Q2 2023 Enerplus Corporation Earnings Call
Sorry free cash flow being returned based on current market conditions.
Share repurchases will continue to comprise the majority of our cash returns.
Even argue that the intrinsic value of our business is not adequately reflected in our share price.
And therefore, the buybacks continues to be accretive to shareholder value.
A significant reduction in our share count over the last two years has meaningfully enhanced our per share growth.
Our production per share increased by 24% compared to the second quarter of 2021.
Over the same period, our net debt decreased by almost 80%.
Although we anticipate the majority of our cash returns will be via the share buyback. We have also increased our quarterly dividend by 9% effective with the September payment.
In summary, our outlook is strong.
We're on track to deliver another year of solid execution and well performance from our Bakken development program.
We have an attractive free cash flow profile.
Competitive return of capital strategy, and our financial position remains rock solid.
I'll leave it there and pass the call to wait for an operational update.
Thanks, Ian and good morning, everyone.
North Dakota production averaged approximately 69000 Boe per day in the quarter, which was up 3% compared to Q1.
We continue to run two drilling rigs in North Dakota, and drilled 17 gross operated wells during the quarter.
It was a very active quarter relative to completion and onstream activity by the end of the quarter. We brought 23 gross operated wells online, which will help set up a strong ramp in volumes in the back half of the year.
Notably we brought our first two pads on production and a little knife area. We.
We have a slide showing each past performance and our updated investor presentation.
At our Hey drop pad, we have six wells producing that have averaged over 100000 barrels of oil per well and 70 days on production.
But our bias pad, we have three wells online, which have produced about 80000 barrels of oil on average per well through 40 days on production.
These are great results and continue to support our view that our little knife inventory is very high quality.
Although we do expect variability as we further develop the little knife area. We are pleased to see strong early production results from these first two pads.
We continue to ground, our view of ultimate recovery with a unit by unit recovery factor model, while also seeking to optimize the early production performance of each well.
We also completed four re frac operations during the quarter. As previously noted these re frac candidates in our portfolio are producing wells, we acquired in 2021 in Dunn County, which were completed several years prior to that these wells in the units. They are in have relatively low recoveries and we think there is potential to increase.
These with a modern re stimulation.
Three of the four wells have been online for more than 30 days post re frac and have averaged a gross peak 30 day rate per well of over 500 barrels of oil per day and over 800 Boe per day on a three stream basis. This compares to a pre frac average rate of 30 to 40 barrels of oil per day.
These initial refract results are positive and in line with our expectations and while we monitor the longer term performance. We are evaluating plans for additional projects next year.
In terms of third quarter activity, we expect to bring 14% to 17 net operated wells on production in North Dakota. This activity combined with our second quarter completions is projected to drive liquids growth of approximately 10% in the third quarter compared to Q2.
Moving on to the cost environment overall, the market feels more balanced today than the tightness, we saw last year at this time.
<unk>, our well cost performance. This year has tracked expectations, our total well cost estimate coming into the year was $7 8 million for a two mile lateral up approximately 10% year over year.
We are effectively on pace to realize $7 $8 million or just under that on average for the year based on the current cost environment.
While we will stay away from making any definitive deflationary calls about 2024 at this point, we do think the market is in a more stable place today with potential tailwind into 2024.
We do continue to capture lower casing costs each quarter.
Turning to our non operated Marcellus position as expected we saw quarterly volumes declined sequentially by 14% to 154 million cubic feet per day, driven by the limited capital activity. This year as a reminder, we're allocating just 2% to 3% of our 2023 capital budget to them ourselves.
<unk>.
Lastly, I'll touch on our emissions performance this year as highlighted with the release of our ESG report in June we're driving quite meaningful reductions to our <unk> emissions intensity through flaring reductions and facility optimizations.
We expect to achieve a 30% reduction to our <unk> emissions intensity this year compared to last year or compared to 2021.
And believe that we can achieve our 2030 reduction target as early as next year, we'll provide.
A progress update along with an updated long term targets in due course.
With that I'll turn the call over to Jodi.
Thanks, Greg.
Let's start with our price realization in.
In the Bakken our realized oil price differential was <unk> 71 per barrel below double UTI in the quarter. This was modestly weaker than our prior estimate and reflected lower prices for crude oil delivered in two markets in both North Dakota, and the U S. Gulf Coast, a weak U S refining margins early in the quarter.
However, U S refining refinery utilization recovered later in the second quarter supported by a resilient domestic product demand.
Therefore on a full year basis, we expect our average Bakken oil price realization to be at par with WP Guy.
In the Marcellus our realized natural gas price differential of <unk> 68 per Mcf below Nymex largely in line with our expectations and we continue to expect our full year differential of <unk> 75 per Mcf below Nymex.
Our NGL realizations weakened in the second quarter, averaging just about $15 per barrel and include a significant propane component.
And Clark propane prices decreased considerably during the second quarter due to the strong U S. Domestic production growth that drove inventory levels well above the five year average.
Ultimately, we generated $197 million of adjusted funds flow in the quarter with.
Net capital spending of $181 million or free cash flow was $16 million.
Notwithstanding this lower free cash flow a return of capital in the second quarter was $67 million, including $55 million of share repurchases and a quarterly dividend of $12 million.
This resulted from accelerating a portion of our second half free cash flow into the first half of the year in order to level load our return of capital throughout the year.
However, as Ian mentioned, we have increased our return on capital for the year and plan to return at least 60% of our second half free cash flow, resulting in over 70% of free cash flow return during 2023 on an annual basis.
Current tax expense came in at $3 5 million in the second quarter and we've lowered our full year current tax expense guidance to 3% to 4% of adjusted funds flow before tax to reflect the lower commodity pricing environment. So far in 2023 compared to previous estimates.
Lastly, we narrowed our capital spending range by $10 million to $510 million to $550 million.
Previously it was $500 million to $550 million.
A significant factor influencing our capital range as our Bakken non op activity and we've seen a fairly material amount show up so far this year.
Ultimately with the non op activity levels. We are seeing we don't think it's likely that we will hit the bottom of our capital range at 500 million. So we lifted the bottom to $510 million.
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 should you have a question. Please press the star followed by the one on your Touchtone phone you will hear three tone prompt acknowledging your request question will be the questions will be taken in the order received should you wish to withdraw your request. Please.
Press the star followed by the two.
If you are using a speaker phone please lift the handset before pressing any cues one moment. Please for your first question.
Your first question comes from Jeffrey <unk> with <unk> and co. Please go ahead.
Good morning, everyone and thanks for taking my questions. My first one maybe first few or just from a really strong performance at <unk>. I know you all have spoken of wells in the program this year being highly competitive against what we've seen from you all in recent years from Fort Berthold, but just looking at the outperformance relative to the type well in your slide deck.
<unk> stands out so I was hoping to ask a few on this one on the type curve and performance specifically can you give us some context as to what was used to formulate that type wells shown there in the charts, whether that's mainly reflecting productivity that you've seen from offset operators through the years. There if theres any risk in your adjustments to think about and then in terms of the performance.
Are there any factors that you'd point to as key drivers behind the productivity that youre showing there that looks a sustained there as well which continue to produce and then I've got a follow up on the on our long term plan.
Thanks for the question Jeff.
Maybe I'll hand that over to Wade to sort of.
Do people some context on the.
We will take what it came from and other key drivers.
Yes. Good morning, Thanks for the question Jeff.
So that type curve that we've had out there.
Not long after the acquisition has been based on the offset producing wells that mostly are.
To the east of our acreage position so.
We certainly had a set of producing wells on the acreage that we purchased but most of those wells have been online for five plus years.
So those weren't really the anchor for the type curve, but they certainly had a bit of an influence. So again type curve based on analysis of a broad set of wells in that greater little knife area.
And certainly as an aggregate of those some wells, obviously produced a lot more than that some less than that.
So we didn't really feel like it was a heavily risked type curve, we thought it was fairly representative.
Yeah.
And even though the the early results from these.
Two patents look a lot stronger.
Time will tell what the ultimate shape of the of the well performance is what is clear though.
Is that the early production performance has been better than what we thought it would be better than say the average.
Offset well used in the type curve. So we're clearly quite encouraged by that.
The spacing that we've used in these first two pads.
As in the us at the upper end of our six to nine well range. Both of these pads are spaced in the 9% to 10, well range and so we're encouraged by the early performance.
<unk> of both the middle Bakken and three Forks wells that we've drilled in these units in terms of key drivers.
Ultimately, we would say that the rock properties are really great quality in the area of the two pads. We drilled we think that's fairly representative of that part of greater kind of northern half of our little knife.
<unk>.
In terms of the stimulation approach, there's nothing materially new or novel, there relative to what we've been doing this year in Fort Berthold.
Our completion design.
Continues to evolve.
Over over each year, but broadly speaking we applied our standard completion recipe standard kind of flowback recipe to these wells and as you said quite encouraged by the early performance.
Okay perfect. That's great color and then on the long term plan can you speak to what the five year outlook assumes on productivity out of little knife type wells shown on the deck is what's embedded in the outlook. There. If there are changes year to year and the guy to be mindful of and then as somewhat to a fall of a follow up to what you just mentioned.
Changes over time variability over time can you comment on your outlook for productivity as far as the near term program in the life and just really that running room of wells that could have this level of performance.
Yeah. So.
The under underpinnings of that five year plan.
You should think about those type curves that we've shown.
In the appendix of our decks.
As the basis for that long range plan.
Now we update those on a fairly continuous basis based on.
Well productivity from our own operations and from offset operators, but.
<unk> those type curves, which form the basis for that five year outlook.
In terms of little nice activity over the next five years, you should expect that it will continue to be an important part of our of our program. Each year, you've mentioned kind of competitiveness with Fort Berthold and your first question.
As you can see from our type curves and even from our recent performance. We think the acreage we have in little knife competes.
On par quite strongly with the best of our best acreage in Fort Berthold.
Okay, Great I appreciate the time.
Thank you. Your next question comes from Patrick O'rourke with <unk> capital. Please go ahead.
Hey, good morning, guys and congratulations on the dividend increase.
And a solid quarter overall, just kind of wanted to ask a couple of questions here. The first with respect to sort of your view on the optimal capital structure and leverage here, obviously net debt went up a little bit in the quarter, but I would infer from ONEOK.
70% payout ratio comes down over the next few quarters.
Youre under a quarter turn that to cash flow sort of where you're comfortable.
At current commodity prices, where do you think is optimal and then how does that play into the potential for further return of capital beyond 70% going forward I know you've talked about some of the puts and takes on that in the past.
Good morning, Patrick.
So let's talk the optimal capital structure.
I think as a general rule less that is better than more debt.
Having a clean balance sheet will be certainly.
Looking at the flexibility the Optionality.
And what it means to the resilience of the business I think a whole bunch of things pointed in that direction.
Last few years.
Sometimes people run hotter balance sheets when deaths.
Inextensible death.
That isn't free now so I think people are paying more attention to that.
So for us very comfortable continuing to pay down debt.
Comfortable going debt free.
You saw that last quarter that strong balance sheet gave us flexibility to actually use the balance sheet, a little bit too on a very temporary basis support return of capital plan.
Now, obviously, that's not a long term.
Plan, when we think about.
Our return of capital framework sustainability is the key word.
The keyword that underpins it.
So.
Yes.
We get to a position where we're debt free.
Could that Directionally put higher upward pressure on working capital plans.
Could possibly we wont have any debt to pay down as an example, as a competing.
Capital allocation choice, but the business is going to dictate.
How much capital we can sustainably returns have a sustainable business and continue to grow the business. So.
Hopefully that gives you.
The framework there.
We showed 60% originally because it was something that made sense to us where we can generate free cash flow and pay down debt.
As worked quite well through multiple cycles.
Obviously, if we end up in a more price environment and costs remained somewhat in check you could see upward pressure on those sales opportunities on payout.
Okay.
Terrific and maybe kind of moving over to the asset side of the equation. I think you guys did a great job on packing or what's going on at little night, maybe shifting over to those re fracs.
Curious with respect to those wells, how they would be currently booked and what sort of I know, it's early days, but how.
The re frac.
We're looking for from a reserve bookings perspective would it be an acceleration of EUR or would it be incremental.
And how that sort of.
<unk> in your five year plan as well.
Yes, I'll hand that to weigh.
To give you some color on how we're thinking about re fracs.
And potentially does re drilling some of these units.
Yes, thanks, Patrick in terms of reserves.
These are wells that we've re frac certainly were.
In our system as producing wells, but the reality is.
Okay.
They looked like they have fairly low recoveries relative to other wells and then even when you zoom out to the unit they are in.
That whole unit looks like it's pretty re frac going to recover quite a bit less than what our normal unit wood, hence the motivation to put some more capital in those units.
We're testing re fracs it may be in some units, we decided to put more wells on those units, but in terms of your reserve booking question.
Once we get a little bit more run time on these wells.
Any of the incremental recovery that we think we've achieved that will essentially be a new reserve bookings.
And then in terms of just a little bit more color today. The the early performance has been solid.
The wells have reasonable initial production rates.
We've been pleased to see the rates have hung in there at least over the first 30 to 60 days, it's really important though for us to monitor those for another three to four months and that will really determine how truly.
Economically competitive they will be.
Pretty high bar for them to compete with the economics of a new well.
Hi.
We still see the value in these as we have them in our operational plan each year provides some flexibility around how we how we.
Run our pressure pumping.
Our crews.
And execute our annual program.
Okay, great and.
I might be the only.
Person in the world that cares about these sorts of things but.
Given the wells, our PDP would they go into the bookings.
As extensions or as technical revisions on the positive side.
Hi.
I would I'm not sure I mean, you've got to actually add the capital that you've spent in.
And so yeah, we'd have to get back to you on a specific technical answer that question.
Okay No problem. Thank you very much.
Thank you. Your next question comes from Greg Pardy with RBC capital markets. Please go ahead.
Yes. Thanks, Thanks for the thanks for the rundown, maybe just staying on the operating side of things if we pivot over to Williams County, I'm just interested in what your.
What your level of activity and plans are there and then.
I guess the other question is just the suitability of three Milers.
Up in Williams any color there would be great. Thanks.
Good morning, good morning, Greg.
Where do you want to give Greg a bit of perspective on.
And we're thinking about the area.
Yes in terms of activity Greg.
We actually have recently completed and brought on stream five wells and a pad on the <unk>.
Eastern edge of our Williams County acreage.
So some of those are included in the Q2 counts and we'll begin with Q3 count. So we will be able to give you an update on the performance of that pad next quarter. That's.
That's the only operated on streams for the year planned in Williams County.
I think that ratio that youre seeing.
Kind of one pad for this year, you can think about that as potentially a proxy for what the next four or five years look like we see that eastern Williams area.
As if you actually dive into the type curves. We got noted in the appendix of our decks actually compete fairly well from an economic perspective with Fort Berthold Little knife. So I think you will continue to see us allocate some capital there.
One of the real important keys to that area in terms of unlocking more and more of the acreage as you move into kind of a central part of our acreage and then even to the western edge of our acreage there is likely going to be three mile.
We're fairly confident that we can execute that kind of.
Technical.
Program, what we've been working on is working through unit conversion.
Permitting to be able to change the previous original development in that area, which was mostly two mile development into three mile development. So stay tuned on on the progress we'll make there.
Okay, and then just to just to be clear then the five wells that you would've brought on in the eastern edge. So those are just all standard two milers.
That is correct.
Yes, thanks very much.
Youre welcome.
Thank you, ladies and gentlemen, as a reminder, so do you have a question. Please press the star followed by the one.
The next question comes from Jamie Kubik with CIBC. Please go ahead.
Yes, good morning, and thanks for taking my questions here, maybe just.
Staying on the asset side of things here just can you can you shed a bit of light on the declines seen in the Marcellus in the quarter I appreciate that.
The non operated asset but can you.
Just to add some color around.
What's happening there on the decline side.
Yeah Jamie.
I would say.
Per plan as per forecast.
Very.
Very little capital being spent on the asset.
Which is we're talking 2% to 3% of our total capital it's rounding to zero.
Very very few on streams coming on so we're seeing the decline profile off of.
The on streams came on late late in the year.
As we think about the.
Profile of the asset over the year.
Declines in start to moderate and sort of flattened out towards the end of the year.
When does it grow again gets to as per gas price I guess subtle level sort of could take the activity that the operators driving out there.
Don't know if there's any more color youre looking for.
As per our expectations now.
Okay No that's helpful.
And then you do talk about variability a little knife in the Bakken.
On the map and contours that you have in your slide deck, I would point to possibly weaker well results as you drill further south but.
Do you expect that that holds based on what you've seen so far just given the strength in the northern part of the acreage can you just talk about how you expect it to to various delineate for the parts of it.
Yes, we do want to provide a little more.
Color commentary there.
Yeah.
Most important geologic trend from north to south in little knives, Jamie is that in the northern half approximately it's fairly clear that the little knife or that the three forks reservoir interval is.
Not only quite productive, but also makes sense from an overall unit development perspective to include.
In in the in the original development, So I think youll see.
If you look at offset operators and you see our operations.
We'll include three forks locations in each of those units Redeveloped.
What's not as clear as you move to the far South end of the acreage is is it the optimal development approach to include three forks or not so that's the biggest technical question still out there in terms of actual well productivity.
As we as we track offset production right along the eastern edge of our <unk>.
Little knife acreage, we still see very strong middle Bakken, well productivity and three forks well productivity.
All the way through kind of a central.
A portion of our acreage.
Bit of well control that we have on our for ourselves still looks solid strong so.
I don't know that we have a model that says the middle Bakken will degrade in productivity, but we probably don't have as much well control at the far South end as we do at the North end.
Okay. That's good color and then maybe just on the capital allocation side of things that reduction or debt levels.
At the <unk>.
The range that they're at right now and then.
Greater than 70% of free cash being returned to shareholders. As you guys mentioned, but how are you thinking about M&A and potentially adding additional inventory into your business.
Can you just outline how youre thinking about that.
Yeah. Thanks for that question Jamie.
Yeah.
On some levels.
We're always thinking about it we've got capability and financial capacity that gives us a lot of flexibility to add to the portfolio.
When you look at the portfolio.
There is no real holes in it.
We've got ample inventory and everything we're thinking we're bringing in we think about what's going to compete with what we've already captured so the bar is probably higher than it has been in other years.
Relative to that.
Question.
So so for us.
Anything in North Dakota, we pay attention to.
At the core.
We're looking for accretive activity that is going to bolster our NAV.
Build out that business and make money for people so.
How do we think about that in the context of this moment in time in the market.
Yes, there hasn't been a lot of deals out in North Dakota, there have been some.
We would characterize as a lot of those as being relatively competitive.
People that.
Danone Bakken typically want to own more of it or want to get in there.
Place, where you can get some really good low risk black oil.
And so.
I guess.
So leave it with a final comment.
The bar is higher than it's been before for us to do activity, but we're certainly in a good position. If we saw something creative that can make our business better and make money for people.
Okay. Thank you for that that's all for me.
Thank you at this time there are no further questions. Please proceed with your closing remarks.
Great well, we appreciate everyone calling in.
Last couple of weeks in the summer.
Have a great rest of your weekend.
Maybe we'll see in the hall thanks, everyone.
This concludes your conference call for today, you May now disconnect your lines. Thank you.
Hum.
[music].
Okay.