successful area of Brazil. That adds a little bit of positivity to it, that where we, as our strategy, you know, is to drill near known oil areas instead of rank exploration with no success in board of deepwater. I think it meets all that criteria. It fits right into our strategy on F&D, size, scale, partner, and we're very happy about it. Okay. Thanks, guys. Thank you, Leo. Ladies and gentlemen, as a reminder, should you have a question, please press the star followed by the one. Your next question comes from Josh Silverstein with Wolfe. Please go ahead. Good morning, Josh. Hey, good morning, guys. I'll stick with the exploration front for the first question. Mexico used to be really big in focus for you guys. I know you had some activity there at Cholula a while ago. It's kind of nowhere to be seen now on the slides. I just wanted to get an update as to what's going on there and maybe just rank that relative to the opportunities that you have elsewhere in the portfolio. Thank you, Josh, for that question on our exploration program. Brazil is still a major in focus for us. There's a slide in the appendix, around I mean, Mexico. I apologize. It is going to be drilled next year. Everyone's working on their budget with their partners. It's very likely to be drilled next year and get back on schedule post the COVID world of 2020. There's a very nice opportunity in the sub-salt, especially the well called Tulum. It's on page 42 in our appendix. There's recent discoveries all around this area in the same-aged rocks and reservoirs. We see this week that Eni had yet another discovery in that region. Cholula is a play that's discovered and will be delineated, but we've advanced Tulum. It has a series of sub-salt opportunities that are larger. Very nice and on a trend of success in the region. It just so happens that our focus in the slides is trying to, as you know, Josh, because you follow the company closely, we're de-levering, executing, and exploring, really working on that this year, while we've increased our debt reduction target this morning. The Mexico drilling is into next year with our partner group, and in no way have we pulled back there our focus there, our likeness, if you will, of Mexico. It's actually very strong for us because we get to operate it, and we have running room of similar plays in that area. Just because it's not up in the deck on our de-lever execute explore area doesn't mean that we're not there liking that or have changed our view there in any way. Got it. Thanks for that. I know you have a multi-year kind of outlook for what you're trying to do at Tupper when you greenlit the project and then hedged a bunch of volumes there. It was a while ago. Prices have obviously risen pretty significantly since then. I'm curious, as you think to next year, is there any thought about stepping up some activity here given the significant increase in gas prices? Is the outlook kind of steady from the project that you've outlined already? Thanks for that question. The way we're thinking about Montney today is it's a long-term project. It's going to flow near $500 million a day for a long time, and we took a long-term view on the hedging. We have an activity plan to reach that level of production that we've disclosed in our capital plans, and it's just like drilling in the Eagle Ford or anywhere else. When it gets better, we're not going to change those plans, because we can reach our plant level there without it. We have about 15% on AECO today. We're enjoying some of those prices. I'd also like to commend my outstanding team under Eric's leadership there, where we handled this heatwave crisis there with very little downtime. That's the way we operate and execute in our facilities and our fields. It's going well, and it's going to be bigger this quarter than the last quarter, and no change in our program there. Just enjoy some higher cash flow on the non-hedged piece at this time, Josh. Great. Thanks, guys. Thank you. There are no further questions from our phone lines. I would now like to turn the call back over to Roger Jenkins for any closing remarks. Thanks, everyone, for listening to our call this morning. We had a real good quarter, we look forward to having another one. Thanks for everyone's helping efforts, I appreciate it. Be talking to you soon. Any questions, get with Kelly, and we'll get it going from there. Appreciate it. Ladies and gentlemen, this concludes your conference call for today. We thank you for participating.