Good morning, ladies and gentlemen, and welcome to the Enerplus Q3 2023 Results Conference Call. At this time, all lines are in a listen-only mode, but following the presentation, we will conduct a question-and-answer session. If at any time during this call you require immediate assistance, please press star zero for the operator. Also note that this call is being recorded on Friday, November 3rd, 2023. Now I would like to turn the conference over to Drew Mair. Please go ahead, sir. Thank you, operator, and good morning, everyone. Thank you for joining the call. Before we get started, please take note of the advisories located at the end of our third quarter news release. Our financials have been prepared in accordance with U.S. GAAP. Our production volumes are reported on a net after deduction of royalty basis, and our financial figures are in U.S. dollars, unless otherwise specified. I'm here this morning with Ian Dundas, our President and Chief Executive Officer, Wade Hutchings, Senior VP and Chief Operating Officer, Jodi Jenson Labrie, Senior VP and Chief Financial Officer, Garth Doll, VP Marketing, and Shaina Morihira, VP Finance. Following our discussion, we will open up the call for questions. With that, I will turn it over to Ian. Good morning, everyone. Our positive operating momentum this year continued through the third quarter. Liquids production was up 14% sequentially, outperforming our forecast. Once again, underpinning this production performance is strong well productivity from our core Bakken position. The outperformance of our wells has taken our annual production forecast higher, and we have increased our 2023 production guidance. The guidance update points to an increase in annual total production of 2,000 BOE per day and liquids production of 1,000 bbl per day at the midpoint. Adjusting for the divestment of our Canadian assets last year, the midpoint of our guidance is moving to 7% year-over-year liquids production growth in 2023. This is the second consecutive year of exceeding our stated 3%-5% annual liquids growth projection and has positioned us meaningfully ahead of the five-year plan we rolled out in 2021. Although anticipated to be modestly lower, we expect fourth quarter liquids production to remain resilient through the end of the year and are guiding to Q4 volumes, liquids volumes of 60,500 bbl- 64,500 bbl per day. This will leave us well-positioned as we enter 2024. We continue to track within our original capital budget and have narrowed our annual guidance for capital spending to $520 million-$540 million. The combination of production outperformance, cost focus, and the cadence of our capital program is driving a robust free cash flow profile with an attractive outlook for the fourth quarter. This will support a strong return of capital program through the end of the year. Having returned $200 million to shareholders during the first nine months of 2023, and an expectation of returning approximately $300 million of our 2023 cash flow based on the current commodity price environment, the pace of returns is accelerating in the fourth quarter. Quarter to date, we have already repurchased about $40 million of stock. Looking ahead into 2024, we expect to continue to return meaningful cash to shareholders. Based on current market conditions, our strong free cash flow outlook and low financial leverage, we expect to return approximately 70% of 2024 free cash flow through share purchases and dividends. I will leave it there and pass the call to Wade for an operational update. Thanks, Ian, and good morning, everyone. Third quarter production from North Dakota grew to just under 78,000 BOE per day, up 13% from the prior quarter. These strong quarterly volumes were driven by an active completions program, comprising 19 operated wells turned online during the quarter, excellent cycle times, and solid performance in our base production wells. We brought wells on production across three pads in FBIR and one in Williams County. We also continued to see strong production performance from the two Little Knife pads that we brought online during the second quarter. On average, these wells are continuing to produce quite meaningfully above type curve expectations. We have achieved some notable execution metrics as well this year. On the drilling side, we've averaged just over 10 days for spud to rig release for our 2-mi wells, which is more than a day faster than last year. We also drilled a record pacesetter well, which was eight days spud to rig release. On the completion side, we've also seen efficiencies build through the year, averaging just under 15 stages per day, also a year-over-year improvement. We set a company record on completions too, simulfracking a six-well pad in FBIR at 20 stages per day. This strong execution has allowed us to bring volumes online faster and help drive costs lower. Our expectation coming into the year was that our total well costs would average $7.8 million. With the efficiency gains we realized and lower steel costs, we anticipate coming in just below this forecast. Based on our procurement work for 2024, where we have secured key supply chain elements, including drilling rigs, directional services, sand, and pumping services, our expectation today is that we could see well costs come in approximately 5% lower next year. Turning to our non-operated Marcellus position. As expected, we saw quarterly volumes decline sequentially by 6% to 145 million cu ft per day, driven by limited capital activity this year. We expect our capital allocation to the Marcellus this year will represent just 3% of our 2023 capital budget. Lastly, we have made significant progress reducing our GHG emissions intensity through improved operational processes and planning and investment in emissions reduction projects. We now expect to exceed our 2030 Scope 1 and 2 emissions intensity reduction target this year, representing an approximate reduction of 40% from the 2021 baseline and 55% from 2019. We are also tracking ahead of our methane intensity reduction targets, and we expect to achieve an approximate 45% reduction from the 2021 baseline and 65% from 2019. To reflect this performance and our outlook for reducing a greater proportion of emissions by 2030 than previously anticipated, we have revised our emissions intensity targets. These targets are detailed in our quarterly disclosures released yesterday. In addition, we are endorsing the World Bank Zero Routine Flaring by 2030 initiative and have established a flare intensity target of less than 2% per 1,000 cu ft of natural gas produced by 2026. I'll leave it there and turn the call over to Jodi. Thanks, Wade. I'll start with our price realizations. In the Bakken, our realized oil price differential was $0.20 per bbl above WTI in the quarter. This was stronger than the previous quarter, reflecting higher prices for crude oil delivered to downstream markets in both Patoka and the U.S. Gulf Coast by the Dakota Access Pipeline, combined with a recovery in WTI prices throughout the summer. Additionally, U.S. refinery utilizations and margins remained strong throughout the third quarter of 2023. However, we've seen some modestly weaker trading in Bakken crude oil prices so far in the fourth quarter, due to increased basin production and lower seasonal refinery demand resulting from maintenance outages. As a result, we are revising our annual 2023 expected Bakken crude oil price differential to $0.25 per bbl below WTI, from par with WTI previously. In the Marcellus, our realized natural gas price differential weakened to $1.24 per Mcf below NYMEX, reflecting increased supply in the Northeast U.S. and regional storage levels tracking above historical averages. As a result of the weaker realizations, we are widening our annual 2023 expected Marcellus natural gas differential by $0.10 to $0.85 per Mcf below NYMEX. Operating expenses came in at $10.17 per BOE in the quarter. We continue to expect operating expenses to increase in the fourth quarter due to planned workover activity. However, with our strong year-to-date performance, our operating expenses are tracking the lower end of our previous full year guidance range. As a result, we have revised our 2023 OpEx guidance to $10.75-$11 per BOE, from $10.75-$11.50 per BOE previously. Overall, we generated $264 million of adjusted funds flow during the quarter, with capital spending of $121 million. Our free cash flow was $142 million. As our capital spending is expected to taper in the fourth quarter, we anticipate Q4 will be another strong period of free cash flow generation. Earlier, as Ian mentioned, this is setting up an attractive return of capital profile to finish the year, having already repurchased $40 million in stock during the month of October, with a total estimated return of $100 million in the fourth quarter, including the dividend. I'll leave it there, and we'll turn the call over to the operator and open it up for questions. Thank you. Ladies and gentlemen, if you would like to ask a question, please press star followed by one on your touchtone phone. You will then hear a three-tone prompt acknowledging your request. If you would like to withdraw from the question queue, please press star, then two. If you're using a speakerphone, we ask that you please lift the handset before pressing any keys. Please go ahead and press star one now if you do have any questions. Your first question will be from Greg Pardy at RBC. Please go ahead. Hi, it's Justin Ho on for Greg Pardy. So thanks for the thorough overview, and, and thanks for taking my question. So, with my first question, I'm wondering if you can delve a bit more into your operational game plan for next year and, what areas you expect to be more focused on for drilling activity in North Dakota? Morning, Justin. Wade, do you want to take that, please? Yeah, happy to. Good morning, Justin. You know, we look forward to providing even more color on that when we release our full 2024 plan and guidance, early in the next year. But we can, you know, directionally, point you to activity next year in terms of on streams will be balanced between Fort Berthold and Little Knife. And, you know, so you'd expect to see a program that looks quite a bit like this year's, next year. Thanks for that. That's really helpful. And, maybe switching gears, if I heard correctly, I think you mentioned, Wade, that you could see potentially 5% lower well costs next year? Could you provide more color on what's driving that and, if there's any embedded inflation in that expectation? Yeah, happy to. So, you know, we think we will end this year just under our $7.8 million total well costs estimate for 2023. And the pacing cost reduction that we saw this year will help us as we move into next year on an average basis. And then if you step back and look at the key components of our well costs for next year, the rigs that we need to drill the program next year are secured. They're the same rigs we've been using, actually for a couple of years. We've got pricing secured for those. We have secured pricing and services for pressure pumping. We also have secured all the sand that we'll need, as well as pricing for that sand. So a lot of the key services that go into assuring that we can actually execute the program and have some confidence in the costs that we'll pay for the program, are already set. Now, the things that will swing for next year are still, OCTG and, diesel, would be the two biggest ones. So, you know, we have enough line of sight to indicate we think we'll see, around that 5% reduction from where we end this year, going into next year. And, you know, that's all predicated on kind of an $80 WTI world. And then we'll just, continue to be strategic around trying to secure, steel, products and, other, components like that, that aren't locked in. That's great. Many thanks. Thank you. Next question will be from Patrick O'Rourke at ATB Capital Markets. Please go ahead. Well, hey, good morning, guys. So solid, results here today, and obviously, you, you took up the, the full year guide. Just looking at sort of the granularity in terms of fourth quarter on the liquids production, there's about a 4,000 bbl a day swing between the lower and the upper end of the guide you provided for, for fourth quarter. So just, wondering if you can unpack a little bit about, what those sort of swing factors will be that'll kind of land you, where you do in that range. Hey, good morning, Patrick. Yeah, I mean, I think you're seeing the granularity of a quarter there, right? We don't factor in for storms of the century, but we factor and account for weather that can move things around, you know, quite a bit. We're done with the operated program. There's a little bit of non-op on stream that are gonna be coming into the mix, as well. And, you know, maybe my last comment, you know, you're seeing sort of the impact of some really highly productive big pads that have come on, and they can move around a little bit. So, Wade, I don't know if there's anything else you would add to that story for Patrick. Yeah, I think you've hit on it, Ian. You know, just maybe a little deeper color on new pads. Even if you go and look at the production that we got from those two Little Knife pads in the second quarter, and then look at how anyone would have tried to forecast those into the third quarter, we had a pretty wide band of uncertainty. You now see what those did in the third quarter. They continued to be very robust. But, you know, anytime you have new pads coming online and they've only been online for 15-45 days, there's still a fairly broad range of uncertainty around how those will perform. You know, we anticipate that each of those wells will, at some time in the first few months, get, we'll run tubing, we'll add the first artificial lift. But even the timing of that is all dependent on well performance, and that ends up driving, you know, on a well-by-well basis, how much production you get, you know, in that ensuing quarter. Okay, maybe then, just shifting gears in terms of return on capital philosophy here. Execution on the NCIB has been very strong. We saw, you know, the October filing last night. Again, impressive stuff. Just wondering, you know, with respect to the dividend, the yield's a little bit lower than some of the peers today. Your payout ratio and, and what we're modeling for 2024 is also, much lower when you consider the capital program and the, the sort of liability or obligation for that dividend. So just, you know, wondering about the approach, with respect to scaling of that element of the return on capital program, how that kind of plays into your thinking as a shareholder value proposition, and sort of how we can think about the ratability of it going forward. With a focus specifically on the dividend, Patrick? When you said our payout's low, presumably you're talking about the simple payout on the dividend, not- Yeah, simple payout on... Well, like when I- Yeah. When I look at the capital program plus the dividend that we're anticipating, and, you know, understanding that the swing factor in terms of return on capital is that buyback, but just wondering, you know, how aggressive you feel you could be with dividend growth here? We'll be balanced in dividend growth. Yeah, I mean, we're. I guess our dividend is lower than some. Certainly, you know, our base is a little bit lower. We don't have a variable construct or a special. And, you know, this will sound familiar to you. You know, as we've thought about that construct, we see value in that in the stock. We think we're trading under intrinsic, and we don't see any signals in the market that suggest different structures are being particularly capitalized in a particular different way. And so we're really comfortable with these kind of valuations leaning into the buyback. And so, you know, we're interested in the dividend going up and, you know, it will sort of go up in the normal course as we reduce the share count. And as you well know, we raised it last quarter, so we'll keep looking at that. But, you know, right now, in the context of how we see the market, you know, we think that share buyback is really pretty attractive. You know, we think we see some of that in the stock performance. You know, for us, that compounding effect of buying stock at these kind of levels is, it feels like a money machine that gonna pay dividends, as it were, over time. And I think you probably have noticed, you know, we've sort of been increasing, as we continue to delever, increasing that return to shareholders. You know, now, you know, Jodi indicated we're thinking next year looks like approximately 70% return free cash flow. Yeah, I think it's all moving in a pretty good direction. Okay, thank you very much. Thanks, Patrick. Thank you. As a reminder, if you would like to ask a question, please press star followed by one on your touch-tone phone. Your next question will be from Jamie Kubik at CIBC. Please go ahead. Yeah, good morning, and thanks for taking my question. A bit of a two-pronged question here. So I guess we've seen overall Bakken natural gas volumes continue to climb in recent months, although depending on the data that you look at, gas to oil ratios seem to be pretty stable over the last couple of years. Just wondering if you can maybe comment a bit on what you're seeing in your portfolio on that side, and then maybe also discuss what's driven some of the outperformance in NGL production in recent quarters. Thanks. And you're looking specifically to our portfolio. You're not talking sort of statewide stuff? Statewide stuff looks like it's... Yeah, I mean, with respect to the question, question on your portfolio, specifically, what you've seen sort of gas to oil ratios and, NGL production, just what's driven the strength in recent quarters, Ian. Sure. Yeah, I guess, Wade, do you want to take both those? They sort of work in concert. Yeah, happy to. So I would say in our portfolio, you know, the GOR of our production, the biggest thing that drives that on a quarter-by-quarter basis is the nature of the new pads we're bringing online. So even within Fort Berthold, there's GOR differences. Some of the big pads we brought online, actually in 2022, had a higher GOR ratio. Some of the pads we brought online in Little Knife have a little bit higher GOR. So that's, that's one of the underlying drivers for that trend for us. But I would say the other key one is we're simply capturing more gas. You know, as you have followed our, you know, emissions reduction efforts, and frankly, just our efforts to capture and produce and sell more gas, we're essentially increasing that sales GOR ratio. And then that ties into the second question around NGL production. Obviously, we're as we capture more gas, we are selling more NGLs as well. And then I'll come back to my first point to close out the NGL answer. It also varies by the geographic area of where new pads come online. Those two fairly significant new pads in Little Knife not only did they have a little bit higher GOR than average and hence higher NGLs, the gas processing plants that we flow those through have a higher NGL yield or realization as well. And so that's why you saw that tick up a bit in Q2 and Q3. I think we've tried to be clear. We'll actually see that come back a little bit closer to our historic average on oil cut for Q4. That's great color. That's all for me. Thanks. Thank you. At this time, we have no other questions registered. Please proceed. All right. Well, we will leave it there. Appreciate everyone's attention. It's a very busy reporting day. Have a nice, safe weekend. Thank you. Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today.