Aug 11, 2017
Executives
Drew Mair – Manager-Investor Relations Ian Dundas – President and Chief Executive Officer Ray Daniels – Senior Vice President Operations Jodi Jenson Labrie – Senior Vice President and Chief Financial Officer
Analysts
Greg Pardy – RBC Capital Market Jason Frew – Credit Suisse Aaron Bilkoski – TD Securities Brian Kristjansen – Macquarie Patrick O'Rourke – AltaCorp Capital
Operator
Good morning my name is Matthew, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus 2017 Second Quarter Results.
All lines have been placed on mute to prevent any background noise. After the speaker remarks' there will be a question-and-answer session.
[Operator Instructions]. Thank you.
Drew Mair, Manager of Investor Relations you may begin your conference.
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 today’s news release. These advisories describe the forward-looking information, non-GAAP information, and oil and gas terms referenced today, as well as the risk factors and assumptions relevant to this discussion.
Our financials have been prepared in accordance with U.S. GAAP.
All discussion of production volumes today are on a gross company working interest basis, and all financial figures are in Canadian dollars unless otherwise specified. I am here this morning with Ian Dundas, our President and Chief Executive Officer; Ray Daniels, Senior Vice President Operations; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; and Shaina Morihira, Corporate Controller.
Following our discussion, we will open up the call up for questions. With that, I will turn it over to Ian.
Ian Dundas
Good morning, everyone, and thanks for joining us today. After spending the better part of the last two years retooling our business to adapt to a lower commodity price world, our strategic focus shifted this year to reestablish corporate growth.
With our second quarter results announced this morning, I think it is clear that our objective of delivering profitable sustainable growth is well underway. Running through the key takeaways from our second quarter results.
First, we continue to demonstrate consistent operational execution. Our program this year has been trending ahead of schedule and on budget.
This, coupled with strong well performance, is supporting our increased production guidance for the year. Second, our North Dakota position is delivering meaningful highly economical well growth.
Quarter-over-quarter, North Dakota production is up 35%, with forecasted growth of 50% over the course of 2017. This project will drive about 25% corporate liquid production's growth.
As for prices, this growth is essentially funded within cash flow as our oil wells are generating between 30% to 60% breakthrough return. Third, changes to our cost structures and realized pricing have fundamentally improved our cash margins.
Our adjusted funds flow for the first half of the year is up close to 100% compared to the same period in 2016. And lastly, we remain in a strong financial position.
At the end of the second quarter, our net debt to adjusted funds flow ratio was 0.7 times. Undoubtedly, this strategic advantage affords us significant financial flexibility.
But to be clear, our overarching strategic objective remains unchanged. We will remain disciplined with our capital allocation decisions guided by returns.
This, combined with our multiyear hedge position and our growth plans, remain resilient despite the market volatility we are experiencing. As we think about the second half 2017, we expect to continue to deliver robust oil growth.
We averaged about 41,000 barrels per day of liquids in the second quarter and expect fourth quarter liquids of between 43,000 to 48,000 barrels per day. Overall, we believe our results further demonstrate a strong position that our company is in and our ability to generate solid returns in the current commodity price environment.
I'll now pass the call to Ray to talk through some of the operational highlights.
Ray Daniels
Thanks, Ian. Through the first half of the year, we brought 19 gross operated wells on production in North Dakota, which represents just over half of our North Dakota completions program this year.
With less downtime and good execution, we advanced further operationally than originally projected. So I'm very pleased about that.
As Ian mentioned, we're planning to continue to deliver meaningful oil growth in the back end of the year, although capital in the second half of the year will be weighted to the third quarter, the large majority of our second half completions will be brought on production in the fourth quarter. As a result, our oil growth in the second half of 2017 is really going to be a fourth quarter build.
In terms of our total production, it will be sequentially lower in the third quarter as we closed the sale of Canadian shallow gas asset and the Brooks waterflood property in the second quarter. In addition, Marcellus production volumes in Q2 benefited from about 6 million cubic feet per day related to our gas balancing adjustment from a prior period.
So we expect Marcellus volumes will be lower in the third quarter. Well performance across our assets has remained strong.
We highlighted some of the initial production rates from our second quarter completions in today's news release. In North Dakota, the Arctic well, a 4,300 foot lateral, has produced approximately 120,000 barrels of oil equivalent in its first 100 days on production.
This is meaningfully outperforming our expectations for a one-mile lateral well. Staying with North Dakota, well costs year-to-date for our base completion design of approximately 1,000 pounds of proppant per lateral foot have come in below our initial forecast.
We had planned for a total well cost of $8 million, that's drilling, completions and facilities and have been coming in just below that. Given some of the success we've had with higher proppant intensity, we will continue to test increased proppant volumes in the second half of the year, which will put some modest pressure on well costs in the second half of the year.
Turning to the Marcellus, through the first six months of the year, we participated in 27 gross non- operated wells that were brought on production. Net to Enerplus, this is just over three net wells and represents approximately half of our 2017 production.
Well performance in the Marcellus has remained resilient, with production approximately flat to the first quarter. Although, as I mentioned previously, second quarter Marcellus production included a gas balancing adjustment from a prior period, so production was down slightly relative to Q1 after adjusting for this.
In Canada, our waterflood portfolio production was just over 13,000 barrels of oil equivalent per day in the second quarter. This number includes some volumes from Brooks, which was divested in the quarter.
On a pro forma basis, after adjusting for the Brooks sale, second quarter production from the Canadian waterfloods was just 12,000 barrels of oil equivalent per day. Canadian activity in the second quarter was largely focused at Ante Creek where we have expanded the source water supply and water injection rate.
We are currently injecting approximately 5,000 barrels of water per day. And by year-end, we're targeting 12,000 to 15,000 barrels of water per day.
Outside of Ante Creek, activity in Canada for the rest of the year will be focused on ongoing polymer flooding and waterflood optimization. I will now turn the call over to Jodi.
Jodi Jenson Labrie
Thanks Ray. Our adjusted fund flow in the quarter was $114 million down modestly from the previous quarter, but up 50% from the same period a year ago.
This has been driven by higher commodity prices, improved sales price differentials as well as our lower cost structure. The significant improvement in our cash flow margin can be seen through our netback.
Compared to the same quarter last year, WTI is higher by 6% and NYMEX gas is higher by 63%. However, when you compare our operating netback before hedging on a BOE basis, it improved by 86% to $17.41 per barrel of oil equivalent.
We recorded net income of $129 million in the second quarter. This included a gain of $78 million associated with sale of our non-core Canadian property.
Operating expenses were $5.83 per BOE this quarter or 12% lower than Q1. As a result, we are reducing our 2017 annual operating cost guidance by $0.45 per BOE to $6.40 per BOE.
We do expect operating costs to increase slightly, however, in the second half of the year from our increasing liquids production. As you can see, the steps we have taken over the last couple of years to high grade our portfolio and focus on lower cost, higher-margin assets having a meaningful impact on our profitability.
Through the first half of the year, we spent $222 million or approximately 50% of our annual capital spending guidance of $450 million. This resulted in an adjusted payout ratio of 101% for the first six months of 2017.
Moving onto pricing differentials. Firstly, in the Bakken, differentials improved modestly in the second quarter to average $5.43 per barrel below WTI.
Spot Bakken prices strengthened considerably late in the second quarter and into the third quarter as the Dakota Access Pipeline, or DAPL, was brought into service in early June. Our second quarter differential was also impacted somewhat by a high proportion of trucked oil volumes from new pads brought on the stream.
Looking forward, we expect our Bakken differential in the second half of the year will average around $3.50 per barrel below WTI and expect our full year average Bakken differential to be around $4.50 per barrel. As part of managing our price exposure, we have locked in a portion of these tighter post-DAPL differentials through sales commitments on up to 10,000 barrels per day over the next 18 months.
The remainder of our Bakken portfolio is exposed to floating market differential prices. In the Marcellus, we saw sales differentials widened slightly through the second quarter averaging $0.64 per Mcf for Enerplus.
Late in the quarter, differentials widened more significantly due to regional pipeline maintenance and delays to the Rover pipeline project. Given the timing uncertainty of Rover, we are expecting some further weakness in Marcellus differentials in the second half of the year and have consequently revised our expected Marcellus natural gas to realize price differentials between 2017to $0.75 per Mcf below NYMEX.
In our producing region of Northeast Pennsylvania, there is approximately 600 million cubic feet per day of incremental pipeline takeaway capacity coming online towards the end of 2017. Once Rover and other pipeline projects slated for completion during the rest of 2017 are in-service, we expect our Marcellus price differentials to improve further to levels tighter than we realized in the first half of 2017.
Briefly on financial hedging. Our funds flow is well protected for 2017, as we have over 70% of our crude oil production net of royalties hedged for the rest of the year at an average floor price of about $50 per barrel WTI largely through three-way collars.
We've added to our 2018 hedge positions and now have about 65% of our crude oil net of royalties hedged based on 2017 volumes at average flow price of $53 per barrel WTI Finally our balance sheet remains very strong. At quarter-end, our cash balance was $385 million, our total debt net of cash was $308 million and our net debt trailing funds flow ratio was 0.7 times.
Now I will pass the call back to Ian for some closing comments.
Ian Dundas
In summary, we are pleased with our operating and financial performance through the first half of 2017 and remain on track to deliver our increased production targets this year. Our financial position is rock solid, which view as a powerful strategic advantage, as we manage through this volatile and complicated market.
And so with that, I will turn the call over to the operator, and we will open up for questions you might have. There we go.
Operator
[Operator Instructions] Your first question comes from the line of Greg Pardy with RBC Capital Market. Your line is open.
Greg Pardy
Thanks. Thanks, good morning.
Ian, definitely vacation is in focus. Nice quarter.
Just a couple of questions on the shape of your CapEx. 3Q and 4Q spending, would it sort of roughly be two-thirds in the third and maybe the balance in the fourth, in terms of the back of the year spend?
Ian Dundas
You're talking about the rest of the year spend, that's not about…
Greg Pardy
Yes. Okay, okay.
Perfect. And then if we're in a $50 world next year, would you directionally expect CapEx to be more or less what you spend this year?
Or do you think you'll be a lot higher?
Ian Dundas
It’ll be higher.
Greg Pardy
Okay.
Ian Dundas
I mean, our -- you said a lot, I don't know what the lot.
Greg Pardy
I mean, you sort of mind, $50 that kind of thing.
Ian Dundas
Those are your numbers, they're not terrible. If you sort of go back to what we're trying to accomplish, we've got a three-year growth target that's sort of weighted towards our liquid spend, which levers us 20% CAGR on our liquid.
In a $50 world with $3 NYMEX, we can make all of that happen within cash flow. And so notionally, that looks like something in the pipes next year, notionally.
And yes, we'll be smart in connection with that, but we're in a pretty good position where we're not going to have to life [indiscernible] on that. The balance sheet is so strong and the hedge book is so strong.
It gives us the flexibility there. But that's not a bad way to think, Greg.
Greg Pardy
Okay. Great.
And maybe just a question for Ray. The Bakken results, I guess, what stood out to me is just the lateral links, but yet not that much of a difference in lot of cases between the IPs.
And in some cases, even though, I think, the 90-day IP you quoted was quite impressive. But could you – could we dig into that just a little bit.
I know you're using more profit and so forth, but some of the wells are a lot – just a lot shorter than others, but very, very good results, nonetheless?
Ray Daniels
Yes. So we – what we do is we take a percentage of the long wells with the short wells.
And as we start completing these short wells, we've seen that the initial performance is a lot better. And we still haven't changed the EUR of these short wells.
We just think that the initial production from that shorter length is better than we had predicted. And the benefit of that is to the value of the wells than at present value of the well.
Greg Pardy
Okay, great. And you mentioned, I think, you've got, I think, another 19 to go in the back half.
What percent would be the short versus the long laterals? Just roughly is fine.
Ray Daniels
Our asset to…
Ian Dundas
I think things can move around a little bit, but – certainly, if you step back a long versus short trough, it started way back when with more shorts. You're talking two to three years ago.
And then our view evolved to economics in the longs were a lot better. And so we transitioned to more longs.
That would still be our view that economics on longs are better. However, we're seeing some interesting rates here, and you got to be careful.
As Ray said, you don't get too fired up in that, because in early time, your only – most of your contribution income of long well would be from that heel of the well, not the toe. So we threw at a 180 days of data, which is better than a month of data, but we'll be smarter on these things in six months and that scaling factor that Ray talked about, broad brush.
We think the reserves on our short would be 60% of a long, even though with what happened with lateral length. And then this question on economics is really interesting, because we are meaningfully outperforming early time performance.
So we'll see how all that shakes out.
Greg Pardy
Perfect. Thanks very much.
Ian Dundas
Thanks, Greg.
Operator
Your next question comes from the line of Jason Frew with Credit Suisse. Your line is open.
Jason Frew
Greg actually kind of went down the path. I was going to on the rates for the shorts.
So I think we'll get there. Thanks.
Operator
Your next question comes from the line of Aaron Bilkoski with TD Securities. Your line is open.
Aaron Bilkoski
Good morning guys. I’m curious what the cost difference was between the shorter more frac-intensive wells and your more traditional well?
And I guess the follow-up question would be, are you guys testing these higher intensity fracs on the shorter wells with the anticipation like it, ultimately, be applied to a longer well in the future?
Ray Daniels
Yes, I think the difference has been $6 million to $8 million short to long. And…
Ian Dundas
Yes. I think so.
Then the there is a question around intensity and whether we're planning to extrapolate? Absolutely.
That was part of the design – that was part of the design was you could put a lot of prop in that play, but relatively lower cost, and we will see what we can learn from that.
Aaron Bilkoski
Perfect. I have another follow-up question, this is on the debt side.
Your debts virtually all U.S. dollars, you report in CAD.
Would you see any benefit of hedging the FX? Or is the reporting currency kind of less relevant in the fact that most of your revenue and costs are all USD?
Jodine Jenson
Yes, it's basically the latter. We just report in Canadian.
We have U.S. revenue as well as the CapEx.
And so its just you're reporting currency thing.
Aaron Bilkoski
Perfect. Thank you guys.
Ian Dundas
Aaron, historically, we have hedged a little bit on the currency. But as the math has changed, we're still balanced on that.
Generally speaking, are going to let us low.
Aaron Bilkoski
All right, thanks again.
Operator
[Operator Instructions] Your next question comes from the line of Brian Kristjansen with Macquarie. Your line is open.
Brian Kristjansen
Good morning, guys. Ray, you mentioned continuing to test more than 1,000 pounds per foot of proppant go forward.
Are you going to see yourself repeating the 2,300 pounds per foot? Or where do you see sort of your average proppant levels on the remaining program?
Ray Daniels
Well, we're still evaluating the results we're getting. I think we're going to be testing in the second half of 1,500 to 2,000 pounds of foot.
Going to that higher level is expensive. And we think when we look at the value of the wells, that's 1,500 to 2,000 an area that we think will maximize value.
Brian Kristjansen
Is that 90-day rate on that 2,300 pound per foot one, is that sort of the definitive? Or do you need even longer production history to know that, yes, that was – that's probably too much?
Ray Daniels
Well, we're looking at the shape of it. I mean where – as we compare the 1,500 to 2,000 and the higher proppant rates, then we will be able to compare the results between each other and start to tune into what the optimum proppant density is.
We're also looking at the rest of the basin and trying to learn from what's going on in other places as well. So all of that work is ongoing just now and will continue into the second half of the year where we've got some additional wells that we're looking to increase the amount of proppant we're using, and we'll get the results from them and add that to our analysis.
Ian Dundas
Brian, I think, strategically, our thinking has evolved a bit on this. And obviously, 100 days for this kind of production matters a lot.
But you are seeing data creep into the samples that regionally it says you might learn a lot at the six-month to one-year level. And it doesn't maybe affect your rate of return quite as much, but it certainly affects long-term reserve performance and NTP per well.
So we're trying to be as objective as we can, look at the data and learn as we forward on this, because it is still early – it is very early times still as we're trying to isolate which variable controls which feature in which part of the basin. And so as Ray said, it's really encouraging, but we're trying to take this objectively.
I think more data is going to continue to be important now.
Brian Kristjansen
Okay, got it. Thanks.
Operator
Your next question comes from the line of Patrick O'Rourke with AltaCorp Capital. Your line is open.
Patrick O'Rourke
Good morning, guys. I saw the quarter it seems like things are shaping up, kind of good plan.
Just a few quick questions. I guess, you're planning to have a pretty big fourth quarter in the Bakken, bringing on a fair amount of wells.
Just wondering if you can give us a sense of at that time, post that – and call it December 31, what you would have remaining in the backlog? And then what you would estimate – with the fresh production coming on, what your decline profile would be?
And how you would think about maintenance capital from that point?
Ian Dundas
Sure. So at the end of the year, we're going to have 13 DUCs in the Bakken.
Ray Daniels
Yes, so the decline question. It'll be steep on December 31.
Obviously, it depends upon exactly how these things come on over the course of the quarter. So I would get into – I think continue to decline and all sort of things.
We've said, think about 24% corporate decline as a good number to think about. And then that inching its way up a little bit.
Obviously, isolating on a quarter, it will be steeper into fourth quarter going into first quarter next year just the way this lines up. But think about adding a point or two to decline as we move into next year as the program moves up.
On the maintenance capital side, this year, it's about $300 million we've talked about. And so as you think about next year, it will move its way up as we've got a bigger base.
We feel capital efficiency as we look into next year feels relatively stable. But as you know, that will be a function of oil price.
If you made a guess today in a $51 oil world for next year, maybe there is top line inflation of 5%. It's really hard to tell, but vis-a-vis certain modest upward pressure on it.
And so, let's say, relatively stable for us. And then, I guess a little bit of upward pressure by declines moving up, but we're keeping our eye on all of those things, and again, from a base of around $300 million of maintenance capital.
Patrick O'Rourke
Okay. That's a great segue into my second question here is, just in the past you guys have locked in service costs going out a little bit further.
Obviously, the market, for the service companies, has improved, albeit, the Permian seems to be quite, quite tight relative to, say, where the Bakken is. Just wondering what sort of opportunities are out there to lock in on the service costs side right now?
Ray Daniels
So we've locked in our rigs and pressure pumping for next year. They only makes up about 70% of our overall costs.
So we're still working on other services to try and lock them in. I think, overall though, we see that's a 5%, maybe to 10% increase overall in 2018.
Ian Dundas
Yes, I knew I could just jump in there is a little bit. So Ray's guys went through a big piece of work looking into the market about two to three months ago.
And out of that came this 5% to 10% kind of number. When we looked at it, we made a decision not to lock all of that in because mainly it felt like a big number that 10% compared to what we were seeing in the activity levels and made a decision not to lock all of that in.
So today, I think 5% is not a bad number, today. You couldn't secure maybe all of that, but it;s really going to be dependent upon – and you can see the volatility and the uncertainty.
And programs are coming down this year in certain places and going up in others. This inflationary sucking sound in the Permian is a real thing.
It's not – it doesn't have the same intensity in North Dakota. So as Ray said, this has taken us to a place now.
We were most concerned about pressure pumping. And so we've had an ability to lock that piece in with some modest upward pressure on it.
Our goal would be to offset that through efficiency gains or mitigate it through efficiency gains. And really does feel like it's on a bit of a teeter-totter balancing act right now.
And you can see the numbers. That $45 of oil, we can afford these programs at $55 if there's more cash flow.
We're in somewhat of a unique position where we are not as heavily influenced by that because of our existing financial position.
Patrick O'Rourke
Okay. And then, I guess, final question here.
Where do you see things go into? The Bakken asset is, obviously, firing on all cylinders, but we've picked up on recent licensing activity in other plays outside of that from you.
Your currency, you've picked up relative to your peers here, so maybe there is potential M&A opportunity. Just kind of wondering how, call it, medium term you're thinking is here?
Ian Dundas
The plans sort of been working out the way we designed it. We changed the math of the business, so that we could be successful and could grow in this lover price environment.
And so now that's what we're doing and have a pretty robust opportunity in front of us. So every time I get asked that, we'd start with that qualifier, which is really, really important.
So as we think about improving the portfolio or expanding our inventory set, our eyes are on those sorts of things. And as you point out, we've built a position in the DJ.
We built it at very modest cost. Our overarching goal is to marry portfolio strategy and then have a financial plan that makes sense, which is critical.
So our eye continues to be on thinking about things that might make our company better that keep our balance sheet strong and makes sense on a per share basis. And as you point out, our currency is getting better, but we still see a lot of value inherent in our stock that's already been captured.
Patrick O'Rourke
Thanks, Ian.
Operator
There are no further questions at this time. I'll turn the call back over to you.
Ian Dundas
Well, thank you, everyone, for dialing in today. Appreciate your attention.
Have a great rest of your day and a nice weekend. Thank you.
Cheers.
Operator
This concludes today's conference call. You may now disconnect.