Q2 2019 Earnings Call
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Afrikaans decision maker, while you're looking for please.
Morning.
We'd like to drain too.
Enerplus Corporation earnings call.
Thank you may get your first name.
First name Rachel.
Last name summit.
And your company.
Our euro A.I.E.R.A.
Well I had in place you win.
The conference is now being recorded productivity from the Marcellus with volumes up 14% from the prior quarter.
As a result of this operational momentum, we're increasing our total production guidance and tightening the range on our liquids guidance importantly were maintaining our capital discipline.
Our Titan capital budget guidance is inside of our original range.
Additionally, we're forecasting lower unit operating and general expenses and stronger Bakken differentials with which are supporting the resiliency of our plan.
So to recap our outlook this year.
Our plan is expected to generate to 14% liquids production per share growth.
Double digit corporate level returns.
Return of capital to shareholders with over $115 million returned year to date.
And plans to continue buying back stock and we're maintaining our peer leading balance sheet.
We believe this is a highly competitive outlook and we continue to see compelling value in our equity at current levels, which we see trading at or near the discounted cash flow value of our producing reserves and little if any value ascribed to our high quality Bakken inventory.
As a result, we have been actively buying back stock this year and continue to see this as an attractive capital allocation decision based on current trading levels.
Our board has approved the repurchase of the full 7% authorized under our existing normal course, issuer bid, which translates into just under an additional 9 million shares.
Once completed this would represent approximately 24 million shares repurchased since last September or about 10% of our shares outstanding.
I'll leave it there for now and pass the call to Jody stock through financial highlights.
Thanks, Dan.
Any strength in Bakken oil realizations, lower cash costs and higher production helped drive second quarter adjusted funds from 10% higher compared to the first quarter. Despite the reduction in natural gas prices. Following exceptional prices, we saw during the winter months.
Our second quarter Bakken oil differential was $3 us per barrel under Wi Fi.
Given the strength year to date in Bakken pricing, we're revising our full year outlook for our Bakken oil differential to $3.25 you asked per barrel below Wi Fi from $4 us per barrel previously.
We continue to believe that the Bakken is in an advantageous position in terms of oil takeaway capacity.
With significant rail infrastructure and the potential for existing pipeline expansion as well as new pipelines in the basin, we expect Bakken differentials will remain competitive longer term.
Despite all this we will continue to manage the risk and volatility through sales and marketing arrangements. We currently have close to 60% of our Bakken oil production in the second half of the year tied to fixed physical sales within the basin and the us Gulf Coast at an average differential of $2.66 us per barrel below Wi Fi.
Moving onto Marcellus pricing as expected, we saw our realizations weaken from the premium pricing in the first quarter.
With a meaningful portion of our sales tied to the Transcos zone six non New York market the change in seasonal demand from winter to spring drives lower quarter over quarter pricing in this region.
Our realized Marcellus differential averaged 57 cents us per mcf below Nymex in the second quarter.
We continue to expect our Marcellus differential to remain at these more moderate levels in the third quarter before strengthening again in the fourth quarter on the back of seasonal heating demand.
As a result, we widened our full year Marcellus differential guidance modestly to 35 cents to use per Mcf below Nymex from 30 cents us per Mcf previously.
Finally, we've reduced our operating and DNA cost guidance per Boe.
Which is largely a function of the higher volumes we are forecasting.
Turning to the balance sheet, our total debt net of cash remained largely flat from the prior quarter and our net debt to adjusted funds flow ratio was maintained at 0.5 time.
As we indicated in this morning's release, we plan to maximize our share repurchases to the full stock exchange approved limit, which was 7% of the company's public float as of March 19th 2019.
As he mentioned upon completion this would equate to 24 million shares repurchased since September last year, representing approximately 10% of shares outstanding.
Our buybacks have meaningfully enhance per share growth.
The midpoint of our 2019 liquids production implies 10% year on year growth, which translates to 14% on a per share basis currently before considering our plans for additional repurchases.
Underpinning our share repurchase plans is our view of the deep value in our stock today and the flexibility that our strong balance sheet provides to execute the full repurchase.
We think about value from several perspective, one of which is our ability to acquire an increased interest in our own high quality reserves at a significant discount to the drill bit or through acquisition.
Based on our current trading level, we could buy our producing reserves at about $11 per Boe.
And our netback this quarter was over $20 per Boe.
That sets up a recycle ratio of almost two times on producing reserves and the cost on a proved plus probable basis as even more attractive.
Lastly, I'd like to highlight a change to our 2020 WT, Iowa hedges.
We took advantage of an opportunity in the market to restructure our 2023 way hedges by essentially buying back the sold calls at a very modest cost. This removes the cap on the upside and leaves our downside protection in place.
With that I'll turn the call over to Ray Thanks Jody.
We saw a strong ramp in Buxton volumes in the second quarter was 26 operated wells brought on production.
Well results are tracking expectations and with a number of these wells being brought on production at the end of the quarter, including a nine well pad. We expect another solid build in Bakken production in the third quarter.
We plan to complete and bring approximately eight to nine net wells on production in the Bakken during the third quarter.
As our planned activity levels reduced in the fourth quarter Bakken production is expected to moderate from the high volumes projected in Q3.
Capital spending through the first half of the year was $368 million or about 60% of our full year spend based on of Titans capital spending guidance of $610 million to $630 million.
Second half capital spending will be weighted approximately two thirds to the third quarter, given the moderating activity levels in Q4.
I want to touch briefly on gas processing in the Bakken us with several questions recently on this topic.
Gas processing capacity in the basin is reasonably tight this is not new information.
We have had this issue I know sites for quite some time and therefore, our plans have incorporated these limitations.
We continue to be compliant with state gas capture regulations and our growth plans take all of this into account.
Additionally, our gas largely goes to third.
Party plant, which was very recently undergone a significant expansion.
In fact, the expansion has just come online.
And has more than doubled existing capacity. So we feel good about our outlook in terms of gas processing.
Turning to the Marcellus we also saw a significant growth in the second quarter due to continued strong well performance from longer lateral wells.
The average lateral lateral length of our Marcellus wells. This year has been over 7600 feet compared to 6500 feet last year.
This outperformance is driving our total annual production forecast higher with our guidance, though 99000 to 102000 barrels of oil equivalent per day.
2% higher.
The mid point.
We've also taken the liquids production guidance to 54000 to 55500 barrels per day with no change to the midpoint.
Part of our normal course portfolio optimization, we divested a modest amount of Canadian production during the quarter.
350 barrels per day for proceeds of about $10 million.
Our focus on capital efficiencies is continuing to show results and the Bakken or current average total well cost is approximately $700000 us lower than 2018 levels.
This has been a function of lower cost efficiency improvements and continuing to optimize completions.
Our current average all in total well cost is about seven $7.5 million us.
Lastly, we drilled five gross or four net wells in the DJ basin during the second quarter.
Our plan is to complete these wells in the third quarter and bring them on production to coincide with a new pipeline connection to a third party gas plant, which is expected to be completed later this year.
With that I'll pass the call back to Ian Thanks, Larry.
So in closing, we remain well positioned to deliver our financial and operational targets.
We're on track for another year of capital efficient high margin growth and strong corporate level returns.
We're also maintaining our significant financial resilience and believe this.
As a competitive advantage in this volatile commodity environment.
Finally, we see the current value of our equity is being discounted relative to our internal view and therefore, we will continue to prioritize the acquisition of our stock.
With that we will turn the call to the operator and be available for your 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 Tom prompt technology you have a question.
If you are using a speaker phone please lift the handset before pressing entities.
Your first question is from Neal Dingmann from Suntrust. Please go ahead.
Good morning, all I'm just wondering how do you view the buy I know you you up you talked about the buyback done completing before inverter sooner rather than later, but I am wondering even if the market remains highly rational how you would see that onyx sort of go forward basis versus thinking about acquisitions.
Good morning, Neil.
It's clearly the stock buyback is clearly a priority right now we see dislocation the market that sort of difficult to understand and as Jodi highlighted you compare filing the quality of our reserves.
$11 would be on a producing basis with anything you can see in the marketplace and it feels sort of like a no brainer right now.
So I mean, that's sort of where our focus is.
Acquisitions, how is that all going to play out.
I would think something has to break in that market to me just hasn't yet.
And so we do keep our eye on that marketplace I think.
Our focus for these days are on smaller things.
Things that you could very easily tuck in and put on the balance sheet and still keep the financially strong.
Theres such a dislocation other low in that acquisition market was.
Few high profile M&A exceptions, nothing's really happening there because there's such dislocation older.
Yes makes sense and then just lastly, there is.
Peers had some takeaway and just line pressure issues could you talk about in the Bakken that is can you talk about how your outlook for that thank you.
Sure ill turn that over to.
Jody regards.
You want to answer yes or no.
I mean, the plant expansion that we mentioned are that Ray mentioned earlier is significant it's more than doubling the existing capacity of the plant, where we take our gas.
Elsewhere in the basin, there's additional capacity being added later this year and into Q1. So we think this will help alleviate constraints later in the year, but for us.
We are.
We're we're pretty happy with Humana takeaway that we have and we see this.
Being excess capacity for several years.
Thank you.
Thank you. Your next question is from Travis what from National Bank. Please go ahead.
Yes, good morning.
As I think ray touched on it from the infrastructure side I just wanted to see if you could.
Share what your throughput is on the little Missouri expansion expected to ramp up to capacity at the end of the year.
Sure I mean, I think our current throughput right now is about 40 million cubic feet, a day thats going into the little Missouri.
And we think there'll be accessed room, there when does once that a little Missouri completes its full ramp it just started in Q or the beginning of August actually and so they're doing a bit of a ramp but most of that should come on in Q3. So we saw an immediate uptick in the amount of gas going through as of August onest.
And is it are you contracted on a on a take or pay through that plant.
Yeah like our our land is dedicated to that plant.
It's not a take or pay concept, though its dedication.
Okay. So the.
Of the 200 capacity, what what would enerplus be able to to have as throughput.
So the 200 and capacity half of that was a joint venture with path.
And so targa that operates plant has the other 100 and they currently have the 90 million Thats currently available or their previous train. So target will have now have doubled their capacity from 990 to 190.
Okay.
And then last question you touched on costs in in North Dakota.
Or maybe it was re down about 700000 to seven and a half do you see further opportunity through the second half of the year to to get that closer to seven.
Yeah, and if you look at absolute best in class performance Best Wells in the middle of summer, we're at those kind of levels.
Then winter comes in stuff happens and so we're trying to give people really get feel for what's happened over the course of the year. We're on a good run rate now and but we still have some activity in the winter, which costs more money in heating so.
Yes, I mean, the the team is it.
Exceptionally focused on continuing to look for nickels and dimes and.
Drilling performance is it's not as big ticket item is completion cost is.
But we just had a pacesetter well the other day.
Just to switch over nine days from spud to TD, which is quite exceptional when you think we're going through 21000 foot hole. So, yes, I see opportunities there to obviously and we don't see external pressures.
Relative to the activity picking up in a meaningful way, we don't see that stuff going on so it's really about us and what we're able to do with people and equipment and its gone pretty well right now.
Okay. Thanks, Thanks for taking my question.
Thanks drugs.
Your next question is from Patrick O'rourke from Altacorp. Please go ahead.
Well, Hey, guys I was actually going to ask on the gas capture there, but you seem to have fairly eloquently answered that the other thing.
We were kind of looking at I'm wondering here in terms of the DJ basin drilling completion activity that is going to be coming up.
Will there be separate horizons tested in and what sort of.
Exploration.
Could that potentially.
Inventory impact to that half.
Mark morning, Patrick.
So.
The DJ to choose zones that we think about codell and the Niobrara.
Our existing wells for and the Codell one of them the Io and our new wells similar kind of split so I guess, the Nile would be the.
The exploratory.
Zone, if you will.
It's a big big package, and it's a big surprise for sure.
Generally speaking in this area than a little bit less productive.
With completion designs have been tested to date, so I guess that would be sort of the upside that sits there we've highlighted 400 locations.
I would assume some contribution from both.
There if you really want to sort of think about it.
Blue Sky scenario.
That Nile package were sort of lending in one sub zone. One interval. If you were on there is there is actually more that's in there as well, we're not really testing any of that right now.
We're we've got a pretty big opportunity in front of us just with the Codell and.
One interval in the Niobrara, which serve our focus is at this moment.
Those wells are being completed as we speak and so we will have data as we move through the year, which will.
Roll into our plans as we're thinking about what this play looks like in 2000 Tony.
So when you guys are planning out these pads like you've done a fairly pragmatic job in the Bakken, where youve space things out and you haven't densified in any one particular area quite yet is that how you're going to approach.
This play as well as as we see it develop.
Yes, I mean, depending where this goes we've got 35000 acres.
Our activity to date has been focused on sort of a block each chunk about a third of that and.
Delineation.
Cost optimization activities are focused in that area and.
Our infrastructure build outs or are happening.
Directly in that area, that's we're pipes being laid and tie it served or occurring so.
Yes, I think you could see a similar kind of pattern to the thing.
We do have a one to one of the differences here is held denials sort of unfolds, we sort of think about the Bakken and three forks at least operationally, we think about those as.
Servicing dealer unit Thats not sure how we'll think about this one still some uncertainty there.
Okay. Thanks.
Thank you. Your next question is from Mike Dunn at GMP first energy. Please go ahead.
Thanks to you and just wondering if you have any comments on how you're viewing.
2020.
I guess a rate of liquids growth.
Relative to how you may have been thinking about it three months ago or so given.
Given the changes in the commodities and investor sentiment. Thanks.
Three months ago, I mean, that's a turn into that that's not fair.
So for those who maybe aren't so there were were in the third.
Early stages of a three year plan anchored on.
Delivers 10% liquids growth that plan.
Was based on some principles around financial resiliency.
Yes, the wrong economics and.
Being able to deliver sort of an attractive total return proposition to shareholders. So.
All of those conditions exist really oil still over 50, and our economics are still looking good and.
The singular difference until that's still our plan.
That's our plan.
You'd be made sense, when we did it and I think it still does step back, though and you know you need. Your question is impart what the heck is going on in the marketplace and so when we rolled out plan that we weren't anticipating that we would be as aggressive on share buybacks as we are.
And so.
I think it would be foolish not to continue to think about the marketplace and can and to think about alternative capital allocation choices.
So you know I think up a plan right now still makes a lot of sense and makes operational sense its attractive growth and we can afford it.
As we think about budgets for next year could evolve sure could evolve, but right now I think it still something that's pretty attractive.
Hi, its actually and Thats all for me.
Thank you.
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The next question is from Jami Qubec Pharmacy RBC. Please go ahead.
Yeah. Good morning, guys. Just a quick question on your Marcellus assets here I mean output during the quarter was well above historical levels and fully appreciate that enerplus is not often that asset, but what are your thoughts on where output is out here versus where gas prices are currently sitting thanks.
Sorry, what versus where they are sitting are you asking about curtailments or capital spending or whats, let's let me other James Yeah. I mean, just with respect to gas prices are fairly weak for Nymex is are there any curtailments planned or how do you think about output going forward on that asset.
Yes, so the growth in that asset asset. This year has been more than we would have anticipated.
But it's not a function of more spending.
It's been a very modest capital program by many levels and it just keeps delivering well results.
Our exceeding everyone's expectations out there so as a general rule, you're seeing all the operators in that core of the core area, including our partner our primary partner.
Spend modest levels, it's a it's a modest programs I don't see that changing I don't see anyone spending more money.
Do I see People's.
Curtailing I guess, we'll see where the cash market goes I mean, that's always a possibility.
If the cash market went to that sub dollar level, we've sort of seen that historically, that's not what we're anticipating.
We think we're sort of in the in the lower levels right now of that dynamic demand dynamic and prices aren't as good as they were but theres still a heck of a lot better than they were.
I'd say.
Broadly speaking as well there are some minimum levels and producers this wouldn't be our situation, but other producers would have some meaningful demand commitments or transport commitments to sort of put some floors on how they think about.
There.
Their volume commitments, so we don't see it now.
Good things change.
Sure Thats always a possibility thats not what we see in fact, we see.
Some possible real strength has become sort of into the winter months.
Okay great.
Another quick question for me here, you guys had a pretty decent tax recovery in Q2.
The tune of about 14 million Bucks or are you expecting any further revisions on this front through the balance of the year that could impact cash flow.
No.
That was actually due to age.
Former dispute in Canada that was resolved favorably for us that was.
Kind of a nice benefit in the quarter for us, but we don't expect that going forward.
Okay.
Right.
And sorry, and just one last thing I guess, we do still have a small.
AMTI refund that will come through.
In Q4, but that's.
Actually.
Kevin.
Okay. Thank you.
Thank you there are no further questions you may proceed.
All right well. Thank you everyone. Appreciate everyones time today people can enjoy the lost a little bit to summer.
Getting on again.
Thank you have a good bye.
Ladies and gentlemen, this concludes your conference call for today, we thank you for participating and we ask that you. Please disconnect your lines.