Enerplus Corp (ERF) 2017 Q1 法說會逐字稿

Good morning, ladies and gentlemen. My name is Sally, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus 2017 First Quarter Results Conference Call. (Operator Instructions) Thank you. I will now turn the conference over to Drew Mair, Manager of Investor Relations. Please go ahead.

Thank you, operator, and good morning, everyone. Thank you for joining the call. Before we get started, please take note of the advisories located at the end of today's news release. These advisories describe the forward-looking information, non-GAAP information and oil and gas terms referenced today as well as the risk factors and assumptions relevant to this discussion.

Our financials have been prepared in accordance with U.S. GAAP. All discussion of production volumes today are on a gross company working interest basis, and all financial figures are in Canadian dollars, unless otherwise specified.

I'm here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; and Eric Le Dain, Senior Vice President, Corporate Development & Commercial. Following our discussion, we'll open the call up for questions.

With that, I will turn it over to Ian.

Good morning. I'll start with the highlights of the quarter. We generated adjusted funds flow of $120 million in the quarter. We've been talking about the improvement in our margins over the last several quarters, and the results today reinforce how meaningful the changes in our business have been.

This netback expansion has been a result of 2 factors: our ongoing focus on reducing our cost structures as well as the significantly improved regional pricing we are seeing in both of the Bakken and Marcellus. We believe both our cost structure reductions and the differential improvements are structural changes to our business. Through cost reductions, continuing to optimize our operating practices and the success we have been having divesting higher operating cost assets, we've been able to reduce operating expenses by over 30% in the last 2 years.

On the revenue side, our Bakken and Marcellus differentials have improved by over 50% during that same 2-year period, combined this has helped to drive a 50% increase in our corporate netback before hedging.

Production in the quarter was 84,900 BOE per day, of which 43% was crude oil and natural gas liquids. With our capital program largely focused on oil growth out of the Bakken, our company liquids waiting will be over 50% in the second half of 2017.

Williston Basin production was on track at 25,100 BOE per day. Consistent with how we have historically managed our operations in the winter months, our first completions in the quarter came onstream in February, so activity was quite back-end loaded.

As we stated in this morning's news release, March production out of the Williston was 27,000 BOE per day, and it's going to continue to build as we move into the second quarter.

In March, we announced the divestment of a package of Canadian gas assets and waterflood asset. A portion of this divestment closed in the first quarter and the remaining portion just closed this week. So natural gas and waterflood production in Canada will be sequentially lower in the second quarter.

Our guidance for 2017. Production volumes remains unchanged, and we are continuing to forecast significant liquids production growth in the back half of the year, with fourth quarter volumes of between 43,000 to 48,000 barrels per day.

Now let's touch on the recent oil price weakness we are seeing. Our approach to the business has not changed. We will remain financially disciplined and nimble, but our growth plans remain unchanged. We have positioned Enerplus to withstand the type of price volatility we are seeing. We've a strong hedge position that goes out several years. Our economics remain robust, and our balance sheet is solid. The others up in our growth plans are well protected.

Now, I'll pass the call to Jodi to talk through some of the financial highlights.

Great. Thanks. As Ian mentioned, our adjusted funds flow in this quarter of approximately $120 million was an 11% increase compared to last quarter, despite the previous sale of 5,000 BOE per day of nonoperated North Dakota production at the end of the December. The majority of this was driven by improved realized pricing in the Bakken and Marcellus and lower-than-expected operating expenses.

Our operating netback before hedging during the first quarter was $17.99 per BOE, which was a 24% increase compared to the fourth quarter and a 330% increase compared to the same quarter last year.

Operating expenses were $6.59 per BOE this quarter or 19% lower than during the same period in 2016. The decrease was due to further cost reductions as well as larger savings than initially forecast from our ongoing noncore divestment activity in Canada. As a result, we are reducing our 2017 annual guidance by $0.40 per BOE to $6.85 per BOE. We do expect operating cost to increase slightly in the second half of the year from our increasing liquids production.

We unwound a portion of our AECO-NYMEX basis physical contracts in conjunction with the recent sale of certain Canadian natural gas property. This resulted in a cash gain of $8.5 million in the quarter. Our balance sheet remains very strong. At quarter end, our cash and restricted cash balance was $394 million.

Our total debt, net of cash and restricted cash, was $350 million, and our net debt to trailing funds flow ratio was 0.9x. Capital spending was $120 million in the quarter, with about 70% allocated to North Dakota. Our $450 million full year 2017 capital budget is unchanged. And with the improvement we have seen in our margin, we expect our cash flow to be essentially balanced with our capital spending in dividends at $50 WTI per barrel and $3.25 NYMEX.

As we have mentioned, however,, we are in a strong position to withstand this recent oil price volatility, given the hedges we have in place, the realized proceeds from our noncore divestments and the cash we have on the balance sheet.

With that, I'll turn the call over to Ray.

Thanks, Jodi. In North Dakota, we completed and brought 8 wells onstream during the quarter.

As Ian mentioned, these onstreams were back-end loaded, with the majority of wells completed in the latter half of the quarter. So we expect a strong production built through the second quarter.

In general, the majority of our well allocations in North Dakota are 2-mile laterals. However, in some cases, the line position requires shorter 1-mile laterals, which tend to have lower rates and (inaudible) than a 2-mile lateral. In the first quarter, we completed 3 1-mile laterals and saw some very strong results with an average peak day-to-day production rate per well of over 1,500 barrels of oil equivalent per day.

We also brought on a 2-mile lateral well at our Elements pad with a peak 30-day rate of over 1,700 barrels of oil equivalent per day. The remaining 4 wells completed in the quarter were at our Cactus pad. We have protracted coiled tubing operations during cleanup. So their initial production rates aren't a good representation of their performance.

Following cleanup, the wells on average have been producing in line with the type curve expectations for that area at over 1,100 barrels of oil equivalent per day.

Our base completion design utilizes 1,000 pounds of proppant per lateral foot. As we look to maximize capital efficiencies and economics, we continue to test variations of this design, with recent completions ranging from 600 pounds per foot to 2,400 pounds per foot. The recent well completed at 2,400 pounds per foot has only been on production for about 20 days and is producing at very strong rate. We will monitor the performance of this well and assess the economics of this completion design with respect to the additional cost incurred with increased proppant volume.

Turning to the Marcellus. We have strong production in the quarter at 205 million cubic feet per day, reflecting solid well performance and strong pricing. We participated in 9 gross wells that were brought on production in the quarter with an average lateral length of 6,100 feet and average peak 30-day production rate of 19 million cubic feet per day.

In Canada, our drilling activity in Q1 was focused at Southeast Saskatchewan and Cadogan with initial results looking strong. Other capital activity included expanding the source water supply and water injection at our Ante Creek asset. Activity in Canada for the rest of the year will be focused on ongoing polymer flooding and waterflood expansion and optimization.

I'll now turn the call over to Eric.

Thanks, Ray. I'll just quickly touch on differentials. Firstly, in the Bakken, differentials improved by about USD 1.20 a barrel from Q1 relative to the fourth quarter of '16 to average USD 5.59 per barrel below WTI. When the Dakota access pipeline starts up sometime in the second quarter, the basin will be structurally long pipe, and we see this supporting stronger Bakken prices going forward. Bakken differentials at Johnson's corner are trading near USD 4 per barrel below WTI for the month of June.

Our Bakken portfolio is well positioned to take advantage of the Maryland differentials, with the great majority exposed to floating market differential prices. We expect our Bakken crude oil differential to average USD 4.50 per barrel below WTI for all of 2017.

In the Marcellus, we also saw sales differentials improve through the first quarter, averaging $0.60 per Mcf per Enerplus below NYMEX. But the continued build-out in infrastructure and strong local demand, coupled with a supply side that has not kept pace with recent takeaway capacity additions, we think the outlook for regional differential is strong. We're tightening up our 2017 Enerplus Marcellus natural gas sales price differential to $0.60 per Mcf below NYMEX.

Our residual $0.66 per Mcf fixed basis position in Western Canada, NYMEX-AECO, continues to protect the majority of our remaining AECO price exposure.

Briefly on financial hedging. Our funds flow is well protected for 2017 as we have almost 70% to our net crude oil production hedged for the rest of the year at an average oil price just above USD 50 a barrel, largely through 3-way collars with the average sold put strike set below $40 a barrel.

For 2018, we've got about 46% of our net crude oil production hedged based on 2017 volumes at an average floor price of about USD 54 a barrel WTI.

I will now pass the call back to Ian

Thanks, Eric. In summary, we are pleased with the margin expansion we are seeing in your business and the well results we continue to post across the portfolio. Our financial position is rock solid. Our production volumes are tracking on forecast. Crude oil volumes at North Dakota began to accelerate, setting the stage for growing second quarter oil volumes and continued ramp into the back half of the year. We remain well positioned to drive sustainable, long-term profitable growth.

With that, we are available to answer your questions. We'll turn the call over to the operator.

(Operator Instructions) Your first question comes from the line of Brian Kristjansen with Macquarie. Brian, your line is open.

Right, your next question comes from the line of Travis Wood with National Bank Financial.

Just some questions around guidance you've laid out kind of at the average of liquids where you plan to be for Q4 within the range. Can you help us understand the profile of how you see the Marcellus rolling out for the next 3 quarters, given the activity? I think the majority of ducts are now onstream. So if you can provide some color around how many wells need to be continued to be drilled and brought onstream to kind of grinded out at 205.

So regarding to $60 million, I notionally think USD 5 million to USD 6 million per well, most of it is D&C spending. And we see that holding production relatively flat over the course of the year.

Okay. And with drilling getting picking up over the last few months there to bring on new production, has there've been any cost pressures that you guys are aware of?

It's been pretty flat. Yes, pretty flat. I mean, if you think about the U.S. and where you see these inflationary pockets, it's -- I mean, there's little bits of pressure everywhere for sure. It's mostly been concentrated in the Permian right now. So Marcellus activity or Pennsylvania activity has picked up, but it's been relatively modest certainly compared to historical.

Okay. And then just staying with the Marcellus, can you provide any color around which pipes are now up and running to help address issues to start to flow the Appalachian gas on the South and West? And which projects are now kind of coming down the pipeline that we could expect to see potentially further differential tightening?

Yes, Eric will take you through that.

I think there was about 500 million a day, well, little less, came on at the end of '16. Some of it just debottlenecking the region and driven to Jersey -- that just Northeast region. What's ahead of us now and looks to be on schedule is, of course, Rover, at least the first stage, and you see that coming on towards the latter part of the year. I think what's happened fundamentally is, with those projects at the end of '16 and with continued (inaudible) out, at least that impacts us in Northeast, Pennsylvania, a regional power demand. Just seeing that balance shift where production stayed pretty flat and that steady regional demand growth of this project additions has taken us to this point where actually pipes are not full and people are making decisions which pipe to flow on any given day.

Your next question comes from the line of Patrick O'Rourke with AltaCorp.

Very strong quarter there. Just a couple of questions here. In terms of the Bakken here, looks like things are moving in the right direction. You talked about being structurally short pipe. What do you need to see to add potentially a third rig here? And then you're structurally short pipe right now, but you do have operators like Marathon adding 6 rigs here. How quickly can that capacity be soaked up?

So let me talk with the activity level. So this 2-rig plan that we have is driving significant growth at field level, and that project is going to grow entry to exit by above 50%. So we're focused on a lot of things, having an efficient operation, sustainable growth. Sustaining that growth is also part of that. That said, we've talked about moving to a third rig as part of our plan. Notionally, we see that starting up next year. As we think about the activity levels we're managing right now, we're right in the middle of sort of talking our way through procurement or the next 12- to 18-month time period. So we're not looking for anything relative to performance, profitability, any of those things. The stars have all aligned relative to us reinitiating growth. We're trying to be very operationally focused throughout the gas gathering and infrastructure and looking for the most efficient way to manage that build. So I think we're still thinking about '18 as an appropriate time to manage that growth and bring it into the pool. There's just a lot of growth directionally in front of us right now. I mean, you think about that activity, it's closing in on 30 net wells we're going to bring on this year, and that didn't start till effectively March. So it's a lot of activity in mostly 3 quarters. So then you also asked about how fast can the build happened. I guess, tell me the price. Is it $44, or is it $57? I think we are in somewhat of a unique position relative to our balance sheet, the quality of our inventory and our hedging program that our growth plans aren't all impacted by what's happened today. I don't think that is a broad phenomena that's going to play out in the industry. I think a lot of people are thinking about those plans. I think, if you set up a robust $55 to $60 kind of world, you could see growth start to come. I don't think that's -- I don't think we are going to be filling pipe anytime soon with this kind of price volatility. Now all that being said, we're spending a lot of time looking at our ability to lock in some of these structurally tight differentials so that we can manage against that risk. I mean, you've seen lots and lots forecast out there. The most aggressive I've seen is, 4 years out, you sort of see that pipe getting filled. I think that's a relatively bullish macro scenario for that to happen. But I think we're in a really good position to protect some of this price improvement that's happened for us.

Okay. Terrific. And just in terms of the down-spacing or well-spacing with the drilling that happened this quarter, Cactus pad, are you guys able to -- I know you've been experimenting with tightening things up, but have any of those things been actualized on the pads that came on this quarter, and maybe provide some color on that?

So for those who aren't as familiar, 2 zones over the majority of our acreage block, we talk about 525 wells, 15-year-plus inventory that of remaining drilling. That ties to 6 wells in the Middle Bakken and 4 in the First Bench of Three Forks, a few other places where we've got deeper bench potential. But we're -- we still think that today makes sense, when we put that in the context of the well results we're talking about. I'd say we're continuing to do work and monitor performance. I'd say largely that others have done. We've logged one test where we've tested tighter spacing that, but there is a sample set of inventory out there where there's tighter spacing than ours, and we're watching it. Probably the bigger question might be in the First Bench of Three Forks and, "Can you add a couple of extra wells in that bench?" You certainly can, and you'll get oil. Question will be the economics. So that whether that's pure acceleration, and so I'd say we have nothing else to add on that right now, and it would all be, I guess, upside if we can take things tighter than we are talking about right now.

Okay. And the spacing on the Cactus pad, that was just standard what you've been doing to-date?

Yes, the spacing standard, we were testing different proppant volumes for each of the pads at different -- and in the 2 different zones that you mentioned earlier on. Too early to see how these wells are performing, but we range from 600 pounds per foot up and compared it to 1,000 pounds per foot, comparing 2 different proppant types, and we are monitoring the results just now to see how they fare.

Your next question comes from the line of Jason Frew with Crédit Suisse.

Ian, I'm wondering if you could maybe step back and provide an update on strategy at this stage, and what you're potentially focused on looking a few years out, and maybe whether or not you see more or less opportunity today from an inorganic perspective.

So you think about the last year, the last year started with a strong focus on improving the sustainability of our business in a low commodity environment, and that meant balance sheet strength and margin enhancement. And you're seeing that come through in this quarter and saw them in the fourth quarter. We've made incredible change to the balance sheet, obviously. But you've got to back to 2014 when oil was $73 and gas was $4 to get this same operating netback that we just posted. So call it a win relative to those objectives. And as we stand today, we have what we think is a compelling organic growth program in front of us. So anytime we talk strategy, we give that little speech, and I think it's an important speech for people to calibrate on. So as we think about complementing that organic platform, yes -- I mean, there are some stuff that's out there that is feeling maybe a little more interesting. You think about our financial capacity. We're building cash on the balance sheet. And the price of oil average is $46 this year. Maybe it will touch a tiny bit of that to complement our cash flow for our organic plan, but we're going to have cash left over. As we think about things that might work in connection with that, obviously, we'll look at assets that would be consistent with our operating strategy. North Dakota could be interesting. And you obviously will remain disciplined as we think about that. There have been very little -- very few deals. Outside of the Permian, they really haven't been a lot of transactions in any particular basin, and this volatility that we're continuing to deal with has just put pressure on the bid-ask spread on both sides. We have thought about expansion, maybe with some modest expansion outside of North Dakota. We've got a lot of experience that we've talked about in the [DJ], and so our eyes are looking at things like that as well. But, Jason, as I say, we're -- we've gone from a scattered business to a highly focused business. And that wasn't the concept. That was to force us to be efficient. And so now we have a highly efficient portfolio that makes sense. We would be very happy to core up around those areas where we operate, and our eyes are open to possibility of expanding that.

Your next question comes from the line of Brian Kristjansen with Macquarie.

Apologies for disconnecting earlier. Just wanted to follow up either Ian or Ray on the 2,400 pound per foot Bakken well. How much of that cost all-in drill case equip tie-in? And did that use white sand or ceramic-coated proppant?

So that guy -- Ray talked about on this call, it's just online. It's just online. So we're not really talking about the rate other than, I think we use the word encouraging. Ray, do you want to chat a little bit about cost there or not?

The additional -- I can talk about additional cost of the proppant was about $1.5 million, and the results are very encouraging. But when you think about the increased cost, you do have to make sure that you understand your wells and the performance to see if the economics are improved by that or not.

So that was SSP. We used on that well. We've talked a little bit of the short wells. It's not a big part of our portfolio. In this instance, that actually was a short well, which worked relatively well for us as we're thinking about cost-efficient ways to test higher levels of proppant. And like, as Ray said, notionally, the completion is the biggest cost of these. These should be short wells with the D and C in the 5-ish range. This big guy would have added around $1 million to that. And is that going to be a smart economic decision? It looks encouraging right now, but we'll see and we need to monitor.

Okay. And is this well -- has it gotten like an immediate asset that you can compare similar raw quality too to say it's x percent better once you get your 30-day-type number?

We will, yes, but -- so there are virtually no areas where we don't have control that's close enough to give us analogs. That's just sort of the nature of our asset. I'd say, be a little careful on 30 days, like 90 days a lot better than 30 days. You can have a lot of noise at the front end of those wells relative to cleanout issues, flow-back practices, all of those sorts of things that can affect it. But at 60, you start to get a better feel -- sorry, at 90, you start to get a better feel.

(Operator Instructions) And your next question comes from the line of Mike Dunn with GMP FirstEnergy.

I've just been following some of the developments, I guess, from other U.S. shale producers with Q1, and many of them are talking about completing -- drilling and completing all of the down-spaced wells at the same time before turning any of the month's production as they've -- they said they've learned from past. I guess, disappointing results from shaled wells in the Eagle Ford and Bakken. That's the best way to do it. Have you seen anyone in the Williston Basin move to this? And are you guys thinking about, I guess, drilling all the infield wells immediately instead of coming back to the pad later on?

Thanks for that question. It's timely. So we're in a bit of unique position out there. In fact, we're singularly unique in North Dakota when you think about our asset. It is 100% in the core, and it is by far the most lightly drilled asset in the core. So the way the Bakken developed, it was sort of, I don't know, innings, the reinning 2 of shale developments certainly on the liquid side, and so a lot of the primary development, if you will, or the lower density was done, all [seemed] time-outs in completion. That's certainly not how we approached. We approached it in a bit of a more systematic fashion. And so we now have the luxury of sort of looking around the world, looking at performance and trying to figure out what the best answer is. We've got a lot of flexibilities as to how we're -- as to how we could approach it. I'd say, our preliminary view on cues is it makes some sense. It's not simplistic. You drill every well, at the same moment, you have to really be honest with yourself about economics and overcapitalization of infrastructure and those sorts of things; but notionally, I think we're going to go down. Notionally, we're planning for something that looks a little bit more 1, 2, 3, 4 at the same time, 1, 2, 3, 4, 5 at the same time. It might be an East-half, West-half kind of deal as you work your way through it. The work that we have done says there is no question that the child will disappoint the parent if you wait long enough, and that is not our dynamic at all. I think you do have a bit of flexibility on that. It doesn't have to be instantaneous and you'd work around off the depletion is -- I think, relatively -- sets up that answer relatively, obviously. So we're heading down the path of probably more continuous development, but it might not be every single well on pad...

And there are no further questions at this time. I will now turn the call back over to Ian Dundas.

Very well. Thank you, everyone. I appreciate your time. We'll let you get back to your day and have a great weekend, everyone. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference call. You may now disconnect.