Good morning, ladies and gentlemen, and welcome to Enerplus Q2 2022 Results Conference Call. At this time, all lines are in 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 August 5th, 2022. I would now like to turn the call over to Drew Mair, Manager of Investor Relations. Please go ahead. 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 second quarter news release. Our financials have been prepared in accordance with the 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, Shaina Morihira, VP Finance, and Garth Doll, VP Marketing. Following our discussion, we will open up the call for questions. With that, I will turn it over to Ian. Thank you, Drew. Good morning, everyone. Our second quarter results and updated 2022 outlook reflect strong operating momentum and disciplined capital allocation. For the second consecutive quarter, we are increasing our annual volume guidance due to well performance and efficient execution. We believe this outperformance is particularly evident considering the impacts to our production from the severe weather in the Bakken we spoke to last quarter, and the recently announced sale of assets in Canada. Combined, these events have impacted our annual production by almost 2,000 BOE per day. Yet we have increased our production guidance by 1,500 BOE per day since our initial 2022 guide released in February. This has set us up for a very robust second half of the year, where we expect significant production and cash flow growth. We continue to operate within our capital guidance range of $400-$440 million as our approach to procurement, focus on cost control and strong execution are helping to mitigate many of the inflationary pressures we are experiencing. We generated over $325 million of free cash flow through the first six months of the year, which we expect to increase by an incremental $475 million in the back half of the year, based upon rest of year prices of $90 WTI and $6.50 NYMEX gas. Given this free cash flow outlook and our solid financial position, we have increased our cash returns to shareholders to at least 60% of free cash flow commencing in the second half of 2022 and continuing through 2023. We have increased our absolute minimum return commitment in 2022 to $425 million, up from $350 million previously. At today's corporate valuation, this minimum commitment represents a competitive cash return yield of approximately 15%. Moving on to divestments. Last week, we announced the sale of a portion of our Canadian assets for total consideration of CAD 140 million. We continue to advance opportunities to divest our remaining Canadian assets in Alberta and Saskatchewan. Lastly, we have updated our five-year outlook to better reflect the higher commodity price and inflationary environment, as well as to exclude our Canadian asset base due to the ongoing divestment process. Previously, our five-year outlook was based on $70 WTI prices and $3 NYMEX. We are increasing our commodity price assumptions to $80 and $4. Under these updated assumptions, our annual capital spending from 2023 through 2026 is forecast at approximately $500 million, and our cumulative free cash flow between 2022 and 2026 is estimated at approximately $3 billion. This five-year free cash flow forecast is equal to our current market valuation. I will leave it there and turn it over to Wade for an operational update. Thank you, Ian, and, good morning, everyone. I'll start with a review of our second quarter operating results before moving on to our outlook for the rest of the year. Total second quarter production was just over 94,000 barrels of oil equivalent per day, including about 57,000 barrels per day of liquids. Although we experienced some downtime early in the quarter due to severe weather, we exited the quarter with strong volumes following an active period of completion activity and strong well performance. During the quarter, we brought 24 gross operated wells on production across 4 pads in North Dakota. Our team continues to customize the development of each pad in terms of landing zones, spacing, offsets to existing producing wells, completion design, artificial lift, and flowback. This optimization, combined with our high-quality locations, are contributing to the outperformance we're seeing from our 2022 wells. These wells have averaged approximately 2,300 BOE per day per well on a peak consecutive 30-day basis. This outperformance is supporting the increases we have continued to make to our production guidance so far this year. We now expect total annual production to be 97,500-101,500 BOE per day, up 1,000 BOE per day at the midpoint. In terms of the cadence of our remaining completions activity in North Dakota, we anticipate bringing eight operated wells online in the third quarter and five online in the fourth quarter. Additionally, we have some non-operated completions in the forecast for the second half of the year. Our program is expected to set up strong second half volumes. As highlighted in our news release, we expect to deliver approximately 15% sequential liquids production growth in the third quarter. Touching on inflation, we have continued to experience upward cost pressure due to the impacts of inflation and supply chain tightness. The impact is primarily being felt in our capital program. However, we remain well positioned to mitigate impacts of inflation on the 2022 program through our early approach to contracting last year, strategic partnerships, and the technology-driven efficiency gains we continue to experience. As a result, we are continuing to operate within our $400-$440 million capital spending range. Touching briefly on activity in our non-operated Marcellus position, we participated in 22 wells which were brought on production during the quarter with an average working interest of 7%. Well performance continues to be solid, with peak consecutive 30-day production rates of approximately 24 million cubic feet per day per well. I'll leave it there and now pass the call to Jodi. Thanks, Wade. I'll start with our realized prices during the second quarter. In the Bakken, we realized a sales price premium to WTI of $0.85 per barrel. This continued strength in Bakken oil prices is being driven by an improving supply and demand balance, significant excess pipeline capacity in the region, and strong prices for crude oil delivered to the U.S. Gulf Coast. With Bakken oil prices continuing to trade at a premium to WTI, we now expect our annual 2022 realized Bakken oil prices to average $1 per barrel above WTI. On the natural gas side, our realized Marcellus price was $0.59 per Mcf below NYMEX in the quarter. We continue to expect Marcellus differentials to widen for the remainder of 2022 due to the seasonal impact on natural gas prices in the region and have left our full-year 2022 guidance of $0.75 per Mcf below NYMEX unchanged. Operating costs were $9.74 per BOE in the second quarter. We anticipate operating costs will trend higher in the third quarter, largely due to anticipated increases in well service activity and artificial lift system replacements, along with an increased liquids weighting. However, on a full-year basis, we have tightened our operating cost guidance to $10 per BOE from our previous range of $9.75-$10.50 per BOE. This includes the impact of our previously announced Canadian asset divestment, which is expected to close at the end of the third quarter, and as a result, we expect lower overall operating expenses in the fourth quarter. We recorded current tax expense of $12 million in the second quarter, and based on the current commodity price environment, we continue to expect 2022 cash taxes of 2%-3% of our adjusted funds flow before tax. Moving on to the bottom line. Our second quarter adjusted net income was $172 million and adjusted funds flow was $297 million. With capital spending of $133 million in the quarter, we generated free cash flow of $165 million. We plan to continue to prioritize returning capital to our shareholders, along with reinforcing the balance sheet with our free cash flow. Under our updated return of capital framework, we have committed to returning a minimum of 60% of free cash flow beginning in the second half of 2022 and at least $425 million to shareholders this year, whichever is greater. Through July, we have returned $179 million through dividends and share repurchases, leaving a minimum remaining return of $246 million between now and year-end. This amount could be higher. If WTI averaged $100 for the rest of the year, this remaining return in the second half of the year would increase to approximately $300 million. We have also extended our commitment to returning at least 60% of our free cash flow into 2023 as well. Over the last 12 months, we bought back 10% of our public float under our normal course issuer bid by spending $285 million and repurchasing approximately 26 million shares at an average price of $11.14 per share. We announced our plan to renew the bid for another 10% of the public float upon its expiry in August. Our view remains that our current share price is discounted compared to our intrinsic value, and under strip pricing, we would anticipate using both a normal course issuer bid and a substantial issuer bid over the next 12 months to fulfill our return of capital commitment to shareholders. In addition to the share buyback program, we have also increased our quarterly dividend by 16%, effective with the September payment. This is our second dividend raise this year and represents an increase of over 50% from the start of the year. The remaining free cash flow not allocated to shareholder returns will be prioritized for strategically reinforcing the balance sheet, resulting in approximately 0.3 times net debt to funds flow by the end of this year. I will leave it there and turn the call over to the operator and open it up for questions. Thank you. Ladies and gentlemen, we will now begin question and answer session. Should you have a question, please press star followed by the number 1 on your touch-tone phone. You will hear a three-tone prompt acknowledging your request, and questions will be pooled in the order they are received. Should you wish to decline from the polling process, please press star, then the number 2. If you're using a speakerphone, please lift the handset before pressing any keys. One moment here for your first question. Your first question today comes from Patrick O'Rourke with ATB Capital Markets. Please go ahead. Good morning, guys. It's Patrick O'Rourke at ATB Capital Markets. Just a quick question. The current dichotomy here between buybacks and dividends in terms of your return on capital formula, obviously, you've clearly gravitated towards buybacks. I know Jodi just mentioned the potential for an SIB. You know, as you look at these and you've exhausted the buyback in 2022, potentially you'll exhaust it in 2023, maybe use an SIB and what the parameters of that are. Is there any potential you know, I think you've been asked this in the past, to see special dividends issued, especially in light of some of the positive performance we've seen from your peers when they've done so? Hey, Patrick. How are you? I'll turn it over to Jodi to address. There's a few things in that. Sure. Morning, Patrick. You know, maybe stepping back, when we think about the return of capital, you know, components of it being dividends and buybacks, we've really considered both parameters. Obviously, the base dividend, we want that to be sustainable. We want that to be continuing to be a growing base dividend. In the context of our total return of capital, you know, we see the biggest part of it or the bulk of it being potentially between a variable or a special dividend or, as we've mentioned, the buyback. Just with our share prices where we see them trading at these levels, which is significantly below the intrinsic value of our shares, we think the best value or the best ability to return capital to shareholders would be through buybacks. We do have those options available to us. As you mentioned, we do have the option to do a substantial issuer bid as well as renewing the NCIB for another 10% here in August. Obviously, if you know, parameters change, and we would continue to look towards the potential to have a variable or special dividend if you know, share prices increase in the future, and we believe we are valued at a value where it makes sense. Okay. Thank you. Maybe just shifting gears slightly to the operational front. The bump guidance is pretty impressive here, especially in light that it looks like it's driven mainly by liquids. On the back of the outage and the asset sale and capital staying flat here, albeit you know I think inflationary considerations came previously. Just wondering if we could get into or get some more color on what's really driving the outperformance versus your prior expectations. Are you still sort of augmenting the completion process and well design here? Is it a better understanding of the geology or hitting on a you know sweet spot in terms of the assets that you've acquired? Is it just, you know, in general, the conservative nature of your planning gave you a little bit of runway here? Thanks. Thanks for that, Patrick. We have raised twice this year. The Q1 raise was performance-oriented, you know, largely related to managing downtime as we had a pretty light capital quarter. Effectively, no on-streams that influenced it. You know, we managed through the storm. We didn't escape that, but we managed through the storm. What's going on this quarter, and Wade talked about it a little bit, and I'll turn it over to him in a second on this, is well performance. You know, this is not a function of sandbagging numbers and hitting average or deterring results. We've been pretty transparent with the actual performance every quarter, every year. We've updated our deck this morning, and you can sort of see how the 2022 wells collectively are performing versus earlier vintages, and it's pretty stout so far. Early times, but pretty stout. What I'll do is ask Wade to maybe get a little bit into what's going on there at the well level because it's been a good quarter for sure. Sure. Thanks, Ian, and appreciate the question, Patrick. I'm actually gonna make a quick comment or two on the base performance and the acquired assets, and then I will dive into well performance. You know, as Ian noted, part of our outperformance this year has simply been good uptime, and that's been across both our existing legacy wells plus the wells that we purchased last year. Even on the capital program, I'll just note one of the four pads that we brought on this year came from that acquired set of assets from last year. Turning to well performance, I think it's helpful maybe to just zoom out and look at the whole basin for a moment and reflect on, you know, the Bakken has actually had very strong well performance over its history. There's been lots of periods where step changes have been made in well performance. I think importantly, in contrast to some other basins, as most operators moved into full development mode, of course, there have been learnings and adjustments, but there hasn't been as many big kind of missteps, if you will, in terms of seeing how that reservoir would perform in development mode. I think you're seeing that even play through in our results this year. Speaking specifically to what we have been doing, given the layout of our assets today in the aspect that almost every new pad that we are developing already has some existing producing wells in the unit or near the unit. We take a very customized approach to the design for every unit, taking into account everything we know about the subsurface, the geology, the reservoir conditions, and everything we know about all of the offsetting producing wells, et cetera. What that ends up resulting in is a very customized program where we will optimize the number of wells we put in the Middle Bakken, in the Three Forks, where they're landed, how many, how they're spaced, how they're spaced relative to existing producers, how we think about the actual frac design in terms of subtle changes in proppant loading. Also integrating that with how we'll flow those wells back and then put them on the initial artificial lift. We feel like we're actually seeing really good results from that approach. Clearly, the results this year, you know, have been really quite strong, in some places have exceeded our expectations. We think that is a direct result of this very customized pad by pad, unit by unit development approach. Maybe I'll just add, you know, it's early time, right? So we're, you know, we're giving you 30-day rates and, you know, we've got a little longer on some of these wells. You can't find many examples of a quality 30-day rate in the Bakken that turns into a bad well, you know, unlike an IP24 or something like that. So we're feeling good. You know, we're not in a position today where we're saying, "Hey, take this and extrapolate it against another 650 wells." You know, will these wells roll? We haven't seen decline yet, those sorts of things. But it's positive it's outperformance. You know, there's a few of these pads are in areas where we would expect better than an average type curve. We don't have an average type curve, right? We've got 16 different subsets of this curve. We have seen outperformance in areas. You know, is that because we are in a statistical play that generally doesn't disappoint? That's maybe part of it. You know, that explanation Wade gave, we think it's paying off. Time will tell, but it's been a strong start to the year. Okay, thank you very much. Yeah, thank you. Your next question today will be coming from Greg Pardy with RBC Capital Markets. Please go ahead. Yeah, thanks. Good morning. Thanks for the rundown. I mean, you know, great operating color. The questions I've got are probably more around pricing and then just stuff like cash taxes. I know, Jodi, you mentioned 2%-3% of pre-tax AFFO for this year. Where does the company now kinda sit from a current tax position, particularly as we look into 2023? Yeah. Thanks, Greg. Yeah, like, as you mentioned, we are expecting at these commodity price levels, both oil and gas, we would expect to use the majority of our operating losses in the U.S., during this year. If these prices hold, I think 2%-3% is still a good number to use for this year, but we would see that moving towards 10%-12% of adjusted funds flow before tax next year, again, under the current commodity prices for both oil and gas. Okay, thanks for that. You went into good detail. I mean, obviously, Bakken oil prices have been really, really favorable for a variety of reasons. What about NGLs? 'Cause this is still, you know, 15%-16% or so of your production, and it obviously has not participated anywhere near what we've seen in terms of oil prices. How should we think about those prices going ahead? That's for sure. In Q2, we did see some weakness in the NGL pricing that was primarily driven by weaker propane and butane prices and has become a smaller portion of WTI. About 42% of our mix in the Bakken is propane, with 24% is butane. Going forward, I think in this range is a good way to think about it as a percentage of WTI. Probably not unlike what we saw in the second quarter, sort of in the mid-30% range or so on the NGLs? Yeah, I think that would be a good number. Okay, terrific. Thanks very much. Thanks, Greg. Thanks. Operator, are there any more questions? Yeah, well, you may have lost the operator. It looks like we don't have any more questions on the line or- Oh, sorry. Sorry about that. It wasn't going through. I was talking here. The next question is from James Kubik with CIBC. Please go ahead. Yeah. Good morning, and thanks for taking my question. Just around the shareholder return framework. You did increase your plan to return 60% of free cash to shareholders from 50%. Could we think about that moving higher as your debt levels get closer to zero, or do you look to preserve additional dry powder for potential M&A or and inventory replenishment? Can you talk about those items? Let's make this the CFO show. Jodi Jenson Labrie, you take that. Sure. Thanks, Jamie. Obviously, we have debt remaining on our balance sheet just around $550 million at Q2. With current debt on the balance sheet, we think 60%, moving to that 60% or at least 60% returns, makes a lot of sense. Obviously, as we continue to pay down debt, and as we look into the future, that could be possible, kinda in the 2023 timeframe. We would expect that this number would be moving higher from 60%, but I think, you know, I wouldn't expect it to go to 100%. You know, we're in a really strong place. We have some of the deepest inventory in the Bakken. We just wanna make sure we. Our focus remains on ensuring we have a sustainable business over the long term. Okay. Then maybe with the remaining asset sales from Canada, remaining production to be sold out of Canada, you know, if you succeed in disposing of that before the end of the year, could that be, you know, a catalyst possibly to move the shareholder returns higher? Or how should we think about that impacting how you think about shareholder returns? Yeah. Morning, Jamie. I think the framework we have today, and this will evolve depending upon when things happen. For your lens of this year timing, if we are to exit this year, I think it's gonna look similar. Debt repayment, we would forecast the remaining debt with this enhanced shareholder return program, so we still see debt this year. Debt plus enhancement to shareholder returns is how we've thought about it. You know, we have said, depending when the transactions occur, a portion of capital or proceeds could go into the ground to sort of enhance returns for next year. You know, if that happens later in the year, then practically there's no real ability to do that, you know, and then we'll think about how that influences the 2023 program. Okay. Thanks for taking my questions. Yeah. As a reminder, should you have a question, please press star then the number one. The next question today is gonna be a follow-up from Patrick O'Rourke with ATB Capital Markets. Please go ahead. Oh, hey, sorry guys. I wasn't trying to be back in the queue there. That was an accident. Since I'm on the line and, you know, just building on Jamie's question, just curious with the balance of the potential asset sale here in Canada, you know, you did half, is there any different strategy will we see? Do you anticipate that would be one sort of chunk, or do you sort of see multiple transactions going forward? Is this Patrick O'Rourke? Patrick, you know, we. From day one, we have said. The reason we announced it so long ago was even though we were obviously a single transaction would have been preferable from an execution perspective, we wanted to maintain the flexibility to do multiple deals if we thought we could extract better value out of that, and that was the decision we've made. What does the next one look like? You know, or what could the next one look like? I would say the next one, it could be multiple transactions. It's probably a little more natural when you actually look at the assets and the nature of those assets. You could see single buyers getting their head around it quite easily from an operating focus perspective. Yeah, we don't wanna be pinned down. You know, this is not liquidity drivers that are chasing this. You know, this is just continuing to focus the business and, you know, maximize the value when we execute. Like the remaining assets are tight. Like, we used to build businesses around these things. You know, low decline, you know, big footprint in Southeast Saskatchewan, good margin, good free cash flow profile. You know, in a different market, this would've been done a long time ago. They're high quality, and we wouldn't hear any pushback on that. It's just about the volatility in the marketplace and, you know, our goal to ensure we attract reasonable value for these things. They're free cash flow in a lot these days. Guess we'll see how it goes. Probably if you made me bet, I would have bet you a long time ago it was more likely to do multiple deals to get this Southeast Saskatchewan done. If you made me bet now with the remaining, it's more likely a single deal, but it could be different. Okay. Great. For the record, I've been dealing with the burden of mispronunciation of that name, basically my entire life. You know, many people have given up and just refer to me as patio lantern or patio furniture. Well, on that note, if we don't have any more questions, that's where we'll be leaving it. Operator, is there any more questions on the line? There are no further questions on the line at this moment. You can please proceed. Perfect. Well, we'll leave it there. Appreciate everyone's attention today and your interest, and I hope you enjoy the last bit of summer here. Looking forward to seeing everyone in the fall. Thank you.