Q3 2022 Enerplus Corp Earnings Call
And our forward program.
These results are encouraging and they are driving very strong 2022 performance.
In terms of remaining completions activity in North Dakota for the year, we anticipate bringing five operated wells online in the fourth quarter.
Along with some non operated activity.
Moving on to inflation, we have continued to experience upward cost pressure, primarily in our capital program.
Previously, we had been forecasting $6 5 million for total well costs in North Dakota in 2022.
Inclusive of drilling completions facilities, and the first lift system or.
Our latest projection is that we will average $6 9 million per well this year.
As we look ahead into 2023, we expect to see another 10% increase to our well costs with steel.
Followed by sand and other consumables, and then labor and other service costs being the most significant items leading to higher anticipated costs.
Lastly, turning to our non operated Marcellus position, we participated in 10 wells, which were brought on production during the quarter with an average working interest of 13%.
Well performance continues to be solid with peak consecutive 30 day production rates of over 30 million cubic feet per day per well.
We expect an active fourth quarter in terms of wells coming online in our Marcellus position, which is projected to drive natural gas production growth for us in the fourth quarter.
I'll leave it there and now pass the call to Jodi.
Thanks, Greg.
I'll start with our realized prices during the third quarter.
Bakken, we realized sales price premium to <unk> of $2 and 41 per barrel.
<unk> continues to be strongly bed and the premium pricing as supported by significant excess pipeline capacity in the region and strong prices for crude oil to the U S Gulf Coast.
The Bakken oil prices continuing to trade at a premium to <unk>, we have strengthened our 2022.
When oil price differential guidance to $1.25 per barrel above <unk>.
Financial gas our realized Marcellus price was <unk> 99 per Mcf below Nymex Macquarie.
And we are still on track to meet our 2020 guidance of 75 per Mcf below Nymex as we transition into cooler winter weather during the fourth quarter.
Operating costs were $10 47 per BOE in the third quarter, an increase from the prior quarter largely attributable to higher planned well service activity and an increased liquids production weighting in the third quarter.
We anticipate operating costs will trend lower in the fourth quarter, partly as a result of the recently closed Canadian asset divestment, which had higher operating cost than our corporate average as.
As a result, we have left our full year guidance unchanged at $10.
Bo.
We recorded current tax expense of just under $8 million in the third quarter and based on the current commodity price environment. We continue to expect 2020 to cash taxes of 2% to 3% of our adjusted funds flow before tax.
Our third quarter adjusted net income was $208 million and adjusted funds flow was $356 million.
With capital spending of $114 million in the quarter, we generated free cash flow of $241 million, which we allocated towards debt and returning capital to shareholders.
We reduced net debt by 28% quarter over quarter and ended September with net debt of $391 million.
We returned $123 million to shareholders in the third quarter, including $11 5 million in dividends and $112 million or 779 million shares repurchased.
We plan to continue buying back shares under our current framework of at least 60% of free cash flow and have a robust return of capital plan for the remainder of this year.
In total from January through early November this year, we have returned $327 million through share repurchases and dividends, which includes our announced December dividend.
Earlier this week, we announced the sale of our remaining Canadian assets, which is expected to close in December .
This was part of our previously announced plans to continue to focus the portfolio on our strategic position in the Bakken.
The proceeds from the divestment will accelerate the deleveraging of our balance sheet in 2023, giving us additional flexibility to support our plans to return at least 60% of free cash flow through dividends and share buybacks.
Lastly, during the third quarter, we entered into new 2023 natural gas hedges to support the strong free cash flow profile of our Marcellus asset.
And Costless winter colors at approximately $6 and 20% by $18 per Mcf and Costless summer colors at approximately $4 by $7 per Mcf.
I'll leave it there and we'll turn the call over to the operator and open it up for questions.
Thank you ladies and gentlemen, we will now begin the question and answer session.
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One moment. Please for your first question.
Your first question comes from Greg Pardy of RBC capital markets. Please go ahead.
Yes, thanks, good morning, and thanks for the rundown.
Sure.
The questions I had are mostly on the financial side I mean, the operations with great just given the strength of the balance sheet and the pace at which you're.
Through deleveraging what would the appetite be for a substantial issuer bid.
Either later this year or next year.
Yes, Thanks, Greg it's Jody.
We've stated previously that that's it.
Potential issuer bid is opportunity a tool in the toolkit.
And we would continue to consider this right now the normal course issuer bid actually gives us a lot of flexibility to buyback our shares.
And as we mentioned we're committed to returning at least 60% of our free cash flow through 2023, So I think.
We won't comment on potential timing, but it's definitely a tool that we can use.
Okay. Thanks for that and then the second question is just more technical.
So understand the cash tax position next year. This year in terms of maybe as a percentage of pretax <unk> for next year are we still is youre thinking that youre still sort of in a 11, 12%.
The range give or take a true cash tax in 'twenty three.
So I'd say that might be a little bit high at this point I am just basing that on how commodity prices are shaking out this year as well as current strip prices. So.
I think if you if you use strip pricing at this point, it's probably in that.
Nine 8% to 9% range for next year.
Okay, Great and last question for me you mentioned, what the just in basin differentials for the Ti in the Bakken in the quarter, where are they currently four five bucks.
No that I guess, maybe that might be clearbrook and you have to take a couple of bucks off that for transport. So I would say its probably two plus two to $3 in the basin right now.
Okay terrific, thanks very much.
Thank you thank.
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 Jeffrey Lamborn <unk> of Tudor Pickering. Please go ahead.
Good morning, everyone. Thanks for taking my questions. My first one is just on the solid Q3, all delivered particularly on the productivity front and I apologize I apologize if I missed this earlier in the call, but just looking at how strong quarter to quarter liquids growth was in comparison to your prior expectations. I was wondering if you could talk a bit about the components there both in <unk>.
Terms of the performance and timing and if there are any comments you can share on how youre seeing the program evolved into next year, whether in terms of productivity might compare.
In terms of activity might be allocated to where you've been active recently versus developing other areas of your core.
Yes. Thanks for the question Geoffrey This is Wade.
The key drivers for the Q3 liquids and total volume performance really the biggest driver has been recent well performance.
So we highlighted this last quarter, but.
Fairly large tranche of wells that came online in the second quarter continued to perform strongly into Q3 and throughout Q3.
We brought on a few new wells in Q3 that also are performing strongly so that's the biggest driver.
We also saw really good uptime performance in our base business, so not helped us.
Volumes in the quarter as well.
In terms of thinking about hurdle.
That would translate into next year I'll comment on two components. One would just be overall performance and then the mix of wells. So.
As we noted last quarter. We noted again. This morning. These wells have exceeded our expectations and on average these pads that we brought online a month.
In the second and third quarter this year have been even higher quality than our average.
So we expected them to be strong, but maybe even exceeded our expectations.
We're not baking that into our forward type curves are forward performance.
We're going to continue to use the same kind of optimization methods on.
The upcoming year's program that we did on those so we.
We feel like we still have an opportunity to continue to improve at least kind of short term.
Initial production performance.
But again, we haven't baked that in for next year, we Wouldnt really guide people to do that.
Okay.
In terms of next year's program.
It is.
An important year for us and we.
We will be shifting to a more diverse mix of.
Locations that we'll be bringing online.
So next year, we'll have several paths from the Dunn County area, but still have a core of the program in our.
Core Fort Berthold program, and then you may even see a spring.
The wells on.
In the.
Eastern side of Williams County, So next year will be a bit more.
Diverse than this year, but we still feel like it'll be a strong program.
And then maybe just let me come back to this optimization question.
We really have spent a lot of time.
Subsurface and production operations teams looking at how can we optimize every well that we bring on and so we've gotten a very customized approach to every pad in every well in terms of tweaks to the completion design.
Lending zone spacing particular, particularly paying attention to existing offset producers that we operate or that someone else operates around us and we think that's having a positive impact on our well performance.
Great that's fantastic detail. Thanks for that and then as my follow up also as we think about next year just given the moving pieces on the volume side related to the success you are filing on asset sales. How are you thinking about volumes overall next year relative to this year on a pro forma basis, and then given the dynamic service inflation.
<unk> environment that we all know about as you work with service providers on locking in contracts and pricing for next year any refreshed thoughts on how that will impact year to year budget expectations at this point.
Hey, Jeff It's drew I might just jump in there on the production question.
No change to how we're thinking about the growth of 3% to 5% growth of our liquid but.
But we do think about that on a divestment adjusted basis. So you really need to back off the well call. It 6000, Boe's a day that we sold this year and then reset expectations. So.
Directionally, it's going to look very similar to that 3% to 5% growth we talked about but yes. There is more of a divestment adjusted number now.
And capital.
Don't take that waste blanking on the capital question what was that again.
Yes, just as you work with service providers on locking in contracts and pricing just wanted to see if there is any new thoughts to expect on the budget year to year next year. If we should wait till February and year end earnings to get more color on that.
Certainly we will give you more color certainly the start of the year, but we can comment a little bit on what we're seeing today as we noted in our prepared comments, we do anticipate seeing capital costs.
Drove driven up a bit next year, maybe on the order of 10% relative to where it will average on well costs for 2022.
And I'll make just a couple of component comments.
In terms of of securing the critical services to deliver next year's program, we feel like we're already very well positioned.
Two rigs that will run next year, we've actually had on contract since 2021, and we've got those priced.
Given the pricing environment that we were in at that point now this year, we've added a little bit of labor costs to those contracts just to reflect current conditions, but we will roll into 2023 with <unk>.
Two well functioning rigs.
We feel like a pretty attractive pricing.
The Frac crew that will use next year is already secured its the same.
Company vendor that we've used since 2021 and the contract.
Is one that we signed in late 'twenty, one again, we've adjusted it up a bit to reflect inflationary conditions, but those two key components we feel.
Very good about in terms of both having the services secure but also good about the performance of those crews.
Two other components on the one is steel steel has been one of the bigger drivers of the inflation, we saw in our well costs. This year.
It likely will be the key component for next year, we benefited a lot in 2022 by having essentially pre bought over half of the year's casing program at the end of 2021.
And.
Is that does that purchase kind of was used up we then it almost a quarter by quarter mode. Given the way steel prices have continued to escalate.
So that's where we're at today, we'll just see what happens to steel prices next year in terms of will they moderate and even rollover.
But certainly a key component of that 10% increase for next year is as big baked in because of what we think we're seeing on the steel side and then on sand.
Got all of the sand we need for next year's secured.
It'll be a mix of Av.
In basin sand.
Sand transported in but we feel like we're well positioned for that as well.
Perfect. That's exactly I was looking for thank you all.
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 Travis Wood National Bank Financial Please go ahead.
Hi, yes, thanks for taking my question here.
First on the operations side, I think you've done a pretty good job of laying out.
Why youre seeing kind of <unk>.
Proved results sequentially.
But if you think back to the Bakken data that you guys highlighted back I think last spring.
Are you doing anything different.
Since then and.
You showcased a lot of.
A big improvement in terms of the completions and drilling side of the equation.
Over that five year window should we expect that type of scale compression and cost advantage on our on kind of a per unit basis.
<unk>.
Into 'twenty two numbers and then ideally into 'twenty three in terms of how you are continuing to push.
Technology and different completions and drilling design into into 'twenty three as well.
Yes. Thanks for the question Travis in terms of what what might be different relative to the investor day on our approach to development.
I would say, it's just been a continual evolution.
From that point.
As we've noted this year in.
In addition to drilling and bringing online really high quality pads.
Strong areas of our core position.
We have continued to perfect or optimize the.
Individual pad and well development.
Figuration, so what I mean by that is taking a look at.
The existing producing wells in the pad or in this unit that we are developing because most of the units. We're developing do have some existing wells already there and then of course these arent islands wells offsetting these these units either our own or other operators. So we've taken that all into account with a fairly well calibrated subsurface model.
Around original oil and gas in place.
And then design, how many new wells, we want to put in that unit, how far away from each of the producing wells they should be how far space from each other they should be.
<unk> are optimal for the middle Bakken and the three Forks and then we actually vary the stimulation design for each of those wells based on those conditions.
And so that we feel like has.
Really done a good job of avoiding any impacts from depletion.
Depletion.
That we would see if we just went with a more standard design.
And then we've also continued to optimize how we flow the wells back and the timing of the first artificial lift and how we how we designed that and so we think all of that is contributing.
Certainly a bit to the well performance that we've been seeing we will continue to do that as we move into next year's program and beyond we would anticipate that we'll be able to continue to find some optimization. So I think that the the new dynamic for 2023 and beyond as we will be bringing wells online across a much.
Bigger.
Part of the Williston Basin.
Our past several years history has been almost exclusively in the Fort Berthold core position in next year as I noted, we will have some wells in Dunn County, and overtime, we will have some more in Williams County.
In terms of the technology application.
I would say those who've bet that there won't be any new technology efficiencies have been wrong for the last several years, so I'm pretty confident we'll keep finding those I think the things. We're most excited about today.
Sure.
Leveraging the ESG power management package, we have on one of our rigs where we've upgraded the engines they've got a battery pack and we're able to actually displace a fair amount of our diesel costs by being able to leverage CMG as a fuel source in those operations I think youll see that kind of activity continue for us will expand.
<unk> into more and more of our operations, where we can I think the use of this in basin sand is going to be helpful from a logistics and even potentially technology perspective as well.
Okay. Thanks, that's great color, thanks for going over that again.
And then second question for Jody here.
You commented on kind of balancing and CIB with the SIV.
If you using the language of kind of at least 60% if we start to see that expand.
Through 'twenty three is there a case that.
Variable dividends or special dividends come into play given.
How you guys think of the value in the stock and kind of intrinsic value on the buyback side.
Yeah. Thanks Travis.
For sure we at this point in time, we continue to view buybacks or buybacks.
As the best capital allocation choice for us at today, given the discount we see between our shares and our intrinsic value.
Okay.
We remain open minded to alternatives for returning capital and if the stock keeps working now maybe there comes a point or we see less of a disconnect with its intrinsic value and we would be open minded to using other mechanisms such as variable or specialist that you mentioned.
Thank you very much that's all.
Thank you.
The next question comes from Jamie Kubik of CIBC. Please go ahead.
Yes, good morning, and thanks for taking my question, maybe just to continue on to the.
Questions around the Bakken I mean, historically, there's been quite.
Quite a bit of shapes.
<unk> and <unk> plus to start the year versus the exit.
Are any of the well designs in the areas that youre drilling going to affect how the shape of 23 should look or should we just accept it.
Expect it to look similar to what we've seen in the past.
It'll be similar Jamie.
Yes, just the nature of it there's a little bit of a frac window there.
This window will be.
Two months or so.
And rule will start pumping towards the end of January and into February so there'll be a dip.
Okay, and then maybe just in the total return.
As shareholders.
Dividend obviously.
On a fairly small amount in that in that bucket.
How should we think about.
That component of the return bucket versus.
The buybacks I know George you just commented on that a little bit, but can you talk a little bit more about how you are thinking about the dividend.
Okay.
Yes, I guess I guess a few comments.
Yeah.
A stable growing.
Fox solid.
Dividend.
It is an important part of the business.
I don't think it's the most important part of the oil companies kept working profile. These days you can you can you can see that because we wanted to be defensible.
In volatile commodity times.
So.
Think about growth I think about that continuing.
Obviously with the cash flows are dealing with right now we have a lot more going on and as Jodi said.
I guess, we've approached it a couple of ways.
We'll be responsive to the market and we'll pay attention to market conditions that will pay attention to where if any of these differential structures get capitalized to differently right. Now, we don't really see that and so we're anchoring it on mathematics, and we see a really powerful opportunity in our stock.
If we get the compounding effect of that.
Over time.
Will we evolve it we might and again its been depend upon evaluation of valuation of the stock.
I think <unk>.
People are thinking about these things right now again, we don't see any discernible trends other.
Then it seems like we're being rewarded for this behavior and we see a lot of value under any of the stock right now so we're going to continue.
Questions around <unk>.
Clearly that's sitting on the shelf ready to use if we need to use it.
And we will pay attention to us.
Okay. That's good color. Thank you I'll turn it back.
Thank you.
There are no further questions at this time please continue.
Alright. Thank you everyone. Appreciate your time today very busy reporting day busy reporting week.
And enjoys the weekend. Thank you.
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.
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