Enerplus Corp (ERF) 2013 Q3 法說會逐字稿

Good morning. My name is Sarah, and I will be your conference operator today.

At this time I'd like to welcome everyone to the Enerplus Corporation 2013 third-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)

Thank you. I'd now like to turn the call over to our host, Ms. Jo-Anne Caza, Vice President, Corporate and Investor Relations. You may begin your conference.

Thank you, operator. Good morning, everyone. Thanks for calling in.

Ian Dundas, our President and CEO, will start us off this morning. And joining Ian on the call today is Ray Daniels, our Senior Vice President of Operations; Eric Le Dain, our Senior Vice President of Corporate Development and Commercial; and Rob Waters, our Senior Vice President and Chief Financial Officer.

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 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 the call available later today on our website.

Over to you, Ian.

Good morning, everyone.

I'm pleased to say we announced another strong quarter today, with cash flow and production exceeding expectations. As importantly, we continued to demonstrate strong capital performance. It was also an active period of A and D. We remain committed to building out our core projects that saw the top-off acquisition in the Marcellus this morning, as well as our decision to exit our undeveloped Montney land position.

So turning to some specifics now. Production side volumes were strong, up 8% from the same period last year, at around 88,000 BOE a day. Notably, we achieved record production in Fort Berthold. We averaged about 18,000 BOE a day up, that was up close to 20% from Q2, and was a key part of driving our liquids volumes to 48% of our total corporate volumes.

We remain extremely focused on capital discipline, and you can see that in our capital efficiencies. Spending was almost flat to the second quarter, at CAD146 million, with 70% of that directed to oil. Through the first three quarters we spent less than 70% of our full year capital program, but are delivering ahead of our budget.

Improved oil realizations and strong oil production drove another solid quarter of funds flow at CAD196 million, which is up 45% from Q3 last year. That combination of improving capital efficiencies and strong fund flow drove our adjusted payout ratio down to 97% of the quarter. It's about 103% for the year. Of course, this is calculated before the proceeds from our investments. Again, it's a big change from where we were last year when we were significantly outspending cash flow.

Turning to portfolio management, our portfolio management strategy remains unchanged. We continue to consolidate interests in our four core areas and look for opportunities to move non-core assets out. On the acquisition front, we did purchase some additional interest in the Wilrich this quarter, but the most significant acquisition was a top-up of additional working interest in our core, non-operated Marcellus properties.

We believe this is a strategic acquisition. We are adding to an existing core position in a proven, top-tier play. It's additional working interest in assets that we currently own. There's a decent amount of existing production, but we also see significant upside. We acquired store 17,000 net acres, producing just over 40 million a day of gas for CAD153 million. We see the majority of the current value in Bradford and Susquehanna Counties, where we are drilling wells in the 10 to 13 Bcf range.

Now we are not out with our 2014 guidance yet, but directionally I would expect activity levels in the Marcellus to be relatively similar next year compared to this year. Obviously, our spending will be a bit higher because of our increased working interest. At this point, we'd expect to spend maybe CAD40 million more in the Marcellus next year because of that acquisition. But this deal will be almost self-funding when we think what the increased cash flow that's going to come from these assets.

Now obviously a big issue is the pricing differential in the region. Supply growth has created a transportation bottleneck and put quite significant pressure on fuel prices. Now we do believe that the market will rebalance as infrastructure builds out, but that will -- that we will likely experience wide pricing differentials for the next few years. Now as we evaluated this transaction, we factored in wider differentials over the next several years, and the returns were still very attractive, given the relatively low purchase price, the large amount of production, and the quality of the inventory.

With our existing contracts, we received dominion point sales and non-New York pricing. When we blend in the acquisition, we expect differentials could range from CAD0.50 to CAD1 on our total Marcellus volumes next year. We expect to make good money on this deal over the near term, and the returns could be quite exceptional as the system balances out over the next few years. And the final point I would make on transaction is that we consider it to be a quite low-risk transaction, given that we, again, are already an owner in virtually all of these well bores.

This morning we also announced the sale of our undeveloped land position in the Montney. We have signed an agreement for the sale of our Julienne prospect in northeast BC. We're selling 33,000 net acres for CAD130 million. We have no production or reserves or contingent resource associated with this property. As a point of reference, we've invested about CAD50 million in this property since we acquired it. It equates to a sales metric of just under CAD4,000 per acre.

This is a good asset. It's focused. It has running room. The only issue is that the liquid content is lower than we were targeting. And as such, we don't see the economics being strong enough to compete for capital with our remaining portfolio. We are now targeting proceeds from dispositions of deals that we've signed up this year of CAD430 million, selling production of about 2,500 BOE a day.

Turning to the balance sheet, our financial position remains very strong, trailing 12-month debt-to-cash, debt-to-funds flow ratio fell to 1.2 times at the end of Q3. That's compared to 1.9 times for the same period last year, and this is before the sale of the non-core production we announced for CAD105 million on October 22 and the sale of the Montney position I just discussed. Now even with the higher spend profile in the fourth quarter, we would expect to be largely undrawn on our CAD1 billion bank revolver as we move to year-end.

I'll turn to operations now and give you some highlights in the quarter, starting with the Bakken. US oil now represents over 50% of our corporate crude volumes. As I discussed earlier, Fort Berthold production grew approximately 3,000 BOE a day, to a record 18,000 BOE a day in the quarter. As we have been discussing over the last quarter or two, our completion design has been evolving. We're moving to bigger fracs, more stages, and more profit, and we believe we are seeing a step change in initial productivity.

Our two most recent wells completed under this new approach are showing quite good promise. The Pinto Bakken long well -- it's a Bakken long well -- delivered a 30-day IP of 41,000 barrels. Our Mustang long well, which is a Three Forks well, delivered a 30-day IP of 35,000 barrels. These are top [depth-file] wells in the basin. The Bakken well rivals our best performance ever on a Bakken well, and the Mustang is the best Three Forks well we have brought on so far.

Cost performance also continues to improve. Drilling has been running about CAD4.3 million per well for wells done on the last three pads. This is down 10% from the start of the year. On the completion side, the average cost per stage of completion is about CAD200,000. This is 15% under where we were the start of the year.

Now our most recent wells, we are increasing stages. The Pinto and the Mustang that I discussed, those are 40-stage wells, with about 1,000 pounds of sand per foot. Cost on those wells with that completion design are about CAD12 million. This is a bit higher than we were in Q2, but with the increased productivity we think we are seeing, we think we'll see payout on that extra CAD0.5 million within a month. As we look out over the last quarter, we are moving to further test down spacing opportunities and lower Three Forks bench prospectivity.

So I guess the summary on Fort Berthold is Bakken productivity seems to be getting better. The first bench on Three Forks looks good across most of our acreage, close to the Bakken, actually, in the northern portions. There is a growing industry data set that down spacing beyond four wells per DSU is a real opportunity for us. And then finally, in terms of the lower benches of the Three Forks, we think there is an opportunity there and they will be productive, but we think for Enerplus, it's going to be a more limited opportunity, isolated to areas in the northern portion of the block, but we will be testing that through the back half of this year -- the back quarter of this year.

All right. Turning to Canada and the Deep Basin, as we said earlier, we acquired a bit of additional acreage in the Minehead area; 5,000 acres targeting the Wilrich. We now have about 60,000 net acres in the Wilrich play. We're now moving to a development stage in the Wilrich. We started a single-rig program. We have two wells planned in Q4, and that drilling will continue into next year.

In the Duvernay, we remain in a appraisal mode, but I will say we're cautiously optimistic. In the quarter, we drilled two vertical wells. We are now moving to drill two horizontal wells. One of those will be a reentry, keying off of the results of those vertical wells, with plans to tie these in in 2014, hopefully before breakup. Based upon core analysis, we are -- from those vertical wells -- we are targeting areas where we would expect free condensate yields of between 75 and 150 barrels per 1 million cubic feet of gas.

Finally I'll talk about the Marcellus. Production in the Marcellus averaged 83 million cubic feet a day in the third quarter. In Susquehanna County, we're seeing very strong well performance. Wells drilled to date in 2013 posted 30-day IPs of approximately 12 million a day. Costs are also falling in the Marcellus.

To refresh your memory, we budgeted CAD8.7 million a well as we came into this year. Current costs are running about CAD7 million, 20% lower than our initial budget expectations. Economics remain very attractive for the best parts of the play. Almost all of our capital will be targeted to areas this year where we see between 10 and 13 Bcf wells.

So to wrap it up, it's four good quarters in a row for us now. Our focus on capital discipline is driving improvement in our operating performance. We continue to execute on our portfolio strategy, building out on our four core positions and moving non-core assets out. We have a strong portfolio, a strong balance sheet, and a growing track record of strong operational performance. I believe Enerplus is well positioned to deliver sustainable, profitable growth with an affordable dividend to our shareholders.

And with that, I will turn it over to the operator and we're available for your questions.

(Operator Instructions)

Patrick Bryden, Scotiabank.

Hello, everyone. Just a few quick questions for me. When we look at the Marcellus, and it sounds like a consolidation of working interest, I'm not sure if you're able to provide any context on the motivation of the seller, and if they still remain a net partner with you as you move ahead with them.

Morning, Pat. I can't comment on the motivation of the seller. I guess a key question people would be interested in are our operators. Our primary operator out there has been Chief Oil and Gas. They've been our partner since the early days of this opportunity, and they remain our partner and key operator.

Okay, great. Thank you. And then when we turn our attention to the Duvernay, I'm just curious if you can characterize for us the initial well costs you'd be expecting in the reentry in the second follow-up? And then maybe in contrast, if we're to see a commercial evolution here, what you would think that could migrate to?

Let's start with the second part first.

The second part first, we haven't drilled a horizontal well there yet, although we are doing that as we speak. But our belief is that well costs will transition to about CAD12 million, which involves an assumption around pad drilling. We think that's pretty reasonable. [Others] are talking about lower that, but I think CAD12 million is a reasonable number to think about from a planning perspective.

Early wells, probably a bit more than that. You're going to core them. A bit of science the front end is a really important thing to do. So a bit more than CAD12 million is a good way to think at the front end.

Okay, great. And then just moving down to North Dakota. If we look at the growth trajectory that you have been on, which has been excellent, thinking about infrastructure and pacing in terms of licensing, and maybe whether there might be more inflation here given the success some are seeing down here, can you give a sense for how those factors are all at play here?

Yes. So, zero to 18,000 in a couple years is not a trajectory we will continue, obviously, but we do see growth in front of us now. That ultimate growth question will, in part, relate to the amount of the inventory that we're dealing with. And as I said, we're feeling optimistic that our inventory's more than 130 wells. So that will influence really how high we go. Over the next year, again, we're not over the budget next year, but we've been telling people we're running a two rig program right now, and that feels like a good kind of pace for next year, as well. That will continue to drive growth.

The question around cost structures and activity level, I don't see us going back any time soon, or maybe at all, to the inflationary problems we had in 2012. There was no infrastructure to maintain the activity levels. You didn't have camps. You just didn't have anything, and that stressed the system. Those things have been built out now.

And so I think that the key driver that was influencing that was also land was not held. If you look at our situation right now, we're -- by year-end we'll be 70% held land will be HVP'd, and that is some pretty significant implications to how people will go forward with their development programs. And that's something that's playing out throughout the whole basin. So I don't see that driver there. I actually think there's a shot to keep getting better here from a cost side.

And our view right now, and a leading indicator is overall rig activity in the basin. It's pretty flat. I think we're going to have a shot at some cost improvement next year, from whatever design we settle on. And feel pretty comfortable next year, but these are pretty [stout] well results, and other few guys have had the same kind of thing, so we're certainly keeping our eye on that. We're keeping our eye on access to white sand and those sorts of things, as well.

Great. And then in terms of infrastructures, lots of room, or are you going to require to keep stepping through here as you build up volume?

No. We feel pretty good. Yes, feel pretty good.

Okay, great. And then --

Pat, if I could say, though, the broad infrastructure question relates, in part, to rail, of course. The rail has built up dramatically, as you know --over built, and see that playing an important part of the whole basin egress question.

Okay. Appreciate that. And then just last question for me, as we look ahead to prospectively entering more of a US reporting standard, can you comment on how we should be thinking about that in terms of the reserve book?

In terms of reserves specifically?

Yes.

Yes. As we disclosed earlier -- actually you know what? Maybe I'll -- I've got Rob Waters sitting here, so why don't we talk -- here. We'll do it this way. We'll have Rob refresh your memory on where we are relative to that, and then Eric can pick up on what that might mean from a reserve perspective. That works.

Thank you.

Yes. I think what you're talking about, Pat, is in the last quarter we were in the MD&A we were expressing some concern that we might lose our foreign private issuer status. And the test that we were focused on was over 50% of our shareholders were US-based. And it was looking like over 50% of our assets are US-based. And if you trip those tests, then you lose your foreign private issuer status, which allows us to access the US markets using Canadian securities through MJDS regulatory regime.

As an update to that, and indeed using IFRS accounting, we were over 50% of our assets were in the US. Since that time, we've gone back in history and redone the last 3 years of US GAAP. And, in fact, using US GAAP, and, of course, US GAAP has different ceiling tests than IFRS in using reserves. We actually passed the test, so 56% of our assets in Canada -- approximately, are in Canada. And so we are dealing with the SEC right now just to confirm that, that would indicate that we retain our foreign private issuer status for another year.

And remember, this test is done at June on an annual basis, so once again, we'd have to revisit the test in June of 2014. So it looks like we're going retain that foreign private issuer status. And that was also what was tripping up. If we lost it, we would have to do both Canadian reserves, and also US reserves. So if we continue to be a foreign private issuer, we wouldn't have to do US reserve reporting.

Got it. Okay, thank you.

At least for another year.

Thank you, always nice to pass a test. (laughter) That's it for me, thanks.

Thanks, Bob.

Cristina Lopez, Macquarie.

Pat has asked a lot of my questions, but I have just a couple more. One is on the Marcellus transaction. Just want to clarify that all of the lands purchased were in Susquehanna County?

No. Virtually everything we had a working interest in. It's all non-operated. The majority would be in Bradford and Susquehanna, and that's where we would see virtually all of the value today.

Perfect. And then the last one is on future growth of Enerplus as a whole. Obviously, have some big growth areas as the Bakken and Marcellus, as well as potentially the Wilrich and Duvernay. Where do you think you can actually take this Company on a per share basis? I know that the 2014 budget isn't out yet. Is this something that you can see returning to growth in the future? And, if so, what targeted payout ratios are you looking at?

We have to grow in the future. I mean, it has to be profitable. It has to make sense operationally, but our plan is predicated on per-share, profitable growth on a debt-adjusted basis. That is our plan. And I think we're well positioned for that, and we've been demonstrating that for the last couple years.

That absolute level of growth, it's going to be influenced by where the oil price is. It's going to be influenced by where the gas price is. But when we look at our models, and with our perspective on pricing, which is oil is going to bounce around in the CAD90 to CAD100 range for a while. Gas, we're at floor, but maybe we'll inch our way up, but it's not going to be dramatic.

And that kind of dynamic -- our goal would be debt-adjusted capital per share growth of 5%, on top of the dividend that we're paying. And then it will move around a little bit. And production growth will come with that, and maybe be a little bit more than that. And how much gas you have in the mix influences it quite a bit, as you know. But that's our targets, and we think we're really well positioned for that.

Excellent. Thank you.

Dirk Lever, Altacorp Capital.

Thank you very much. Congratulations on a nice quarter. I wonder if you could give us a little bit more color on -- you talked about, you can see the inventory down in the Bakken Three Forks growing. But given what you're getting on your most recent wells, and looking at in-fill spacing, when do you get the sense of that inventory level -- I think you had talked about 130 wells in inventory? When do you get a sense of when that grows, and what should we be looking for milestones? And if you're at a crystal ball, where could you see that getting to?

So the upside in the inventory is going to come through downspacing the Bakken -- or I guess, could come, through downspacing the Bakken, through downspacing the first bench, and through increasing the amount of first bench that is prospective. It could also be influenced by a bit of that -- those deeper benches. So collectively, those are the things that we're looking at.

The data that we have today tells us we feel pretty whizzy about the first bench of the Three Forks over the lion's share of the acreage block. So I would think, based on what we know today, there's going to be upward pressure on the inventory from that. We don't have a lot of data on the downspacing, but we have some. I'll turn this over to Ray in a moment to talk about some of the specifics on when these things are coming. But based on what we see today, I guess based on our technical work, and based on what we see others doing, and having tested these downspacing opportunities in both the Bakken and in the Three Forks, we're starting to feel pretty good that, that is going to grow.

And then the last piece will be these deeper benches. The deeper benches of the Three Forks are very likely to work. They are working in industry, and they're working quite close to our acreage. But when we look at it, we think it's really only the northern portions of our acreage, which -- call it 15% of the land, plus or minus. So you get a lot of oil in a section of land, and that could matter.

When you add all of those things up, we could see, maybe double it, something along those lines. So that's the broad setup. Now, I'll have Ray speak a little more specifically to the timing and a couple key things we're doing regarding the downspace and a bit of the Three Forks.

Thanks, Ian. We've actually drilled three wells of a seven-space pattern that we are -- we'll be fracking this month. So by the end of year, we'll have these wells on. We'll carry out testing in quarter one 2014. So by the end of Q1, we think we'll have much better insight as to the downspacing opportunities that we have in the Bakken there. And then we've got another test happening early next year, and there will be online by the middle of the year next year on this next pad.

On the Three Forks testing, we are drilling a vertical well up in that northern section of our land. We will core right through all of the Three Forks to the Nisku. It'll give us a good insight as to what we see in the second, third benches of Three Forks. We'll be setting intermediate casing at the second bench, but depending on what we see from the core, we'll either run the horizontal out in that second bench or move back up into the first bench. We're relatively confident that the second bench will be good. And so we think we'll be drilling that out early next year. And again, it will be February/March time before we've good indications on a productivity from that second bench dug.

Right. And if I could get you to shift over, but still be in the US and go to the Marcellus, what's being -- what is the thinking there as far as the inventory levels? Are you starting to think about expanded inventory within the Marcellus as the results come in there?

Maybe to refresh your memory, so we had just over 200 Bcf on the books at the end of the year, and we pointed to a contingent resource of 1.3 Ts. If you want to think maybe locations, we would have had, I think, about 18 undeveloped locations in that 2P report. The contingent resource report would have been 187 net locations. Whatever they were before, they are more now after this acquisition. And we're on a pace of around 15-ish net wells a year. So, we've got a lot of inventory and a growing inventory in some of the best areas.

Thanks very much.

Thanks, Dirk Lever. (laughter)

Gordon Tait, BMO Capital Markets.

Thanks, good morning. Just on the new way you're drilling these Bakken wells, these 40-frac stage wells, what sort of a one-year decline rate would be associated with those?

We don't really know yet. So if you look at our type curves on our materials, they're updated today, or they will be today. We still haven't changed our one-year type curve. And our one-year type curve is 70%-ish. It depends where you're calculating it, because 70%-ish, maybe a little better than that, from IP 30 to exit rate.

We're clearly hitting these things with more sand, and we're seeing this in the first month's rate. And some of our longer wells are at 4 months, and we're seeing those outperform that curve quite significantly. I think the risk would be that it's just all acceleration. If you look at EOG, who was early to do this and has a longer sample set than some people, they're seeing some pretty good decline performance that it's not steeper than their initial curves.

So we're -- I guess we're hopeful that we're going to effectively shift the curve, but we'll see. Time will tell. I think it's pretty hard to argue that economics are going to be better in all scenarios. And I think you have a good shot at increasing reserve estimates here at some point.

Okay. And they've done a pretty good job selling properties in the market with a lot of assets for sale. So, two things I was wondering. Are there more assets you've earmarked for sale? Are you happy with where your balance sheet's sitting? And then maybe, specifically, can you just maybe talk about your plans for that Duvernay acreage?

Sure. We've never been unhappy with the balance sheet. We've always been happy with the balance sheet. The drivers here were, I guess, to maintain flexibility, but to also free up money to put into other opportunities that we had, all with the overlay of focusing the business. So, at 1.2 times trillion debt to cash flow, you feel really good, and felt okay at 1.9, actually. When I look at the portfolio now, we're -- about 90% of the value in the Company sits in those four focus areas.

So we're very focused from a value perspective. There's still some assets in the conventional gas side in Canada that were not getting a lot of attention, and we'll struggle to compete for capital. So we'll keep looking for opportunities to get those out of the portfolio when we can be smart about it. But it's an important part of our business, but it's not going to really rock our world financially. They're not strong cash flow contributors, but they're assets that we'll leave at an appropriate time.

In terms of the Duvernay sale -- or not sale, the Duvernay asset and the potential sale or something -- the Duvernay -- the decision to sell the Montney was, in some respects, it was hard, because it's a really good asset. Teams built a really good position. It was focused. We had growth and running room, but it didn't have the liquids content that we wanted, and we just didn't see it competing. So that, when you think about it in terms of focus, and capital allocation, and striving for top decile economics, it was quite an easy decision. We just needed to get value. And we're very happy with the value we got in it, not just in a tough market, but we were really pleased with the value in all circumstances.

The Duvernay is very interesting for us. It's got a lot of risk still, clearly. We've drilled -- we've got three core data points on our land, so not a lot. But we're rapidly moving to the point we're going to have more information. I'd say that what we're hoping to achieve is to end up with that 4 million a day-plus well, with whatever, call it 100 barrels a million, and that could look really exciting economically.

So if we target that, we will have some choices in front of us. One very possible choice is we develop it all ourselves. If someone else shows up with a -- here's some extra money to help accelerate that -- we'll look at that and think about it at the time. But I'd say the base case at this point is we're moving forward with our own plans, and we'll see how that unfolds.

Okay, thanks.

(Operator Instructions)

I have no further questions queuing up at this time.

Okay. I think then that wraps up our call. Thanks very much for your time, everyone, and have a good weekend.

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