Enerplus Corp (ERF) 2013 Q2 法說會逐字稿

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 Corporation 2013 second-quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions)

Ms. Jo-Anne Caza, Vice President Corporate Investor Relations, you may begin your conference.

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 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 www.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 will open up the phone lines and answer any questions you may have, and we will also have a replay of this call available later today on our website.

So with that, over to you, Ian.

Thanks, Jo-Anne. Good morning, everyone. Thanks for joining us on the call today. We are pleased to report another strong quarter for Enerplus. Production is ahead of expectations, at just over 90,000 BOE a day, 3% higher than 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 to the Wilrich. Ray will provide some additional color on our operations shortly.

Our corporate netback also improved, up 15% during the quarter, primarily due to stronger pricing. Growth in our production and an improved netback drove our funds flow up by 20% from the first quarter to CAD205 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 CAD10 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 gas production. But the productivity of the Marcellus is largely to blame for these widening differentials. The discounts to NYMEX on our Marcellus production widened to about CAD0.18 during the quarter, and we could see further widening for the remainder of the year. Fortunately, about 15% of our gas volumes in the US are from the Bakken, and earn a premium to NYMEX given the higher heat content.

Turning to hedging, we've added additional crude positions, and now we have fixed price hedges in place for 75% of the remainder of our net 2013 oil production at just over CAD100 a barrel, and have just over 50% of our net 2014 volumes hedged at approximately CAD93 a barrel. On the natural gas side, we are hedged on about one-third of our remaining expected net 2013 gas volumes at CAD3.50 an Mcf, and on about 25% of our expected 2014 net production at $2.17 an M, US dollars.

Year to date, we spent just under 50% of our total capital budget. We are 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 are increasing our guidance on cash equity-based compensation expenses from CAD0.45 a BOE to CAD0.60 a BOE. Lower capital spending and higher funds 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 non-core asset sales.

To date, we've signed agreements to sell approximately CAD160 million of non-core producing assets with approximately 1,700 BOE a day of associated production. In addition, we've raised another CAD35 million in proceeds from the sale of non-core facilities in the US. We have also had some success on the acquisition front, as we closed a 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 CAD140 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-funds flow ratio was 1.6 times at the end of the quarter, down from 2 times a year ago. If we look to the remainder the year, we expect to see some production decline in the third quarter given the slower drilling activity in Q2, as well as planned [plant] maintenance and divestments. Despite the sale of non-core production to date, and some additional asset sales that we would like to do in second half of the year, we are 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 liquids 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.

Good morning, everyone. Enerplus currently qualifies as a foreign private issuer with the Securities and Exchange Commission in the US. The principal advantage of being a foreign private issuer is the ability to use the multi-jurisdictional disclosure system called MJDS. MJDS allows Canadian companies who are listed on a US exchange, such as Enerplus, to file largely unmodified versions of their Canadian disclosure documents in satisfaction of many of their US disclosure obligations. Given our substantial US shareholder base, and the growth of our US 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 US residents, and over 50% of our assets are located in the US.

As a result, we believe that we will become subject to US domestic reporting requirements for all US 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, US regulators would consider us a US 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 US generally accepted accounting principles instead of IFRS beginning with our December 2013 year end including the comparative periods for 2012 and 2011. The US GAAP financial statements will satisfy our Canadian filing obligations, and IFRS statements will no longer be prepared.

We expect the most significant differences between US 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 cost, G&A, netbacks or adjusted payout ratios.

In accordance with US 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 US 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.

Thanks, Rob. Good morning, everyone. As Ian pointed out, this is another strong quarter operationally. Our assets are delivering in all our core areas. We spent CAD140 million of capital, and drilled 10 net wells, and 18 net wells were brought on stream.

Let's start with US oil. We invested more than 50% 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 a 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 frac 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 design 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 non-core asset sales. And we experienced minimal impact on our production due to the flooding in southern Alberta.

Shifting to natural gas, in the US, 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 for 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 have generated approximately CAD34 million of funds flow from the Marcellus, essentially fully funding our capital program.

Production from Canadian gas assets also increased this quarter. We saw a 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 into 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 to 80 million cubic feet per day.

In the Montney, we are 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.

Thanks, Ray, and I'll switch back to English for the remainder of this call. 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 non-core assets.

Now, as you are aware, we've been pursuing a joint venture or a partial sell down of our Duvernay and Montney assets over 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 are undertaking in the second half of this 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 are 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 are now happy to take your questions.

(Operator Instructions)

Cristina Lopez, Macquarie Securities.

Congratulations on the quarter. 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?

Sure, Cristina, we will turn it over to Eric to talk to you about that.

Sure. I think as you say, Cristina, 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 take-away access to the marketplace.

As I think probably everyone is aware, the basis, in particular on Tennessee, gas pipelines on 4, line 300 widened considerably in June. And what is happening through July and into August is it is actually we are seeing a widening extend from the Tennessee pipeline through -- even into the Transco points of market. We're -- I think we're seeing something like still down $1.50 an MMBtu out of Tennessee, and we're seeing markets on -- even into Transco at -- in the, say, the minus $0.50 range on the spot market. Our pricing for June was all-in rolled in minus $0.41 an 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.

Thank you. 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?

We haven't given that number, Cristina. But I think we're being pretty transparent that we're positioned to beat the 85,000 AA, and I guess we're still reaffirming our exit of 84,000 to 88,000. So, I think you can say we would probably be above 85,000, and potentially to the high end of that exit range.

Is there -- and then my last question -- is there any plans for drilling a exploration well into the lower Three Forks following the results that we've seen from Continental this week?

We're looking at that very carefully. Obviously, it's quite exciting for us. We have acreage that is relatively proximal in the northern ends of -- certainly in the northern ends of our play. This year we've got about one-third of our drilling is targeted to the Three Forks. Nothing in the second bench at this moment, but I would say it's potential we are looking at very carefully, and pretty likely a Q -- 2014 event for us.

Excellent, thanks.

Greg Pardy, RBC Capital Markets.

Indeed a very, very nice quarter. Just a couple of questions -- maybe first to start with the Marcellus. Can you let us know just how many wells you would've 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? Thanks.

Sure. So, maybe we will split this between Ray and I. The plans for the Wilrich -- we could see taking that production -- 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.

We have the 10.5 non-operated wells not tied in. There's a number of different reasons for that. There is operational reasons, there's waiting for price, and a few of them may never be tied in.

Okay, so -- sorry, Ray, that was 10.5?

10.5 net of non-operated.

Okay, and then the reason that they would not be -- why wouldn't they be tied in? Or is it just the economics just aren't as competitive as some of the new stuff or --

That's right. There is 169 gross wells out of that lot that we get 10.5 from.

Okay. Got it.

So there's ones that we get very few that a small working interest in.

Okay. And maybe just for planning assumptions now, 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?

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 has been very concentrated in Bradford and Susquehanna, and even within those areas, it's high graded. These would be plays that are 10 to 12 Bcf kind of plays. And on an unconstrained basis, you could see some of the rates that could 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 been part 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 some of the basis discussions and pricing that we're seeing recently.

Okay. And maybe just last question. (multiple speakers) Oh, go ahead, Ray.

It's Ian. I was just going to say just one more thing. If we look at those gross and net wells, the vast majority of them will come on. And it's just effectively been timetables, but if you go back over time, and the amount of delineation activity, some of those wells would have been the first well into an area. And then there is no growth follow-up. It's gone, associated with that, as the play has been cored up and high graded over the last couple of years.

Okay. (multiple speakers)

[And on that] --

Sorry, go ahead.

I was just going to say -- I would also add that now that we are through the carry commitment, we have this ability to take a look at the individual wells that we are going to participate in, and decide whether or not we will consent. So we have that ability to really high-grade our capital spending, and make sure that we're spending in those areas where we will see the best economic return.

Okay, very good, very good. And last question for me is -- the 60 million, Ian, that you referred to is -- I don't want to pin you down too much, but is that a number that you could see getting to by, say, 2015 exit?

What was 60? (multiple speakers)

I think it was the well rate.

No, no, that is not an exit. That is 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 then that's really going to impact the ultimate develop 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.

Great. Thanks, all.

Kyle Preston, National Bank.

Congratulations on the quarter. I've got a few questions here. The first one just relating to your potential asset sales here in the second half of the year. Can you give us an indication on what sort of volumes we would be looking at, if you did indeed sell those assets?

No. (laughter)

Okay.

No, I get the issue. I get the issue. We spent a lot of time thinking about how we were 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 counts for the vast majority of our production. But there are 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 is where the market has been. And when we look at the 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 are subject to the vagaries of the A&D market right now, because it's hard to get deals done. We've done a good job on that, but it has 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 you look at that combination of events, and it makes it difficult to call, and so we 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.

Okay, thanks. Next question here just related to the infrastructure that you sold in North Dakota. Is that going to have any impact on your operating costs or transportation and realized pricing going forward?

A little bit. You won't really see it corporately, though. So, as people may understand, our infrastructure in North Dakota is largely owned by third parties. That is 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 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 structure.

So, at the margins, it moves the corporate numbers, but it's pretty small. Think CAD0.10 corporately. It's pretty modest.

Okay, so immaterial there. Last question here just relating to your comment about suspending the JV process on the Montney and the Duvernay. Can you just expand on that, and is this something that you're looking at now as a potential asset to develop yourself, or you're just delaying that process?

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, a long time-table 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 was not part of our plan, but we had to do that. And so, you look at all of that, and the changed -- the efficiencies, the improving in the growth profile that's happened, you look at the Laricina 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 it -- look at those assets, and realize they will benefit from some additional delineation activity, feel it's easier for people to understand where these assets -- where we are at this moment. Will we revisit it again? For sure.

And I think it's, 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 were going to develop those in a rapid timetable. So they are parked, but we still have the same sort of strategic perspective on those assets at this moment.

Okay, great. Thanks a lot.

Patrick Bryden, Scotiabank.

Just curious if you can maybe provide a little bit of elaboration on your Bakken longs and the Three Fork longs, and how those occurred in terms of -- were they in sweet spots? And then I would be most interested in terms of how the relative economics compare with one another, and I'm happy to hear the answer in Scottish. (laughter)

There will be a translation in English afterwards. So, no, Pat, these wells weren't chosen to be in sweet spots. They were pre-planned, and as we developed our thinking around completions and the development of the completion design, it fell upon these particular wells. So, no, they are not chosen as sweet spot wells. And, in fact, the first two that we did still had the reduced number of frac stages at 28. And these wells are very strong for that area that they are in, which we don't see as prolific as other parts of our field there. So, we do believe that this technique is producing improvement, absolutely.

That's perfect. And then, any comment on how the Bakken versus Three Forks economics compete with one another?

As we look across our field -- up in the north area, we see the Three Forks as being very -- 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 is a balance in there part right across our play. We still -- we'll get more wells into the Bakken. We know more about the Bakken. Ian talked about the second bench, and doing a bit more work on there next year. We are doing some coring, so we will get a lot more information over the next 6 to 12 months to give us a better understanding of what that potential of the Three Forks could be.

Perfect. Thank you. 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?

So, we have three non-operated partners, two of which are more significant. As we look at how their activity and tone has changed from, I guess, 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.

So, I would say -- 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 portfolio -- our marketing portfolio, and we are positioned to do much better than many. If you have no access to anything other than the spot market, it would be a problem for you. But again, netbacks coming under a little more pressure than we would have anticipated. So the margins, would that slow it down a bit? It might slow it down a little bit. So, I would say consistent-ish with where we would have been a year ago.

Okay, perfect. Thanks for the English and the Scottish. (laughter)

I didn't say I gave you good English.

(Operator Instructions)

A quick clarification, sorry -- to Greg's question. Greg, I think you asked what the Wilrich production was? I think I said 25 million a day. It was actually about 30 million a day.

Dirk Lever, AltaCorp Capital.

Thank you very much, and congratulations on your quarter. I wanted to focus on your land position and your inventory when you look forward. So you've got some non-core assets that are up for sale, your debt now is at a low level. How do you see your position? 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?

Thanks, Dirk. We have -- so, let's talk about the four core areas. We will start in the US So, in the US, although the Marcellus is core, all that we feel is core within that is the non-operated 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 are bringing on somewhere in the neighborhood of 15 net wells a year, we've quantified contingent resource of 100 -- that includes 187, 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 [and core up] positions within that. But we've got growth locked in front of us for quite some period of time, so we will 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 -- certainly in our area, it 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 is all adding to the opportunity set. I would be happier to have more of it, but it's been very pricey. And so, we would like to add to it, but we don't feel panicked to do it, and obviously won't do it if the economics don't make sense when you look at the acquisition cost.

Turning to Canada, in the waterfloods -- continue to look for opportunities to add to that portfolio. If you look at our reserve base, we effectively see something that looks like a double of the reserve picture in the waterfloods, so 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 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 than 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. This is all effectively 100% working interest stuff. I'm sorry, 55,000 was the Wilrich.

So, we are continuing looking 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 a drier -- we see good economics even in this market.

The Montney is a great asset, but it is drier. And then the Duvernay is a wild card. 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 still focused in the operating groups and business development groups looking for opportunities to bring things in.

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 is it's got to make the portfolio better. So it is going to displace something out the back end. All that being said, I think it is a really interesting opportunity out there right now. It is clearly a buyer's market in many instances, and so we are looking for chances to be opportunistic.

Excellent, thank you very much for that, Ian.

(Operator Instructions)

And we have no further questions at this time. I turn the call over to the presenters.

Well, once again, appreciate you joining us on this summer morning, and enjoy the rest of your day. Thank you, everyone.

This concludes today's conference call. You may now disconnect.