Aug 9, 2013
Executives
Jo-Anne Caza – VP, Corporate & Investor Relations Ian Dundas - President and CEO Ray Daniels – SVP, Operations Eric Le Dain – SVP, Corporate Development and Commercial Rob Waters - SVP and CFO Mike Politeski - Treasurer and Corporate Controller
Analysts
Cristina Lopez - Macquarie Greg Pardy - RBC Capital Markets Kyle Preston - National Bank Patrick Bryden - Scotiabank Dirk Lever - AltaCorp Capital
Operator
At this time, I would like to welcome everyone to the Enerplus Corporation 2013 second quarter results conference call. [Operator instructions.]
Ms. Jo-Anne Caza, vice president, corporate investor relations, you may begin your conference.
Jo-Anne Caza
Thank you, operator, and good morning, everyone. Thanks for calling in this morning.
Ian Dundas, our president and CEO will start the call off this morning, and joining him we also have Ray Daniels, our senior vice president of operations; Eric Le Dain, our senior vice president of corporate development and commercial; Rob Waters, our senior vice president and chief financial officer; and Mike Politeski, our treasurer and corporate controller. Before we get started, please note that this call will contain forward-looking information.
Listeners should understand the risks and limitations of this type of information and review our advisory on forward-looking information found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and EDGAR and available on our website at enerplus.com. Our financial statements were also prepared in accordance with International Financial Reporting Standards.
All financial figures referenced during the call are in Canadian dollars, unless otherwise specified, and all conversions of natural gas to barrels of oil equivalent are done on a 6-to-1 energy equivalent conversion ratio, which does not represent the current value equivalent. Following our review, we’ll open up the phone lines and answer any questions you may have, and we’ll also have a replay of this call available later today on our website.
So with that, over to you, Ian.
Ian Dundas
Thanks, Jo-Anne, and good morning everyone. Thanks for joining us on the call today.
We’re pleased to report another strong quarter for Enerplus. Production is ahead of expectations at just over 90,000 BOE a day, 3% higher in Q1 and 10% higher than the second quarter of last year.
We continue to see strong results across our core areas, with the most notable growth coming from the Marcellus and the Wilrich. Ray will provide some additional color on our operations shortly.
Our corporate net back also improved, up 15% during the quarter, primarily due to stronger pricing. Growth in our production and an improved net back drove our fund flow up by 20% from the first quarter to $205 million.
Although WTI was relatively flat quarter over quarter, our realized crude pricing was 12% higher from Q1, largely due to improved Canadian differentials. Crude oil differentials in North Dakota and Montana averaged about $10 a barrel for the quarter, slightly wider than the first quarter, but still under our forecast for the year.
Our realized natural gas pricing also increased, up nearly 20% over the first quarter. However, we have seen a recent widening of the AECO basis differential and the differential on our [Marcellus] [ph] gas production.
The productivity of the Marcellus is largely to blame for these widening differentials. The discounts to NYMEX on our Marcellus production widened to about $0.18 during the quarter, and we could see further widening for the remainder of the year.
Fortunately, about 15% of our gas volumes in the U.S. are from the Bakken, and they’re at a premium to NYMEX given the higher heat content.
Turning to hedging, we’ve added additional crude positions and now have fixed price hedges in place for 75% of the remainder of our net 2013 oil production at just over $100 a barrel, and have just over half of our net 2014 volumes hedged at approximately $93 a barrel. On the natural gas side, we are hedged on about a third of our remaining expected net 2013 gas volumes at $3.50 in Mcf and on about 25% of our expected 2014 net production at $2.17 [an M] [ph] in U.S.
dollars. Year to date, we’ve spent just under half of our total capital budget.
We’re tracking our original capital spending guidance, but production is ahead of expectations, pointing to an improvement in capital efficiencies. Operating costs and G&A are also tracking our guidance.
However, with the increase in our share price this year, we’re increasing our guidance on cash equity based compensation expenses from $0.45 a BOE to $0.60 a BOE. Lower capital spending and higher fund flow have resulted in a dramatic improvement in the sustainability of our business.
Our adjusted payout ratio was 89% in the quarter, and 106% year to date before accounting for the positive impact of our noncore asset sales. To date, we’ve signed agreements to sell approximately $160 million of noncore producing assets with approximately 1,700 BOE a day of associated production.
In addition, we’ve raised another $35 million in proceeds from the sale of noncore facilities in the U.S. We have also had some success on the acquisition front, as we closed the tuck-in acquisition of additional working interest in our operated Pouce Coupe Boundary Lake waterflood oil property.
If you look at our total A&D activity over the course of the year so far, we have agreements in place that we expect will generate net proceeds of approximately $140 million for 1,300 BOE a day of net production sold, with some modest infrastructure as well. These transactions are all designed to improve our portfolio and obviously further strengthen our balance sheet.
Our debt to fund flow ratio was 1.6x at the end of the quarter, down from 2x a year ago. If we look to the remainder of the year, we expect to see some production decline in the third quarter, given the slower drilling activity in Q2, as well as planned maintenance and divestments.
Despite the sale of noncore production to date, and some additional asset sales that we would like to do in the second half of the year, we’re maintaining our annual average production guidance at 85,000 BOE a day. However, we are halfway through the year, and we’ve averaged about 88,600 BOE a day for the first six months.
For those doing the math, we clearly have the potential to exceed our annual average production guidance if we don’t complete additional divestments. We also expect our liquid weighting to change from 50% of total volumes to 48% as a consequence of our strong gas production growth and the oil weighted nature of our divestments.
Overall, we are on track with our guidance targets, and are well-positioned for the remainder of the year. I’ll now turn the call over to Rob to provide some detail on the pending change in our foreign private issuer status.
Rob Waters
Good morning everyone. Enerplus currently qualifies as a foreign private issuer with the Securities and Exchange Commission in the U.S.
The principal advantage of being a foreign private issuer is the ability to use the multijurisdictional disclosure system called MJDS. MJDS allows Canadian companies who are listed on a U.S.
exchange such as Enerplus to file largely unmodified versions of their Canadian disclosure documents in satisfaction of many of their U.S. disclosure obligations.
Given our substantial U.S. shareholder base, and the growth of our U.S.
assets, we expect we will no longer qualify as a foreign private issuer as of January 1, 2014, as over 50% of our shares are held by U.S. residents and over 50% of our assets are located in the U.S.
As a result, we believe that we will become subject to U.S. domestic reporting requirements for all U.S.
filings completed after January 1 of 2014. This change in filing status is not expected to impact our operations, but rather, it will change the way in which we report our results.
An easy way to interpret the loss of foreign private issuer status is that Canadian regulators would continue to view us as a domestic Canadian company and expect us to comply with their rules. Meanwhile, U.S.
regulators would consider us a U.S. domestic company and expect us to comply with their rules.
We get the best of both regulatory worlds, so to speak. We expect our financial statements will be presented in accordance with U.S.
generally accepted accounting principles instead of IFRS beginning with our December 2013 year-end, including the comparative periods for 2012 and 2011. The U.S.
GAAP financial statements will satisfy our Canadian filing obligations and IFRS statements will no longer be prepared. We expect the most significant differences between U.S.
GAAP and IFRS for Enerplus will relate to the accounting for our oil and gas assets, specifically impairment calculations and the accounting for dispositions. The change in accounting principle may impact our earnings, however we don’t expect a material change to our key performance indicators such as funds flow, debt levels, capital spending, operating costs, G&A, net backs, or adjusted payout ratios.
In accordance with U.S. protocol, our sales revenue and volumes would be presented on a net after royalty basis, but we expect to provide supplementary disclosure on a gross basis to facilitate comparisons with Canadian peers.
Our reserves information would also be prepared and filed under both U.S. and Canadian standards.
Again, I emphasize that we expect these changes to take place for our 2013 year-end reporting cycle. Enough about regulations, let’s get back to our operating results.
So I’m going to turn the call over to Ray to give you some highlights on the operations side.
Ray Daniels
Thanks, Rob, and good morning everyone. As Ian pointed out, this was another strong quarter operationally.
Our assets are delivering in all our core areas. We spent $140 million of capital and built 10 net wells and 18 net wells were brought on stream.
Let’s start with U.S. oil.
We invested more than half of our capital in the Fort Berthold region this quarter. As a result, production was up 4% quarter over quarter to just over 15,000 barrels of oil per day, with 4.7 net wells drilled and 6 net wells completed in both the Bakken and Three Forks.
The majority of these completions were done late in the quarter, and now that we have effectively managed lease expirations, we are able to focus on more efficient pad drilling and further the exploitation of the most promising areas of the field. We mentioned last quarter that we were going to test a new completion technique in a couple of wells.
I am pleased to report that we saw meaningful improvement in well performance and have now used that design on six wells, and are very encouraged by the results. Our last [long] Bakken well was completed using white sand in 37 frack stages.
The 30-day IP rate on this well was 1,300 barrels a day, the second best 30-day rate we’ve achieved to date. Our last Three Forks completion, with the same completion design, had an IP-30 rate of 1,000 barrels of oil a day and is our most prolific long Three Forks well drilled to date.
Having said that, we are not finished looking for improvements, and in fact we have increased the sand concentration again on two wells that are being pumped as we speak. As for costs, we continue to see operational improvements in a number of places, and are realizing costs that are slightly better than the 10% improvement we anticipated last quarter.
We will continue to look for opportunities to reduce costs further, without negatively impacting profitability. Based upon the growth in production over the past three years, we anticipate moving into a positive cash flow position in this region in 2014.
In Canada, our oil assets continue to meet expectations. Production averaged just over 21,300 barrels of oil equivalent a day, down slightly from the first quarter as a result of noncore asset sales.
And we experienced minimal impact on our production due to the flooding in southern Alberta. Shifting to natural gas, in the U.S.
the second quarter saw another strong showing from the Marcellus, with production averaging about 88 million cubic feet a day, up over 10% from quarter one. The Marcellus has become a more meaningful part of our portfolio, and now accounts for about 30% of our corporate natural gas production, up from about 15% last year.
Drilling activity continues to be focused in Bradford and Susquehanna counties, where we are seeing the best performance to date. Roughly 65% of the wells brought on stream during the quarter in our core areas had an average 30-day IP rate in excess of our 12 Bcf type curve.
The 30-day IP rates of these wells ranged from 8 million cubic feet a day to 21 million cubic feet a day. With the upswing in natural gas prices, capital cost reductions, and improvements in well productivity, the economics on these wells are rivaling some of our Bakken oil wells.
To date, this year we’ve generated approximately $34 million of funds flow from the Marcellus, essentially fully funding our capital program. Production from Canadian gas assets also increased this quarter.
We saw 3% increase from the first quarter due to the impact of the successful Wilrich drilling program in quarter one. We plan to recommence Wilrich drilling later in the year with another two horizontal wells in the fourth quarter, in order to cost effectively transition the 2014 development program we have planned for that play.
With over 100 future drilling locations and access to infrastructure, we see the potential of taking our production level to about 60 million cubic feet a day to 80 million cubic feet a day. In the Montney, we’re planning two horizontal wells during the fourth quarter and a further two early the following year where we will test both the upper and lower zones.
We expect to complete all four wells in 2014 and are pursuing plans to bring these wells on stream later in the fourth quarter of 2014. We have two vertical wells planned for the Duvernay this year, with one well currently underway.
And with that, I’ll turn it back to Ian.
Ian Dundas
Thanks, Ray. Before we open for questions, I just want to summarize a few points.
This was another solid quarter for Enerplus. We delivered strong production and funds flow growth while remaining disciplined in our capital spending.
We continue to improve our operational focus, which is driving improved efficiencies. Although our focus is much improved, we see an opportunity for further rationalization and will continue to look for opportunities to sell noncore assets.
And as you are aware, we’ve been pursuing a joint venture or a partial sell down of our Duvernay and Montney assets during the last year. We’ve decided to suspend this process at this time.
There’s two reasons for this. First, the additional delineation activity we’re undertaking in the second half of the year will increase our knowledge of the potential of the play, and we believe will help unlock value regardless of the decision we make on these assets.
And secondly, we’ve made such significant progress on changing the financial sustainability of the company we’re now in a position to do this. We believe our results over the last few quarters are consistently demonstrating an improvement in capital efficiencies and operational execution.
The sustainability of our business has improved dramatically from this period last year, and we feel confident that our dividend is sustainable at the current level. Thank you for your interest in Enerplus this morning, and we’re now happy to take your questions.
Operator
[Operator instructions.] Your first question comes from Cristina Lopez from Macquarie.
Your line is open.
Cristina Lopez - Macquarie
Just a few quick questions. The first one has to do with the current Marcellus pricing.
Can you give us a benchmark as to what you’re receiving currently in the Marcellus for your pricing, understanding that most of it is under contract?
Eric Le Dain
As you say, we are contracted. However, those contracts, keep in mind, are based on the indices, largely, the great majority, Dominion South, which is the strongest index in that area.
What that contracting assures us of is takeaway access to the marketplace. As I think probably everyone’s aware, the basis in particular on Tennessee gas pipeline, zone four, line 300, widened considerably in June.
And what’s happening through July and into August is we’re seeing a widening extend from the Tennessee pipeline even into the Transco points of market. I think we’re seeing something like down $1.50 U.S.
in MMBTU out of Tennessee, and we’re seeing markets even into Transco in the minus $0.50 range on the spot market. Our pricing for June was all-in, rolled in, minus $0.41 U.S.
in MMBTU, and we see definite potential through the remainder of the summer period of the gas market to see those kind of levels or even wider.
Cristina Lopez - Macquarie
Also, if you were to undertake no asset sales for the remainder of the year, what would your production look like in the second half of the year, or sort of in line with your budget?
Ian Dundas
We haven’t given that number, but I think we’re being pretty transparent that we’re positioned to beat the 85 AA, and I guess we’re still reaffirming our exit of 84 to 88. So I think you can say we’d probably be above 85 and potentially to the high end of that exit range.
Cristina Lopez - Macquarie
Is there any plans for drilling an exploration well into the lower Three Forks following the results that we’ve seen from Continental this week?
Ian Dundas
We’re looking at that very carefully. Obviously it’s quite exciting for us.
We have acreage that’s relatively proximal in the northern end of our play. This year we’ve got about a third of our drilling targeted to the Three Forks.
Nothing in the second bench at this moment, but I’d say we’re looking at it very carefully, and it’s pretty likely a 2014 event for us.
Operator
Your next question comes from Greg Pardy from RBC Capital Markets. Your line is open.
Greg Pardy - RBC Capital Markets
First, to start with the Marcellus, can you let us know how many wells you would have brought online in the second quarter, and then what your backlog looks like there? And then maybe just shifting to the Wilrich, I just didn’t catch what your current production is and how you would see that program shaping up over the next couple of years.
Ian Dundas
The plans for the Wilrich, in the quarter it was in the 25 million a day range. We see taking that to 60 million, potentially higher.
It’s going to be a function of success and how broadly it is over our acreage block. On the wells behind pipe, partially completed, I’ll turn that over to Ray to take you through.
Ray Daniels
We have the 10.5 [net] [ph] non-operated wells, not tied in. There’s a number of different reasons for that.
There’s operational reasons, there’s waiting for price, and a few of them may never be tied in.
Greg Pardy - RBC Capital Markets
And why wouldn’t they be tied in? Or is it just the economics, they’re just not as competitive as some of the new stuff?
Ray Daniels
That’s right. There’s 169 gross wells of that lot that we get 10.5 from.
So there’s ones that we’ve got a small working interest in.
Greg Pardy - RBC Capital Markets
And maybe just for planning assumptions, what kind of an EUR and IP are you using, even though there’s probably multiple type curves for the Marcellus? How are you planning for it?
Ian Dundas
It’s area by area. And so we have a series of areas with type curves with, I’d say, ever-increasing levels of confidence in many of them.
This year the activity is very concentrated in Bradford and Susquehanna, and even within those areas, it’s high graded. These would be plays that are 10-12 Bcf kind of plays, and on an unconstrained basis, you can see some of the rates come on pretty dramatically from a planning perspective.
It’s tied to specific locations, and we’ve got pretty good visibility around that. And then it’s further tied to the nature of the specific infrastructure in the area.
And if you look at our corporate presentations, we’ve given a pretty good flavor for, we see relatively flat production in some of these areas. And so that’s sort of been part of how the teams have been managing it.
A type curve in one of these areas is sort of six months at 8 million a day flat, and you see some variability within that. Clearly one of the things that has been going on of late has been we’ve been exceeding that.
And generally good, but it’s also been impacting the basis discussions and pricing that we’re seeing recently. If we look at those growth in net wells, the vast majority of them will come on.
And it’s just effectively been timetables. But if you sort of go back over time, and the amount of delineation activity, some of those wells would have been first wells into an area, and then there’s no real follow up that’s gone on associated with that, as the play has been sort of cored up and high graded over the last couple of years.
Jo-Anne Caza
I’d also add that now that we’re through the carry commitment, we have this ability to take a look at the individual wells that we’re going to participate in and decide whether or not we’ll consent. So we have that ability to really highgrade our capital spending and make sure that we’re spending in those areas where we will see the best economic return.
Greg Pardy - RBC Capital Markets
Is the $60 million that you referred to a number that you could see getting to by, say, 2015 exit?
Ian Dundas
No, that’s not an exit. That’s a development plan over a couple of years kind of scenario.
If you look at what’s going on in the Wilrich, it’s really quite exciting. We’ve got 55,000 acres available to us, with various levels of delineation around it.
One area looks quite exceptional, and that’s where we’re going to be starting in our development. There’s other areas that we have less information on as well, and so you can see quite wide variability around how big this thing actually gets, and that’s actually really going to impact the ultimately development scenario.
But $60 million is not a bad number to think about in the context of a pretty risked way of thinking about this asset at this moment.
Operator
Your next question comes from Kyle Preston from National Bank. Your line is open.
Kyle Preston - National Bank
The first one, just relating to your potential asset sales in the second half of the year. Can you give us an indication on what sort of volumes we’d be looking at if you did indeed sell those assets?
Ian Dundas
No. [laughter] I get the issue.
And we’ve spent a lot of time thinking about how we’re going to communicate this point. When we look at our portfolio, we’re really pleased with the progress we’ve made, and we look at our core areas now, and that accounts for the vast majority of our production.
But there’s still assets that don’t fit our long term plans. To make things more complicated, there are gas volumes in there, and there are oil volumes in there.
So year to date, the focus has been on oil, because that’s where the market has been, and we look at that oil side of the equation. I could see looking at 1,000 to 2,000 barrels of oil that we could potentially have leave the fold.
Whether that happens or not is very difficult to predict, and we are not going to put ourselves in a position where we’re subject to the vagaries of the A&D market now, because it’s hard to get deals done. We’ve done a good job on that, but it’s still been hard to get deals done.
On the gas side, there are bigger volumes at play that don’t fit our long term plans. That has been very difficult to call, getting gas deals done.
And so if you look at that combination of events, it makes it difficult to call, and so we’ve settled on what we think is a very transparent way of communicating this, but positioning for people that we’re trying to get both gas and oil done this year. I think the most likely thing is it’s oil, because that’s where the market has been, but we are focused on focusing this portfolio.
Kyle Preston - National Bank
Ian Dundas
A little bit. You won’t really see it corporately, though.
As people may understand, our infrastructure in North Dakota is largely owned by third parties. That’s the original plan that we entered into, where our oil pipe and gathering lines are generally owned by a third-party gatherer down there.
That was how we started as the play developed over the last couple of years. Not all of the additional infrastructure was third-party financed, and so as we’ve talked about that over the last couple of years, some of the incremental spending that came from that, we’ve effectively taken all of that infrastructure and consolidated under that initial kind of structure.
So at the margins, it moved the corporate numbers, but it’s pretty small. I think a dime corporately.
It’s pretty modest.
Kyle Preston - National Bank
And last question, just relating to your comment about suspending the JV process on the Montney, can you just expand on that? And is this something that you’re looking at now as a potential asset to develop yourself?
Or are you just delaying that process?
Ian Dundas
We have not made a development decision. And some of the underlying conditions that caused us to think of this originally are still in place.
Specifically, big assets, lots of capital, long timetable associated with them. And so that hasn’t changed.
We still see an opportunity to partner or potentially sell down these, but if you go back a year ago and you look at all of the things that we were talking about doing relative to improving our sustainability, we’ve done all of those. And in addition, we had to cut the dividend, which wasn’t part of our plan, but we had to do that.
And so you look at all of that, and the efficiencies, the improvement in the growth profile that’s happened. You look at the [unintelligible] sale, you look at what’s happening relative to our spend, and you see we don’t have to do this at this moment.
And so when we step back and look at those assets, and realize they will benefit from some additional delineation activity, it’s easier for people to understand where we are at this moment. Will we revisit it again?
For sure. And again, you come back to both Montney and the Duvernay and you think about the timetable of development, and you think about Enerplus and our focus on capital discipline and financial stewardship, it’s very hard to see how we are going to develop those in a rapid timetable.
So they’re parked, but we still have the same sort of strategic perspective on those assets at this moment.
Operator
Your next question comes from Patrick Bryden from Scotiabank. Your line is open.
Patrick Bryden - Scotiabank
Just curious if you can maybe provide a little bit of elaboration on your Bakken longs and the Three Forks longs and how those occurred in terms of were they in sweet spots? And then I’d be most interested in terms of how the relative economics compare with one another.
Ray Daniels
These wells weren’t chosen to be in sweet spots. They were preplanned, and as we developed our thinking around completions and the development of the completion design, it fell upon these particular wells.
So no, they’re not chosen as sweet spot wells. And the first two that we did still had the reduced number of frack stages at 28, and these wells are very strong for that area that they’re in, which we don’t see as prolific as other parts of our field.
So we do believe that this technique is producing improvement, absolutely.
Patrick Bryden - Scotiabank
And then any comment on how the Bakken versus Three Forks economics compete with one another?
Ray Daniels
You know, as we look across our field, up in the north area, we see the Three Forks as being potentially very prolific, as good as the Bakken, maybe better, just looking at some of our competitor offset wells. And then down in the south, we see the Bakken as being a bit better.
So there’s a balance in there across our play. We still will get more wells into the Bakken.
We know more about the Bakken. Ian talked about the second bench and doing a bit more work there next year.
We’re doing some coring. So we’ve got a lot more information over the next six to 12 months to give us a better understanding of what that potential in the Three Forks could be.
Patrick Bryden - Scotiabank
And then just lastly, given all the dynamics in the gas market, and within the Marcellus specifically, any comment on the tone or pulse with what you’re seeing in terms of industry and partner activity and pace there, and how that trickles down to you folks?
Ian Dundas
We have three nonoperated partners, two of which are more significant. As we look at how their activity and tone has changed from the start of the budget cycle last October, two of them are spending at around the same pace, maybe a little bit slower than we thought, and one is increasing its activity a little bit.
But I would also say that this move in basis is wider than many of us thought. We all anticipated this was a possibility, and we look at our marketing portfolio, and we’re positioned much better than many.
If you had no access to anything other than the spot market, it would be a problem for you. But again, [FX] coming under a little more pressure than we would have anticipated, so at the margins, would that slow it down a bit?
It might slow it down a little bit. So I’d say consistent-ish with where we would have been a year ago.
One clarification, Greg. I think you asked what the Wilrich production was.
I think I said 25 million a day. It’s actually about 30 million a day.
Operator
[Operator instructions.] Your next question comes from Dirk Lever from AltaCorp Capital.
Your line is open.
Dirk Lever - AltaCorp Capital
I wanted to focus on your land position and your inventory when you look forward. You’ve got some noncore assets that are up for sale.
Your debt now is at a low level. How do you see you’re positioned?
Could you be adding to your core positions driving forward? How are you looking at the company and where do you need to add in?
Ian Dundas
Let’s talk about the four core areas. We’ll start in the U.S.
So, in the U.S., although the Marcellus is core, although we feel it’s core, what’s in that is a nonoperated position, because of the productivity we’re dealing with there, tier one versus our operated, which is not tier one. So when we look at that inventory, we’re bringing on somewhere in the neighborhood of 15 net wells a year.
We’ve quantified contingent resource that includes 184 net wells, and so see a decent inventory in front of us there. We continue to buy bits of land here and there, and consolidate in core positions within that, but we’ve got growth locked in front of us for quite some period of time, so we’ll be very opportunistic in connection with adding to those positions.
In the Bakken, we still see growth in front of us. At the current pace of activity, we could see six years of drilling in front of us.
The play seems to be getting better and better. If you look at some of the commentary out there, people are generally finding in the sweet spots that recoveries are going up a bit, and the view that the Three Forks is more prospective.
And so that’s all adding to the opportunities. I’d be happy to have more of it, but it’s been very pricy.
And so we’d like to add to it, but we don’t feel panic to do it, and obviously won’t do it if the economics don’t make sense when you look at the acquisition costs. Turning to Canada, in the water floods, continue to look for opportunities to add to that portfolio.
If you look at our reserve base, we expect to see something that looks like a double of the reserve that is in the water floods, through a combination of drilling and EUR. It’s a low growth profile, and if that profile were to shift, it would be probably associated with some kind of acquisition that would kind of shift that.
So focused on it, but, again, very value-oriented. And the last couple of deals that we’ve done, where we’ve consolidated working interest in these fields, we saw an opportunity to bring something that made economic sense to us.
So then the last piece of this would be the [deep basin] portfolio, broadly. We have a lot of opportunity there.
The Duvernay is 85,000 acres, the Montney 33,000 acres. We’ve got 55,000 acres in the Wilrich.
This is all effectively 100% working interest stuff. So we are continuing to look at opportunities to add to that, but you’ve got to be very realistic relative to the affordability and the timetables associated with those.
So we’ve got a lot of opportunity captured. We know we’ve got a strong dry gas inventory.
The Wilrich is so prolific that even though it’s drier, we see good economics, even in this market. The Montney is a great asset, but it’s drier, and then the Duvernay is a wildcard.
So some of our delineation activity this year is to understand and I guess further enhance our understanding of the liquids content in the Duvernay. And if that liquids content is at the higher end of our ranges, we’ve got a lot to deal with, and don’t need to bring anything else in.
But a lot of guys are still focused in the operating group looking for opportunities to bring things in. But the operational bar is higher than it has been to bring something in.
The how are you going to pay for it bar is high, and maybe most importantly, it’s got to make the portfolio better. And so it’s going to displace something else at the back end.
All that being said, I think it’s a really interesting opportunity out there right now. It’s clearly a buyer’s market in many instances, and so we’re looking for chances to be opportunistic.
Operator
[Operator instructions.] And we have no further questions at this time.
I turn the call over to the presenters.
Ian Dundas
Well, once again, we appreciate you joining us on this summer morning, and enjoy the rest of your day. Thank you, everyone.