Good day, ladies and gentlemen, and welcome to the Enerplus's Q4 year-end 2022 results conference call. At this time, all lines are in a listen-only mode. 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. This call is being recorded on Friday, February 24th, 2023. I would now like to turn the conference over to Drew Mair. Please go ahead. Thank you, operator. 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 fourth quarter and year-end 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. 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, Shaina Morihira, VP Finance, and Garth Doll, VP Marketing. Following our discussion, we will open up the call for questions. With that, I'll turn it over to Ian. Good morning, everyone. Our positive operational and financial performance continued through the fourth quarter of 2022. Production in the quarter averaged just under 107,000 BOE per day, an increase of 4% compared to the same period in 2021. Capital spending of $86 million in the quarter helped to support another quarter of strong free cash flow generation of $230 million. Overall, we believe 2022 was an outstanding year for our company. We executed our operating plan efficiently, delivering volume growth ahead of expectations while maintaining a focus on cost control and capital discipline, which helped to dampen the impacts of the inflation we were all experiencing. Total production increased 9% year-over-year. This increases to 17% on a per share basis as a result of our significant share repurchase activity during the year. While we were clearly impacted by cost inflation, strong planning, procurement, and execution sheltered us from the worst effects of it, ultimately, we were able to operate within our original 2022 capital spending guidance range. The combination of production outperformance, cost control, and the strong oil and gas pricing environment in 2022 drove a robust free cash flow profile. We generated free cash flow of just under $800 million during the year. This allowed us to reduce net debt by 65% and return over $450 million to shareholders through dividends and share repurchases. We increased our quarterly dividend by 67% last year and reduced our share count by 11% over the course of the year. Importantly, we also made further advances on our key ESG initiatives. Key highlights in 2022 include an 80% reduction in our three-year average lost time injury frequency, a reduction in annual methane emissions intensity by 9%, and a reduction in total greenhouse gas emissions intensity by 16%. In a separate news release yesterday, we also reported our year-end reserves. Under U.S. reserve standards, we replaced 112% of our 2022 production through net proved reserve additions. Under Canadian standards, we replaced 139% of production through gross proved plus probable reserve additions. Under each reporting standard, we added reserves at competitive costs. For example, our net onstream PDP finding and development costs came in at $8.27 per BOE, reinforcing our view that our deep resource base in North Dakota will continue to support a resilient long-term outlook for Enerplus. Turning to 2023, consistent with our multi-year outlook, we have a Bakken-focused capital program designed to generate attractive free cash flow and efficiently deliver 3%-5% liquids production growth. Our capital program will be very straightforward, with spending of $500 million-$550 million, 95% of which will be allocated to Bakken. Our liquids production guidance is 57,000-61,000 barrels per day. This is in line with our 3%-5% growth rate, investment adjusted for the sale of our Canadian assets at the end of last year. Similar to 2022, we expect this growth rate to be enhanced on a per share basis as we continue to execute our share repurchase program. With natural gas prices currently under pressure, we anticipate significantly reduced spending in our Marcellus gas asset. This is expected to result in approximately 8% lower Marcellus natural gas volumes in 2023 compared to last year. Overall, our total production guidance for this year is 93,000-98,000 BOE per day. We expect to continue to generate competitive free cash flow this year. At an $80 West Texas price and $3.50 NYMEX price deck, we project about $475 million in free cash flow, which maps to a current free cash flow yield of approximately 14%. Priorities for free cash flow will continue to be focused on returning capital to shareholders and reinforcing the balance sheet. As we previously indicated, we plan to return at least 60% of 2023 free cash flow to shareholders. Based on current market conditions, we intend to continue to prioritize share repurchases for the majority of our return of capital plans, given our view that the intrinsic value of our business is not adequately reflected in our share price. As we assess the market today, we also anticipate accelerating a portion of our second half weighted free cash flow profile into our share repurchase program during the first half of 2023. Lastly, we updated our five-year outlook to include 2027 and better reflect the ongoing inflationary environment. The plan is focused on the Bakken. It is designed to deliver attractive free cash flow and sustainable growth, and is underpinned by a deep, high-quality drilling inventory. The updated plan projects annual capital spending of between $500 million-$550 million, 3%-5% annual liquids production growth, and an average reinvestment rate of approximately 50% based on long-term commodity prices of $80 and $4 NYMEX. I will leave it there now. Turn the call over to Wade for an operational update. Thanks, Ian. Good morning, everyone. Beginning with North Dakota, during the fourth quarter, we drilled 10 wells and brought five wells on production. Our strong well performance in 2022 and a resilient base production helps drive fourth quarter North Dakota production 8% higher than the fourth quarter of 2021, despite severe weather impacting fourth quarter 2022 volumes. In our non-operated Marcellus position, we participated in three net wells that came on production during the fourth quarter, capping off an active year of drilling and completions activity. Fourth quarter 2022 Marcellus natural gas production was 12% higher than the fourth quarter of 2021. Reflecting on 2022, it was an exceptional year operationally, marked by a continued focus on safety, impressive well results, efficiency gains, and cost control. Moving on to 2023, I expect our operating momentum to continue. While inflation will continue to be a headwind, our planning and procurement have left us well positioned to efficiently execute our program, which is expected to translate into strong financial returns for the business. Our drilling and completions plan in North Dakota is straightforward. Two full-time rigs and a pressure pumping crew for 9-12 months. The program will be focused primarily around our FBIR and Dunn County acreage. We plan to drill between 55 and 60 gross operated wells and bring 45-55 gross operated wells on production with an average working interest of 87%. We also plan on executing a small number of refrac opportunities this year, which relates to a suite of older vintage wells we acquired in Dunn County, which we believe are under-stimulated. Turning to well costs, while we're continuing to drive improvements to our drilling and completion cycle times, we expect well costs to average about $7.8 million in 2023, up 10% compared to our 2022 average. This increase is largely driven by higher steel and consumable costs. Operating expenses are also continuing to experience some cost pressure year-over-year. This is being driven by a few key drivers. General cost escalation, particularly where we have contracts with price escalation clauses linked to CPI. Higher gas processing volumes and therefore gas processing costs due to improved capture rates. Lastly, higher well service activity driven by several factors. Lastly, we've updated our drilling inventory estimates for January 1, 2023, which benefits from the continued subsurface review of the Dunn County and Williams County assets, as well as additional activity from offset operators in these areas. We peg our core and extended core drilling inventory at 655 net locations. Relative to our plan to bring approximately 50 net operated and non-operated wells online this year, this inventory continues to offer significant running room. I'll leave it there and now pass the call to Jodi. Thanks, Wade. Our strong earnings and cash flow momentum continued in the fourth quarter, closing out a solid financial year. Adjusted net income per share was $0.78 on a diluted basis in the fourth quarter, an increase of 56% from the same period in 2021, and adjusted funds flow was $315 million in the quarter, up 22% over 2021. With capital spending of $86 million, our fourth quarter free cash flow was $230 million, which we allocated towards the balance sheet and returning capital to shareholders. We returned $181 million to shareholders in the fourth quarter, including $12 million in dividends and $169 million or 9.8 million shares repurchased. We reduced net debt by $170 million, or over 40% during the quarter, and ended the year with net debt of $222 million, or 0.2x net debt to funds flow. Our debt reduction during the quarter was achieved through proceeds from our Canadian asset sale, as well as a portion of our free cash flow generated. Turning to 2023, we expect Bakken oil prices to continue to trade at premium to WTI. Bakken crude continues to be strongly bid, and the premium pricing is supported by significant excess pipeline capacity in the region and strong prices for crude oil delivered to the U.S. Gulf Coast. We expect our realized Bakken oil price to average $0.75 per barrel above WTI in 2023. Our expectation for our Marcellus natural gas price differential in 2023 is $0.75 per Mcf below NYMEX, which is consistent with 2022. As Wade noted, operating expenses are expected to increase year-over-year due to inflation, increased gas processing volumes and higher well service activity. Our 2023 operating expense guidance is $10.75 per BOE-$11.75 per BOE. Our cash tax guidance in 2023 is 5%-6% of adjusted funds flow before tax based on a commodity price environment of $80 per barrel WTI and $3.50 per Mcf NYMEX. Lastly, as an update on our normal course issuer bid or NCIB, we have repurchased 1.4 million shares year to date and have 6.5 million shares remaining under our current authorization. As a reminder, we can renew our NCIB in August for another 10% of outstanding shares at that time. I will leave it there, and we'll turn the call over to the operator and open it up for questions. Thank you. Ladies and gentlemen, we will now begin the question and answer session. Should you have a question, please press star followed by the one on your touch tone phone. You will hear a three-tone prompt acknowledging your request. Should you wish to decline from the polling process, please press the star followed by the two. If you are using a speakerphone, please lift the handset before pressing any keys. One moment please for your first question. Your first question comes from Greg Pardy of RBC Capital Markets. Please go ahead. Yeah, thanks. Good morning, and thanks for the rundown. Really, there's just one question I'd have for you, and that is, if you look at your, like, just all the messaging around the shareholder returns and given, you know, pretty limited runway on the NCIB, what's the appetite for to do an SIB here in the near term? Thanks, Greg. Jodi, do you want to handle that? Yeah. Sounds good. Morning, Greg. Morning. you know what? We believe today that NCIB gives us lots of flexibility to buy back shares. As I mentioned, we're able to renew it again in August for another 10%. We do view the SIB as a tool, that we can utilize, if in the future we, see, you know, opportunity or strategically to buy back an even larger portion of our shares. Okay. Maybe just a follow-up then is that, how are you thinking? I know you're saying at least 60% of free cash flow, so it gives you some latitude. We've seen, you know, different companies pursuing different strategies, but in some cases there's, you know, net debt floors and the net debt floors then are unlocking payout ratios closer to maybe 80%-100% or so. Given the balance sheets, what, $250 million in net debt, I mean, you're gonna be debt free here pretty soon. Could at some point we expect that 60% to increase as a payout? It could. Yeah, we've chosen the very specific language of at least 60% to sort of deal with that issue. You know, Greg, as we think about it now, again, I use the word sustainability a lot. We're looking for a sustainable plan that makes sense in the fullness of time. You know, to-today, that 60% number allows us to buy what we think is a return, a meaningful amount of capital. We think that that yield, if you will, is competitive, and it allows us to continue to pay down debt. You know, pick a price deck. You know, if you like the strip this year, there's pretty steep backwardation that sits in there, right? You know, gas has come off. You know, we would model under strip getting debt free towards the end of the year. You know, as I think about it from a gating perspective, really comfortable getting to zero debt or zero net debt. You know, this plan at that 60% kind of level, that all sort of comes together this year. You know, if we get to that level, 'cause there could be intervening events, I guess acquisition activity or something along those lines is a good example of that. If we get to that level, you know, then I think you've got a pretty strong likelihood that there could be opportunity for returns to increase at that point. You know, there'll be, I think a lot of people if pricing stays high, I think the industry is gonna be in a state where many companies are going to be in a zero debt position. You know, I think then maybe the really interesting thing will be the optionality around all of that, 'cause there's gonna be lots of opportunities to do a lot of interesting things, increasing returns. You know, if the shares are performing really well, maybe there's a bit of cash that gets built. You know, I don't know how all that plays out at this point, but, you know, I think this is the year where we're gonna be approaching that towards the end of the year. You know, come back to your original question, could returns go up? Yeah, clearly they could go up. Okay. Understood. Thanks for that. Thank you. Once again, ladies and gentlemen, if you do have a question, please press star one at this time. The next question comes from Patrick O'Rourke of ATB Capital Markets. Please go ahead. Good morning, guys. I was gonna ask about the dividend and the parameters for growth here, but I actually just wanna unpack very quickly a comment that Ian made with respect to potential for intervening events and acquisition activity. I'm just kind of curious how you're looking at the M&A market right now. I know you've, you know, sort of thoughtfully run through what your ideal targets would be or what the parameters for that are. I'm just wondering about your sense in terms of bid-ask spreads and what you think might be out there that would be attractive. Good morning, Patrick. Acquisition activity, you know, it's something that we have always maintained a capability to do and an interest in doing, if we saw something that would be accretive to shareholders, make the business better, make the portfolio better. Pretty generic statement, it's true. You know, as we look at our portfolio, there are no holes in our portfolio. We've got a deeper inventory than we've ever had. Non-core stuff is gone, and we see a really good runway in front of us. We also have exceptional financial capacity to be able to add to that, if we see opportunities that make us better and that are accretive. I guess maybe the bar is reasonably high to do something. We maintain a lens into the market. To your question of bid-ask spreads and those sorts of things, you know, volatility is never a friend to successful transactions. You know, if you look back over the last couple of years, there actually hasn't been as much as we would have been typically seen, and I think that ties just to volatility. A little bit of capital markets volatility, a lot to pricing volatility. Oil, it's actually been sort of stable-ish for a little while now. You know, if it sort of stays in that 70 to 80 kind of world, I could imagine some activity happening. I mean, there's clearly a lot of conversations, a lot of people, you know, testing the waters, a few processes that get out there. You know, we really haven't seen a heck of a lot of stuff come together. I would guess bid-ask starts to narrow. You know, one of the things that'll be very interesting is if oil assets start to trade in the context of the strip. With that backwardation that, you know, I think a lot of us struggle with that longer term price signal. We don't see how that really connects to our view of supply demand fundamentals. I would guess we're gonna start to see some oil stuff start to happen over the course of the year. You know, gas is a bit different now. You saw a very... You know, it was, it was tough, I think, for buyers to get gas deals done in the last couple of last year and a half with prices so strong. You know, now they've taken it in the year, and I think there's a lot more interest on the buy side to wanna do something. You know, will sellers be interested in doing that? I don't know. Again, back to the volatility question. I think it's gonna be interesting to see if gas trades when the prompt is so low. Don't know if that helps you out though. No, that's very helpful. I, you know, I'll just circle back to the original question I was gonna pose here. You know, I know you went through some of the return of capital with Greg a moment ago, getting to zero debt, and potential to exceed the 60% target return for investors here. Just, you know, wondering with respect to the dividend, how you think about sort of the cadence and sizing of growth. You've got sort of 3%-5% target liquids growth. You're buying back 10% of your float. Like, how would you think about keeping the dividend right-sized in this environment? The dividend's important. You know, growing stable base dividend's important. You know, when we step back and think about the mathematics of our business, you know, that share buyback is. The math is compelling. It compounds, and we see and you saw it last year. You know, we really leaned into it, and we think that is a really good decision for our shareholders. You know, dividend in these kind of conditions, you know, it will go up over time, but we just see more value in the buyback, based on the valuation of the company and where it sits at this moment. You know, others have taken different approaches to that. When we look into the market for pricing signals, I guess broadly, we don't see the dividend as offering a superior advantage to our shareholders now. You know, it'll stay there. We want it to grow over time. I mean, if you recall in Jodi's comments, she referenced the fact that we are open to alternatives, specials and variables and all those sorts of things. We'll be responsive to the market. You know, at this moment, we see a modest growing dividend as a part of the capital structure and the return proposition. You know, it doesn't dominate our thinking based on where we see the valuation of the stock. Thanks very much, Ian. Thanks, Patrick. Thank you. The next question comes from Jamie Kubik of CIBC. Please go ahead. Yep. Good morning, and thanks for taking my question. Enerplus had a slide in its presentation last year that highlighted the improvements in well performance it was enjoying in the Bakken in 2022 compared to its prior vintage wells. I'm just curious if you would expect to see continued improvement in your 2023 vintage wells based on where you're targeting drilling this year? I guess second to that is how does your guidance incorporate the improved performance that you've enjoyed? Thanks. Wade, do you want to take that? Yeah, thanks for the question, Jamie. You know, the continued improvement in efficiency in our drilling completions and even facility programs got masked a bit last year with all of the inflationary pressures that we in the industry were seeing. We did drive a improvement in our drilling cycle times and in the efficiency of our fracture stimulation program. We continue to, you know, optimize the facility design as we weave in additional emissions controls and optimize those facilities for the kind of development we're doing. We're actually quite pleased with that, and that actually was one of several components that helped us mitigate the impacts of the inflationary environment last year. We would expect that same trend to continue this year. We have incremental technologies that we continue to test, that we are finding some success with in terms of shaving incremental time off of our drilling and completion activity times, which ultimately translates into both a bit of cost savings, but also a more efficient program where we see the production come on sooner. You know, I would say that the guide for 2023, you know, it has a fairly basic assumption around, you know, seeing about a 10% increase year-over-year in well costs. Most of that increase is inflationary pressures that frankly we were seeing near the end of last year, early this year. It is offset by a few additional things around, you know, differences in, small differences in scope and continued anticipated efficiency gains. I'd say it's all baked in there, but we always feel like we've got a bit of a chance to outperform that as we apply these new ideas that the team continues to come up with. I think a really important point for last year's program was also the actual well performance that came from that drilling and completions program, where we saw, you know, really good well performance beyond what we expected from the pads we brought on last year. As we've noted, you know, those pads on average were really high quality relative to the average pad from previous years. Beyond that, we saw even better performance than we thought. This year's program looks really solid. I would say it looks a lot more like, you know, maybe that previous three or four-year average of well quality. With that said, we think that the optimizations we were doing last year impacted well performance a bit incrementally, and we're continuing to use those same optimizations in our program this year. Again, we, you know, we always have a bit of optimism around can we continue to improve the overall capital efficiency of the program that we're executing. Okay. That answers that. Thank you very much. You're welcome. Thank you. There are no further questions at this time. Please continue with closing remarks. Looks like we might have one more question, operator. I apologize. The next question is a follow-up from Greg Pardy. Please go ahead. Yeah, sorry, I did think I just sneaked that one in. Wade, you talked about just a small number of refracs, and I'm just curious, what do those cost? How many have you got planned? If they're successful, what kind of incremental production would you expect to see from those, like maybe on a per well or per pad basis? Yeah, thanks. Thanks for the question, Greg. Let me zoom out for a minute. You know, as we've deepened our subsurface analysis of the assets that we bought in Dunn County about two years ago, what we've recognized is that there are several areas in those producing units that, you know, were stimulated many years ago, some as old as, you know, 10 years ago. In our view, there are places that are under-stimulated, it looks like there's additional resource that could be recovered from those producing wells. We're gonna test that concept this year. Right now, we're planning on two pads of re-completions. I mean, that's roughly about seven or eight wells on a gross basis. In terms of the cost, what I would note for you is, you know, the stimulation itself is not too different than a stimulation of a new well. There are a few additional costs required to get the well prepped, get it cleaned out, get it ready to be stimulated. They do cost a little bit more than a just the completion phase. Of course, the facilities and everything are already there. In terms of incremental production, we don't have an external guide on that at the moment. We actually have a bit of a range of what we think might happen with each of those wells. We really view this year as a bit of a test case. Assuming this year goes fairly well, we would expect to see this kind of a recompletion program be a regular part of our annual program for years to come. There's a moderately good number of additional candidates that go beyond this year's program. Okay, thanks for that. You'll update us over the course of the year, maybe on progress? Certainly. Okay. Yeah, I wouldn't expect that. Thanks very much. Yeah, I wouldn't expect it to be, you know, immediate. The program's spread out kinda mid to end of the year. Yeah, you'd get an update. Okay. Understood. Thanks again. Thank you. There are no further questions at this time. Please continue with closing remarks. All right, we'll call it there. Appreciate everyone's time on this busy reporting week. If you're on the western part of the continent, we share your pain. If you're on the east, enjoy the warmth, 'cause this is coming at you, hopefully. Everyone have a great weekend. Thank you very much. Ladies and gentlemen, this does conclude the conference call for today. We thank you for your participation and ask that you please disconnect your lines.