Enerplus Corporation (NYSE:ERF) Q3 2023 Earnings Call Transcript

Enerplus Corporation (NYSE:ERF) Q3 2023 Earnings Call Transcript November 3, 2023

Operator: 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. [Operator Instructions]. Also note that this call is being recorded on Friday, November 3, 2023. And now I’d like to turn the conference over to Drew Mair. Please go ahead, sir.

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 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.

Ian Dundas: 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 barrels 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% to 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 liquids volumes of 60,500 to 64,500 barrels 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 to $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.

Wade Hutchings: 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 tight 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 two mile 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 to final fracking 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.

And 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 declined sequentially by 6% to 145 million cubic feet 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 cubic feet of natural gas produced by 2026. I’ll leave it there, and turn the call over to Jodi.

Jodine Jenson Labrie: Thanks, Wade. I’ll start with our price realizations. In the Bakken, our realized oil price differential was $0.20 per barrel 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 the 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 base in production and lower seasonal refinery demand resulting from maintenance outages.

As a result, we are revising our annual 2023 expected Bakken crude oil price differentials to $0.25 per barrel 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 to $11 per BOE, from $10.75 to $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.

Operator: Thank you. [Operator Instructions]. And your first question will be from Greg Pardy at RBC. Please go ahead.

Justin Ho: Hi, it’s Justin Ho on for Greg Pardy. So thanks for the thorough overview 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?

See also 20 Largest Exporters of Blueberries in the World and Dogs of the S&P 500 Strategy.

Q&A Session

Ian Dundas: Good morning, Justin. Wade, do you want to take that, please?

Wade Hutchings: Yes, happy to. Good morning, Justin. 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 directionally point you to activity next year in terms of on-streams will be balanced between Fort Berthold and Little Knife. And so you’d expect to see a program that looks quite a bit like this year’s, next year.

Justin Ho: 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 cost next year. Could you provide more color on what’s driving that? And if there’s any embedded inflation in that expectation?

Wade Hutchings: Yes, happy to. So we think we will end this year just under our $7.8 million total well cost 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, 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 cost that we’ll pay for the program are already set.

Now the things that will swing for next year are still OCTG and diesel, that would be the two biggest ones. So 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 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.

Justin Ho: That’s great. Many thanks.

Operator: Thank you. Next question will be from Patrick O’Rourke at ATB Capital Markets. Please go ahead.

Patrick O’Rourke: Hey, good morning guys. So solid results year-to-date, and obviously, you took up 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 barrel a day swing between the lower and the upper end of the guide you provided for fourth quarter. So just wondering if you can unpack a little bit about what those sort of swing factors will be that will kind of land you — where you do in that range?

Ian Dundas: Hey, good morning, Patrick. Yes, I mean I think you’re seeing the granularity of a quarter there, right? We don’t factor for — factor in for storms of the century, but we factor and account for weather that can move things around quite a bit. We’re done with the operated program. There’s a little bit of non-op onstream that are going to be coming into the mix as well. And maybe my last comment, 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?

Wade Hutchings: Yes, I think you’ve hit on it, Ian. 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 were — continue to be very robust. But any time you have new pads coming online, and they’ve only been online for 15 to 45 days. There’s still a fairly broad range of uncertainty around how those will perform. We anticipate that each of those wells will have, sometime in the first few months, get — will 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, on a well-by-well basis, how much production you get in that ensuing quarter.

Patrick O’Rourke: Okay. Maybe then just shifting gears in terms of return on capital philosophy here. Execution on the NCIB has been very strong. We saw the October filing last night, again, impressive stuff. Just wondering, with respect to the dividend, the yield is a little bit lower than some of the peers today. Your payout ratio and what we’re modeling for 2024 is also much lower when you consider the capital program, and that sort of liability or obligation for that dividend. So just wondering about the approach with respect to scaling of that element of the return of 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.

Ian Dundas: With the focus specifically on the dividend, Patrick? When you said our payouts are low, presuming you’re talking about the simple payout on the dividend.

Patrick O’Rourke: When I look at the capital program, plus the dividend that we’re anticipating, and understanding that the swing factor in terms of return of capital is that buyback, but just wondering how aggressive you feel you could be with dividend growth here.

Ian Dundas: We’ll be balanced in dividend growth. Yes, I mean we’re — I guess, our dividend is lower than some. Certainly, our base is a little bit lower. We don’t have a variable construct or a special. And this will sound familiar to you, 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 being capitalized in a particular different way. And so we’re really comfortable with these kind of valuations leaning into the buyback. And so we’re interested in the dividend going up, and it will sort of go up in the normal course as we reduce the share count. And as you — though we raised it last quarter — so we’ll keep looking at that.

But right now, in the context of how we see the market, we think that share buyback is really pretty attractive. I think we see some of that on the stock performance. For us, that compounding effect of buying stock at these kind of levels is — it feels like a money machine that’s going to pay dividends as it work over time. And I think you probably have noticed, we’ve sort of been increasing as we continue to de-lever, increasing that return to shareholders. Now, Jodi indicated, we’re thinking next year looks like approximately 70% return on free cash flow. So I think it’s all moving in a pretty good direction.

Patrick O’Rourke: Okay, thank you very much.

Ian Dundas: Thanks, Patrick.

Operator: Thank you. [Operator Instructions] And your next question will be from Jamie Kubik at CIBC. Please go ahead.

James Kubik: Yes, 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 it, 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?

Ian Dundas: And you’re looking specifically to our portfolio, you’re not talking sort of statewide stuff?

James Kubik: Statewide stuff looks like it’s — yes, I mean, with respect to the 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?

Ian Dundas: Sure. Yes. I guess, Wade, do you want to take both those? But they sort of work in concert.

Wade Hutchings: Yes, happy to. So I would say, in our portfolio, 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 at Little Knife have a little bit higher GOR. So 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. As you have followed our 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 have a little bit higher GOR than average and enhance 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 actually see that come back a little bit closer to our historic average on oil cut for Q4.

James Kubik: That’s great color. That’s all from me. Thanks.

Operator: Thank you. And at this time, we have no other questions registered. Please proceed.

Ian Dundas: All right. Well, we’ll leave it there. I appreciate everyone’s attention. It’s a very busy reporting day. And have a nice, safe weekend. Thank you.

Operator: Thank you, sir. Ladies and gentlemen, this does indeed conclude your conference call for today. Once again, thank you for attending. And at this time, we do ask that you please disconnect your lines.