Feb 23, 2018
Executives
Drew Mair - Manager, IR Ian Dundas – President & CEO Jodine Jenson Labrie - SVP & CFO Raymond Daniels - SVP, Operations, People & Culture Eric Le Dain - SVP, Corporate Development & Commercial
Analysts
Greg Pardy - RBC Capital Markets Brian Kristjansen - Macquarie Research Patrick O'Rourke - AltaCorp Capital Inc. Travis Wood - National Bank Financial Dennis Fong - Canaccord Genuity Dan Healing - Canadian Press
Operator
Good morning, my name is Sharon, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus' 2017 Year-End Results Conference Call.
[Operator Instructions]. 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'm here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; Eric Le Dain, Senior Vice President Corporate Development, Commercial; and Shaina Morihira, Vice President Finance.
Following our discussion, we will open up the call for questions. With that, I'll turn the call over to Ian.
Ian Dundas
Good morning, everyone. Thanks for joining us today.
In 2017, we delivered on our growth targets, drove further margin expansion and maintained our best-in-class balance sheet strength. In short, we continue to deliver on our plan.
We remain well positioned to drive another year of differentiated cash flow growth in 2018 under an affordable fully funded capital program. We've been talking a lot about the improvement in our corporate margins and the results from the fourth quarter are further evidence of just how meaningfully this margin expansion has changed the math of our business.
Excluding the Alternative Minimum Tax refund of $50 million, our adjusted funds flow in the fourth quarter increased by 65% compared to the prior quarter and our operating netback was just over $21 per BOE. This is the highest unhedged netback we have had since mid-2014.
As we think about our plans for 2018, this margin expansion, combined with the robust returns we are seeing in North Dakota, affords us the ability to drive competitive oil production growth and fund our dividend through internally generated cash flow. And as strip pricing materializes, we would expect excess cash flow.
Our 2018 guidance remains unchanged. We have a capital budget of between $535 million and $585 million, which is predominantly being directed to our light oil project in North Dakota and is projected to grow our company liquids volumes by approximately 20%.
We made further progress in 2017 focusing our portfolio on fewer, larger and higher-margin assets. We divested just under 8,000 BOE per day of noncore production during the year.
While these divestments have improved our efficiencies and cost structures, they have also significantly reduced our abandonment liabilities. The present value of our ARO today are the lowest they have been in over a decade.
Our reserves performance in 2017 was also strong. Our finding and development costs remain highly competitive, particularly since we directed the large majority of our capital to our oil assets.
In 2017, over 85% of our capital was allocated to our oil assets. And for the third consecutive year, we generated sub-$10 per BOE proved plus probable F&D costs.
We replaced 189% of our 2017 production through the drill bit with material reserve additions in North Dakota, where we replaced over 400% of 2017 production. In summary, 2017 was a strong year for Enerplus and the company is well positioned to continue to generate value for our shareholders.
I'll now pass the call to Jodi to talk through some of the financial highlights.
Jodine Jenson Labrie
Great. Thanks, Ian.
The higher benchmark oil and natural gas prices in 2017, combined with our improving pricing differentials in the Bakken and Marcellus as well as the lower cost structure, resulted in a significant increase in our cash flow in 2017 compared to 2016. Our 2017 adjusted funds flow increased by over 70% compared to 2016, which included the benefit of $50 million related to half of our Alternative Minimum Tax, or AMT, refund.
Excluding the AMT refund, adjusted funds flow increased 55% over 2016. The remaining $50 million in AMT credit carryovers is expected to be realized over the three-year period between 2019 and 2021.
Our net income for 2017 was $237 million and included a deferred tax expense of $46 million in the fourth quarter related to the remeasurement of our deferred tax assets. This was a result of the new U.S.
tax legislation, which reduced the U.S. Federal Tax rate from 35% to 21%.
Looking forward, however, the lower tax rate will benefit our after-tax earnings in the future, if we become taxable. In terms of cost structure, our execution and cost focus resulted in realized operating, transport and cash G&A expenses all lower than our guidance in 2017.
Particularly noteworthy is our operating cost performance over the past three years. Since 2014, we've reduced cash operating costs by 30%, while at the same time increasing our liquids production weighting from 42% to over 50% in the fourth quarter of 2017.
Turning to our financial position, our balance sheet remains strong. We reduced net debt by 13% over the course of the year and ended 2017 with a net debt to adjusted funds flow ratio of 0.6x.
At current pricing levels, we expect to realize increased cash flow in 2018 that will continue to provide us with significant flexibility and further support the resiliency of our growth plan. In addition, we remain committed to our principles of disciplined, return-based capital allocation as well as cost management.
I'll now turn the call over to Ray.
Raymond Daniels
Thanks, Jodi. Our 2017 Q1 to Q4 corporate crude oil growth rate of 28% was driven by North Dakota, where we added a second operated rig at the start of the year.
We were able to increase production by 70% in North Dakota over the course of 2017. In 2018, we plan to continue operating two drilling rigs and one completions crew in North Dakota.
This is expected to drive year-over-year production growth of 30% in North Dakota, lifting our corporate liquids production by approximately 20%. However, we expect to see a decline in North Dakota production in the first quarter of 2018 from last quarter as our on-stream activity in Q1 is back-end weighted.
Following Q1, the shape of our program is expected to result in sequential growth throughout the remaining quarters, once again, peaking in the fourth quarter. We're keeping a close eye on costs as activity has increased in the Bakken.
The rig count has picked up modestly to around 50 rigs, although this is still well down from 2014 levels, when there were around 190 drilling rigs in the basin. While we've seen some inflationary pressures, we believe we can offset these increases through efficiencies in execution, essentially holding our baseline well costs largely flat to 2017 levels.
That said, we expect our average 2018 well cost to increase slightly due to the continued testing of higher proppant completions in the 2018 program. We still consider our baseline completions to be pumped with approximately 1,000 pounds per foot of proppant that we plan to complete certain wells in 2018 using higher proppant concentrations.
In the Marcellus, after curtailing production in September and October due to pricing weakness, unconstrained rates in November and December were closer to 205 million cubic feet a day with fourth quarter production averaging 193 million cubic feet per day. We expect the Marcellus production to remain broadly flat in 2018 relative to average 2017 levels.
Canadian waterflood production averaged 10,700 barrels of oil equivalent per day in the fourth quarter and is expected to remain around this level during most of 2018 with an increase towards the end of the year related to Ante Creek. Lastly, we gave some details in our press release this morning about a well we drilled in Colorado in the DJ Basin.
As background, we acquired most of this acreage during 2015 and 2016 through leasing activity and we were able to get this done from very low entry cost with our Denver-based in-house expertise. The acreage is located in northwest Weld County, where there have been some encouraging offset wells drilled in the area.
We drilled and cored a pilot hole throughout the entire Niobrara-Codell interval and the data indicated significant oil saturations throughout the zones of interest. We went onto drill and complete a 9300 foot lateral well in the Codell using a high-proppant and high-fluid intensity slick water completion.
The well had high initial water cuts during cleanout operations due to the high fluid volume pumped during the completion. The oil rate and oil cut inclined for the first four months on production, following which the well produced a relatively stable rate of approximately 400 barrels of oil equivalent per day.
We shut the well end for about 30 says starting in mid-January for facilities modifications and in the last week we brought the well back on production and it's producing at around 550 barrels of oil equivalent per day. Overall, we're encouraged by the results and the current rate compares favorably to offset wells.
But this is the first well in a reasonable acreage footprint, so it's still very early days. We plan to drill a few more wells in the DJ during 2018 and capital for these wells was included in the 2018 budget.
And with that, I'll turn over to Eric.
Eric Le Dain
Thanks, Ray. Our realized prices benefited in the fourth quarter from further improvements in the Bakken and Marcellus differentials.
In the Bakken, our differential average to $1.61 per barrel below WTI, benefiting in part from issues with Canadian synthetic supply and pipeline issues. With the strength we have seen in recent Bakken pricing, we took steps to lock in additional annual volumes at these tighter differentials.
We have now entered into 2018 term sales contracts on roughly 16,000 barrels per day at a weighted average differential of $2.50 per barrel below WTI. The remainder of our Bakken portfolio is exposed to floating market differential prices.
We have guided to a Bakken differential in 2018 of $2.50 per barrel below WTI. In the Marcellus, although October prices were weak, we saw stronger pricing in November and December in response to seasonal heating demand and as additional industry pipeline capacity came online.
Our fourth quarter Marcellus realized differential averaged $0.81 per Mcf below NYMEX, while the full year averaged $0.76 per Mcf below NYMEX. We continue to see 2018 as a pivotal year for Marcellus pricing with some large FERC-approved pipeline projects being brought into service in both the southwest and northeast Marcellus, tightening differentials further.
We are already seeing this in the regional daily cash spot market, which has had an average differential of $0.56 per Mcf below NYMEX at [indiscernible] since December 1, 2017. We are in a good position to benefit from this with our balanced portfolio, providing exposure to both the local sport market and to downstream market points through our firm sales and transportation commitments.
We are maintaining our realized Marcellus differential guidance for 2018 at $0.40 per Mcf below NYMEX, which excludes our firm transportation costs of $0.18 per Mcf of Marcellus production. Briefly on hedging, we have approximately 65% of our 2018 crude oil production, net of royalties hedged.
The majority of our hedged positions are three-way caller structures with the average floor just below $0.53 per barrel and participation up to about $61.50 per barrel WTI. Quick comment on AECO.
Our remaining Canadian gas production is only about 5% of our total company production. Additionally, the $0.65 per Mcf AECO-NYMEX basis swap we have had in place for the last three years continue through to November 2019.
These swaps cover all of our existing Canadian gas production. With that, I'll pass the call back to Ian for some closing comments.
Ian Dundas
Thanks, Eric. And before opening up for question, I just wanted to announce that Eric has decided to retire from Enerplus after over 11 years with the company.
Eric has had an extensive and tremendously positive impact on our business. He started as VP of Marketing in '06 and has consistently taken on more and more responsibilities as his career progressed here and his commitment and performance have been at the highest levels.
So we will wish him the best. And also, I suppose, special thanks to his wife, Christie.
Christie, fingers crossed, but I'm sure it's going to be all okay. And so to conclude the call, I'm confident that we can continue to deliver on the strong momentum, which we had as we finished 2017 and offer another year of profitable growth for our shareholders.
The key elements for our growth plan remain unchanged. We are committed to managing risk, maintaining a strong balance sheet, delivering responsible and consistent execution and are focused on generating competitive full cycle returns.
And now, we'll turn the call over to the operator and we're available for your questions.
Operator
[Operator Instructions]. Your first question comes from Greg Pardy from RBC Capital Markets.
Greg Pardy
Eric, just all the very best to you as you go ahead. Just a couple of questions on my end.
Could you maybe just frame what you expect your D&C cost to be in the DJ? And is it likely you'll drill three?
I know you're indicating up to three this year. And I'm just trying to get a better sense, are those wells -- I mean, it's a fairly large acreage position, but will they be fairly proximate to what you’ve just drilled?
Or will they be a lot more dispersed?
Raymond Daniels
Yes. Greg, it's Ray here.
So these wells will be fairly proximate to where we've drilled. We'll be looking at testing both the Niobrara and Codell -- are continuing to today Codell and Niobrara.
And the cost of the well -- we -- so right now, we've just been -- we drilled the well. We did a bunch of science well, where we cored the well and did a bunch of tests on it.
So we expect the well costs to be well down this year.
Ian Dundas
Yes. The only thing I'd maybe add to that is -- I mean, we're obviously in an early delineation mode.
Producers in the area who are more active would be talking in that $5 million, $6 million range. I think if you're think about a bigger completion, there are probably talking in the $6 million to $7 million range.
So that's probably not a bad number to be thinking about at this stage. But as Ray said, this is delineation and these are one-offs right now and we're going to be doing a little bit of a science on this.
Greg Pardy
Okay. Great.
And the other question is just relating to your North Dakota production. With the quarterly trajectory that you see over the course of this year, could you give us an idea what you think you'll exit 2018 at?
Ian Dundas
Higher. Greg, I'd say, last year we put an exit number out and we felt that was really important just because of we were starting to grow again, right?
So we don't have an actual exit number out there this year. We're targeting 20% liquids growth.
North Dakota is the big driver of that and it's going to continue to be really, really strong, double-digit stuff. We gave a little bit of color -- Ray did, I suppose, few minutes ago.
Really strong exit rate. When you look through -- how we have consistently thought of our operations, December, January.
We thought the best thing for us was always slowdown completion activity in those two months. That's worked pretty well for us.
I think that's an efficient thing to do. So that sets up a little bit of a dip as we come into Q1 and then it will be sort of steady growth from there on out.
And again, North Dakota is the key driver. So it's strong double-digit growth.
Greg Pardy
Okay. And obviously, after Q1, it will be sequential increases 2Q, 3Q, 4Q?
Ian Dundas
That's how we see it.
Operator
Your next question comes from Brian Kristjansen from Macquarie.
Brian Kristjansen
Can you comment at all what you had for EOR bookings in the DJ, if you had some?
Ian Dundas
De minimis. We've got one well and that's sort all how we're thinking about right now and you think about -- even the [indiscernible] process didn't have a lot of data coming at year-end, so.
Brian Kristjansen
Okay. And what have you got for gas processing access in Weld County right now?
Eric Le Dain
Yes. At the moment, the way the regulations work, you've got a significant period of flaring.
We do not have direct tie to gas processing at this moment. But we, of course, as many players in that area, are working and looking at the different alternatives being proposed for incremental processing.
Brian Kristjansen
Okay. And then you eluded at the onset -- if the [share pulls] [ph], you've got free cash flow.
Where would you see that directed? Would that be debt, growth, dividend?
What's your preference for tuck-ins, et cetera?
Ian Dundas
Yes. So we believe we're offering robust and differentiated growth to the drill bit right now.
So that extra dollar we don't see going into the ground. Don't need to do that at all.
Don't think that makes us more efficient. Don't think that's the way to add value.
So strategically, I suppose, the incremental -- when we think of balance sheet, we're, I think, best-in-class right now. Well under 1x debt to funds flow.
And as you said, that will be better under the strip. So don't feel a need to go to the zero debt.
So strategically, it would be about positioning for the future. And this North -- this DJ project is a good example of that.
We have the financial flexibility to buy the land at a point where people weren't buying a lot of land. Again, we got that pretty cheap.
We've got financial flexibly to spend whatever we want this year. We think the right plan is this additional three-ish wells and it just gives us a lot of latitude there.
I suppose the only other thing that -- again, it's now 0.5 hour into the call and this is the first time I've whined about valuation. The stock is doing very well, but we see a lot of value in that.
And so we're keeping our eyes on the possibility of share buyback as well. That would be something that's strategically at the right price could make some sense for us.
Operator
Your next question comes from Patrick O'Rourke from AltaCorp Capital.
Patrick O'Rourke
I guess, Greg took a bit of the first question that I was going to ask here. But I just -- you guys talked about coring close to 400 feet in the DJ.
Just wondering, in terms of number of benches that you see there -- I think some of your competitors are talking about three in the Niobrara, one in the Codell. Is that how you see it, kind of, playing out?
And then with the delineation there, you are going to focus on hitting multiple benches to kind of test that theory?
Ian Dundas
I think we'll sort of stay away from that right now. It's very early.
We've got a core that looks like we were thinking it would that gives us prospectivity into broad play concepts. You're right.
There's a lot of complexity as your work within that, but I think we'll -- we're not going to sort of talk about that right now. There's not a lot of data around us, but this is -- it's encouraging where we are right now and is setting us up to put a little bit of capital to work to go forward and there'll be a lot of things that we will be testing and trying to understand.
Patrick O'Rourke
Okay. Great.
And then second question here. Reserve report, looks like some quite strong technical revisions that you had in there.
Just wondering if you can provide some granularity? How you're booked?
I know it's different from section to section, but on average EOR per location in the Bakken and how many PUDs and probable per section that you're booked out at now?
Ian Dundas
Yes. We can give you a little bit of color.
I'll turn that to Eric. Just at a high level -- reserve bookings for us are -- they're tied to where our capital is being spent and our capital is mostly being spent in North Dakota.
And so that's been a big driver to those bookings. We highlighted 400% reserve replacement in North Dakota.
When you think about those technical bookings though, they are also influenced a little bit by our Marcellus project, which is the gift that keeps on giving from a reserves perspective even though we're not putting a lot of capital into it. Eric, do you want to give a little more color on North Dakota?
Eric Le Dain
Yes. Just one last point.
On the Marcellus, I think we had our fifth year here of positive technical revisions on PDP in the Marcellus. Coming back to the North Dakota, probably are for a long lateral of two miles were probably in -- around the 850,000 barrel oil equivalent type level of EOR.
We have about 175 wells net in the ground.
Patrick O'Rourke
And in terms of the future booking, what sort of density per section are you booked at? It seems like you would still be booked quite light.
Eric Le Dain
Yes. I'd say we're still quite light compared to our projected 10 wells per drilling spacing unit.
Operator
Your next question comes from Travis Wood from National Bank Financial.
Travis Wood
Congrats, Eric. Question is around the A&D, probably more on the D side of that equation.
Can you provide us any color in terms of how you're thinking about the rest of the potential assets that you could get rid of here over the next year or so?
Ian Dundas
Yes. So we're dealing with pretty small numbers now.
The last two years have been -- we've effectively changed the Canadian asset base. And so now we're sitting on some core [indiscernible] properties and the other stuff is pretty modest numbers.
It's gassy, but not that assets now actually, just sort of smaller. And it's not a great time for Canadian gas.
But in the context of 5000-ish kind of BOE plus or minus, we'll keep looking for opportunities to move that out depending where gas prices are and have a little bit of cash flow or not. It's not a big thing any longer and we'll just continue to look for the best way to monetize that.
But I'd put it in the context of not particularly strategic work now.
Travis Wood
Okay, but in the magnitude, are you suggesting that, that could be plus/minus 5000. Is that a fair way to think about volume side of that?
Ian Dundas
Yes. That's not a bad number to think about.
Travis Wood
Okay. And then costs in North Dakota.
You had somewhat alluded to -- activities up, but still down from 2014. Can you help us understand how you're sitting for the two rigs that you're running, the completion crew in terms of, kind of, fixing and some of those costs through this year?
And then at what point -- is there any point where we could potentially see activity from Enerplus be curtailed a little bit because of cost?
Ian Dundas
So I think Ray painted a pretty good picture of -- I mean, clearly, there's -- cost come up a little bit from the absolute lows. There were moments in there where things -- you could get work done on a one-off basis really, really cheap.
So it's a little bit up there off of those levels, but pretty stable. A little pressures here and there.
And when we sort of roll it all up, we don't think you see much of a change for us relative to capital efficiencies and the bigger movers are just decisions we're making around completion design. So could we see inflation impact our activity?
I don't think it's very likely this year. We're reasonably insulated from some of it.
Drilling's locked. We have fixed pricing on drilling.
Proppant supply cost is largely locked in. Maybe some of the bigger movers would be around pressure pumping.
And it's tighter out there. We've explored the possibility of locking that stuff up over time and haven't liked what that has looked like.
We haven't liked it and some of the research providers haven't liked it either. And I think we're at a really good place to be able to manage it.
The margins are really, really strong right now. If there are some cost pressures there, we will be able to manage those.
We said about six months ago that if you think the price of oil is $50, think about a 5% inflationary hit in North Dakota. Maybe that has -- maybe that hasn't quite borne out, but it's hard to call.
I really think one of the best ways to think about this, figure out what's going to happen in the Permian. Whatever happens in the Permian, there will be less inflation in the Bakken.
And then when you think about that inflationary number, we will be in a position to mitigate a lot of that based upon how we're positioned in the Bakken.
Travis Wood
Okay. And then last question.
Somebody had asked that around the free cash flow potential and you had suggested the buyback. Is there -- I know the dividend is very nominal, but is there any strategic reason that that's still in place, given the shareholder change over the last couple of years?
Ian Dundas
Is there a strategic reason? Every shareholder...
Travis Wood
Around the dividend.
Ian Dundas
Yes. I know, I understand.
I mean, everyone I know likes money. And so we didn't turn the dividend off.
The biggest strategic reason wasn't the shareholder base. The biggest strategic reason was, it was a symbol of capital discipline and full cycle returns for shareholders.
Obviously, if you can continue to grow at the levels we're growing at, that map trumps dividend increase. But there will be a day when maybe the better answer is a return of capital to our shareholders.
And every shareholder that I talk to is interested in that, independent of whether they're growthy or not growthy. So not at all interested in turning it off.
We can afford it. I thought you're going to going to when you're going to increase it.
I'm also not interested in increasing it today because we've lots of ideas around how we can spend money. And so strategically, that's more important to us.
But it's a tool and it's a tool that's consistent with the broad strategy of a focus on shareholder returns. And maybe that's a little more topical these days, but it's how we've been thinking for years now.
Travis Wood
Okay. No, I think -- so to understand is it kind of put you on the spot to get an appreciation for the buyback versus that dividend increase in -- on -- kind of on strip numbers...
Ian Dundas
Today, based on where our shares are valued, based on our free cash flow profile, based on the growth we see and based on some of the interesting opportunities we see to maybe build inventory, share buyback is way more interesting than dividend increase. And if we're successful in this plan in the fullness of time, we will be able to do all of those things.
We will be able to buy shares back. We will be able to increase the dividend over time and continue to grow and it'll be awesome, Travis.
Operator
Your next question comes from Dennis Fong from Canaccord Genuity.
Dennis Fong
Just a couple of quick questions. First on just completion techniques in North Dakota.
I know you guys were experimenting with higher frac intensity. I'm just wondering if you have any additional color on some well productivity results that you can kind of share on that side?
Ian Dundas
I don't think there's any specifically where we've been out today, Dennis. It's the same thing we've been talking about for a while.
I don't know if you recall, Ray underlined a couple of quarters ago, they talked about -- we're almost thinking like it's a custom solution by DSU and that's maybe we're stating a little bit practically, but what works in a very small area on some levels and yet -- but the rock moves around and new -- oil emplacements around quite a bit too. So what works in one area might not be the optimal solution in other.
So we're just continuing to test those things. May be the single biggest question for us today might be, as you're thinking about down spacing, which for us -- that means six wells in the Bakken and four in the Three Forks.
If you're thinking about down spacing, can you get away with a smaller frac? Or -- and there will be a lot of money on the table if you can make that happen without deterioration of results.
So there's not a lot we're talking about that's new on that, but that continues to be something we test.
Dennis Fong
Okay. Okay.
And then just quickly on the DJ there. In terms of the next three wells, like how much more sciencing are you guys planning on doing for those next three?
And maybe -- like -- maybe an indication as to probably still in the first or second inning as to where you think you guys are with respect to the play in general and your thoughts there?
Ian Dundas
One well over 35,000 acres is -- it's the top of the first. Now we're not having to start from scratch and we know how to play baseball.
So we're looking at things that we've learned in other play concepts and including other parts of the DJ as well. So I don't know where we are in this, but there's lots of things we want to learn.
And if you think about the evolution of the shale plays, every play has got a nuance that's interesting. And what -- maybe you can take a similar approach in many of them and get economic wells.
But that's not necessarily the optimal solution. So we've got a lot of things to test.
We don't have a well into the Niobrara, so that's one. Earlier question on the call talked about subtleties around zones within.
You've got big questions around fluid composition, amount of fluid. So there's lots of stuff that's going to go on.
And that maybe gets you to place where you can declare commerciality and, sort of, take it to the next level. And there'll still be a lot of science that goes into that as we sort of look to optimize economics over time.
This place has so much resource and there are so many wells. You can never declare a victory on it.
And I think if you're not always thinking about science, you're missing an opportunity to improve.
Dennis Fong
Okay. Perfect.
And then just lastly, just here on the Alternative Minimum Tax side of it all. I think, kind of, middle, late or I guess at the beginning of the year, you guys had indicated about $85 million of expected refunds between 2018 and 2021?
We saw, obviously, a fairly significant chunk of it here. Is there any expectation on cadence for the remainder?
Jodine Jenson Labrie
Yes. So it's Jodi.
The way it's scheduled out as you get the first year, you get 50% and then the following year you get another 50% of the remaining balance out for four years. So it starts 2018, ends in 2021 and the $85 million we press release is U.S.
dollars and our financials are just showing the Canadian equivalent of half of that.
Operator
Your next question comes from Brian Kristjansen from Macquarie.
Brian Kristjansen
Just wanted to follow up. Earlier on the call you mentioned that after the 30-day shut-in of the DJ well, it came back at 550 barrels a day, was that barrels of oil or BOE equivalent?
Raymond Daniels
It was BOE, Brian.
Operator
Your next question comes from Dan Healing from the Canadian Press.
Dan Healing
I was looking for more detail around the realized prices for the oil from North Dakota. The press release says that there were improvements in transportation.
And I think, Eric said something about -- it also benefited from the Canadian oil transportation system. Can you expand a bit on it?
Eric Le Dain
Yes. It's fairly straightforward.
There's less light oil coming from Canada during the fourth quarter. And as a result, there was increased demand for Bakken oil to feed the U.S.
refinery.
Dan Healing
Okay. So that helped the prices a bit then?
Eric Le Dain
That's right.
Dan Healing
Okay. And on a strategic point, I was wondering if I could ask Ian.
What would it take for you to return to Canada or start spending more money in Canada?
Ian Dundas
Yes. We didn't make an anti-Canada call.
We just saw better opportunity in the U.S. And then the nature of the assets we had in Canada completely independent of the jurisdiction caused us to sell those.
They weren't scalable and weren't large enough. We didn't see them competing.
Over time, that's turned out to be a really good call when you sort of layer on some of the other complexities that are happening in Canada versus the U.S. The U.S.
market is highly supportive to industry. That's manifesting itself in strong pricing in an improving regulatory environment.
You see the tax benefits that Jodi was talking about earlier. So that's -- it's all -- we're pretty well positioned.
And by effectively ever standard, we're a U.S. company now.
So could we expand in Canada at a point? It's certainly a possibility.
The Canadian regulators could make life a lot better for Canadians if they start to really pay attention to what's happening in the U.S. The Canadian projects actually -- there's world-class rock and there's world-class people and there's some interesting opportunities here, but it just needs to compete.
I really don't care too much where we spend money if we can operationalize it effectively and it competes economically with our other choices. And for the last while, it's been pretty easy to put money into the U.S.
and it's been harder to put money into Canada. I suppose we might have a bit of a competitive advantage to have a window on it, at least, to see how things unfold here.
But you can see from our project -- spend levels today, 90% of our money is going into the U.S. Just it's winning.
Operator
[Operator Instructions]. We do not have any questions over the phone at this time.
I will turn the call over to the presenters.
Ian Dundas
Great. Well, thank you, everyone, for dialing in today, your participation and your continued support.
Everyone have a great weekend. Cheers.
Thank you.
Operator
This concludes today's conference call. You may now disconnect.