Enerplus Corporation (NYSE:ERF) Q4 2022 Earnings Call Transcript

Enerplus Corporation (NYSE:ERF) Q4 2022 Earnings Call Transcript February 24, 2023

Operator: Good day, ladies and gentlemen, and welcome to the Enerplus’ 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. This call is being recorded on Friday, February 24, 2023. I would now like to turn the conference over to Drew Mair. Please go ahead.

Drew Mair: 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 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 and our financial figures are in U.S. dollars unless otherwise specified. I am 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.

Ian Dundas: 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. And while we were clearly impacted by cost inflation, strong planning, procurement and execution sheltered us from the worst effects of it, and ultimately, we were able to operate within our original 2022 capital spending guidance range. The combination of production of performance, cost control and 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, which 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 reserves additions, and 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 on-stream 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% to 5% liquids production growth. Our capital program will be very straightforward with spending of $500 million to $550 million, 95% of which will be allocated to the Bakken. Our liquids production guidance is 57,000 to 61,000 barrels per day. This is in line with our 3% to 5% growth rate, divestment 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 to 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 to $550 million, 3% to 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 and turn the call over to Wade for an operational update.

Wade Hutchings: 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 nine to 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 to 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 stimulating.

Turning to well costs. While we are continuing to drive improvements to our drilling and completion cycle times, we expect well cost 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 and lastly, higher well service activity driven by several factors. Lastly, we’ve updated our drilling inventory estimates for January 01, 2023, which benefits from the continued sub-service 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.

Jodine Jenson Labrie: 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. The 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 funds flow.

Our debt reduction during the quarter was achieved through proceeds from our Canadian asset sales 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 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 of 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.

For 2023, operating expense guidance is $10.75 per BOE to $11.75 per BOE. Our cash tax guidance in 2023 is 5% to 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.

Q&A Session

Operator: Thank you. Ladies and gentlemen, we will now begin the question-and-answer session. Your first question comes from Greg Pardy of RBC Capital Markets. Please go ahead.

Greg Pardy: Yes. 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 pretty limited runway on the NCIB, what’s the appetite for €“ to do an SIB here in the near-term?

Ian Dundas: Thanks, Greg. Jodi, do you want to handle that?

Jodine Jenson Labrie: Yes. Sounds good. Good morning, Greg.

Greg Pardy: Good morning.

Jodine Jenson Labrie: We believe today the NCIB gives us lots of flexibility to buy back shares. And as I mentioned, we’re able to renew it again in August for another 10%. But we do view the SIB as a tool that we can utilize if in the future we see opportunity or strategically to buy back even larger portion of our shares.

Greg Pardy: Okay. And maybe just a follow-up then is just 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 different companies pursuing different strategies, but in some cases, there’s net debt floors and the net debt floors then are unlocking. Payout ratio is closer to maybe 80% to 100% or so. Given the balance sheet is what got $250 million in net debt, I mean, you’re going to be debt-free here pretty soon. Could at some point, we expect that 60% to increase as a payout?

Ian Dundas: It could. Yes, we’ve chosen the very specific language of at least 60% to sort of deal with that issue. Greg, as we think about it now, and again, I use the word sustainably a lot. We’re looking for a sustainable plan that makes sense in the fullness of time. And so today, that 60% number allows us to buy what we think is a return of a meaningful amount of capital. We think that yield, if you will, is competitive, and it allows us to continue to pay down debt. So pick a price deck. If you like the strip this year, there’s a pretty steep backwardation that sits in there, right? Gas has come off. And so we would model under strip getting debt free towards the end of the year. So as I think about it from a gating perspective, really comfortable getting to zero debt or zero net debt.

And so this plan at that 60% kind of level, that all sort of comes together this year. If we get to that level, because there could be intervening events, I guess acquisition activity or something along those lines is a good example of that. But if we get to that level, then I think you’ve got a pretty strong likelihood that there could be opportunity for returns to increase at that point. There’ll be €“ I think a lot of people €“ if pricing stays high, I think that the industry is going to be in a state where many companies are going to be in a zero debt position. And I think then maybe the really interesting thing will be the optionality around all of that because there’s going to be lots of opportunities to a lot of interesting things, increasing returns.

If the shares are reporting really well, maybe there’s a bit of cash that gets build. I don’t know how all that plays out at this point. But I think this is the year where we’re going to be approaching that towards the end of the year and come back to your original question, could returns go up? Yes, clearly, they could go up.

Greg Pardy: Okay. Understood. Thanks for that.

Operator: Thank you. The next question comes from Patrick O’Rourke of ATB Capital. Please go ahead.

Patrick O’Rourke: Good morning, guys. I was going to ask about the dividend and the parameters for growth here, but I actually just want to 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 sort of thoughtfully run through what your ideal targets would be or what the parameters for that are. But 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?

Ian Dundas: Good morning, Patrick. So acquisition activity, 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 the shareholders and make the business better and make the portfolio better, pretty generic statement, but it’s true. 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 that’s 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. So I guess maybe the bar is reasonably high to do something. But we maintain a lens into the market.

To your question of bid-ask spreads and those sorts of things, volatility is never a friend to successful transactions. And so 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. So oil, it’s actually been sort of stable-ish for a little while now. And 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 testing the waters, a few processes that get out there. So we really haven’t seen a heck of a lot of stuff come together, but I would guess bid-ask starts to narrow.

One of the things that will be very interesting is if oil assets start to trade in the context of the strip. I mean, with that backwardation that 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. So I would guess we’re going to start to see some oil and gas €“ some oil stuff start to happen over the course of the year. Gas is a bit different now. So you saw €“ it was tough I think for buyers to get gas deals done in the last couple of years €“ last year and a half with prices so strong. Now they’ve taken it in the year, and I think there’s a lot more interest on the buy side, if you want to do something. Will sellers be interested in doing that?

I don’t know. So again, back to the volatility question, I think gas €“ it’s going to be interesting to see if gas trades when the prompt is so low. So I don’t know if that helps you out though.

Patrick O’Rourke: No, that’s very helpful. And then I’ll just circle back to the original question I was going to pose here. 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 wondering with respect to the dividend, how you think about sort of the cadence and sizing of growth. You’ve got sort of 3% to 5% target liquids growth. You’re buying back 10% of your float. Like how would you think about keeping the dividend rightsized in this environment?

Ian Dundas: The dividend is important €“ growing stable base dividend is important. When we step back and think about the mathematics of our business, that share buyback is €“ the math is compelling. It compounds and we see and you saw it last year, we really leaned into it, and we think that is a really good decision for our shareholders. Dividend in these kind of conditions, 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, where pricing signals, I guess, broadly, we don’t see the dividend is offering a superior advantage to our shareholders now.

And so 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 will be responsive to the market. But at this moment, we see a modest growing dividend as a part of this capital structure and the return proposition, but it doesn’t dominate our thinking based on where we see the valuation of the stock.

Patrick O’Rourke: Thanks very much, Ian.

Ian Dundas: Thanks Patrick.

Operator: Thank you. The next question comes from Jamie Kubik of CIBC. Please go ahead.

Jamie Kubik: Yes, 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? And I guess second to that is how does your guidance incorporate the improved performance that you’ve enjoyed? Thanks.

Ian Dundas: Wade, do you want to take that?

Wade Hutchings: Yes. Thanks for the question, Jamie. 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 and the industry were seeing. But we did drive an improvement in our drilling cycle times and in the efficiency of our frac stimulation program, and we continue to optimize the facility design as we weave in additional emissions controls and optimize those facilities for the kind of development we’re doing. So 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. So I would say that the guide for 2023, it has a fairly basic assumption around 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. But it is offset by a few additional things around differences in €“ small differences in scope and continued anticipated efficiency gains. So 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 really good well performance beyond and what we expected from the pads we brought on last year. As we’ve noted, those pads on average were really high quality relative to the average pads from previous years. But beyond that, we saw an even better performance than we thought. This year’s program looks really solid. I would say it looks a lot more like maybe that previous three or four year average of well quality. But 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. And so again, we always have a bit of optimism around can we continue to improve the overall capital efficiency of the program that we’re executing.

Jamie Kubik: Okay. That answers that. Thank you very much.

Wade Hutchings: Welcome.

Operator: Thank you. There are no further questions at this time. Please continue with closing remarks.

Drew Mair: Looks like we might have one more question, operator.

Operator: I apologize. The next question is a follow-up from Greg Pardy. Please go ahead.

Greg Pardy: Yes. Sorry, I did think I’d just sneak that one in. Wade, you talked about just a small number of refracs. And I’m just curious, what do those costs? How many of you got planned and then 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?

Wade Hutchings: Yes. Thanks for the question, Greg. Let me zoom out for a minute. 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 were stimulated many years ago, some as old as 10 years ago. And so in our view, there are places that are understimulated. And so it looks like there’s additional resource that could be recovered from those producing wells. So we’re going to test that concept this year. Right now, we are planning on two pads of recompletions. 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 the stimulation itself is not too different than a stimulation of a new well.

But there are a few additional costs required to get the well prepped, get it cleaned out, get it ready to be stimulated. So they do cost a little bit more than just the completion phase. But 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. And so 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.

Greg Pardy: Okay. Thanks for that. And then you’ll update us over the course of the year maybe on progress?

Wade Hutchings: Certainly.

Greg Pardy: Okay. Thanks very much.

Wade Hutchings: Yes. I wouldn’t expect that to be €“ yes, I wouldn’t expect it to be immediate. The programs spread out kind of mid to end of the year. But yes, you’d get an update.

Greg Pardy: Okay. Understood. Thanks again.

Operator: Thank you. There are no further questions at this time. Please continue with closing remarks.

Ian Dundas: All right. So we’ll call it there. I appreciate everyone’s time on this busy reporting week. If you’re on the western part of the continent, we share your pain. And if you’re on the east, enjoy the warmth, because this is at you hopefully. Everyone, have a great weekend. Thank you very much.

Operator: 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.