Enerplus Corp (ERF) 2016 Q2 法說會逐字稿

Good morning. My name is Stephanie and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2016 second-quarter results conference call.

(Operator instructions)

Thank you. I would now like to turn the call over to Mr. Drew Mair, Manager of Investor Relations. Please begin.

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 US 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 am 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 and Corporate Development Commercial.

Following our discussion, we will open up the call for questions. With that, I will turn the call over to Ian.

Good morning everyone. We have been focused on positioning Enerplus to deliver profitable growth in a lower commodity price involvement. And with our second-quarter results, we continue to demonstrate strong cost performance that is in improving our margins.

This morning's results highlighted a strengthened balance sheet, including a 45% reduction in debt that net of cash since the end of 2015. Strong operational performance leading to an increase in the midpoint of our 2016 annual average production guidance range to 93,000 BOE per day. Our continued emphasis on cost control, with operating costs per BOE for the first half of 2016, that are 12% lower than the corresponding period last year.

The continued execution of our divestment program which has moved higher cost, lower margin assets out of our portfolio and strengthened our balance sheet. And to the combination of reduced operating costs, lower G&A and interest expenses, and to narrow differentials that are all driving strong margin improvement.

We also highlighted a CAD15 million increase to our 2016 capital spending. Effectively reinvesting a portion of our cost savings back into the business as we position to reestablish growth. This incremental spending will be directed toward additional completion activity in the fourth quarter, as well as additional facilities work to jumpstart our 2017 capital program.

Even at today's lower prices, these completions represent highly economic activity. We had talked previously about Q4 volumes of approximately 88,000 BOE per day. These additional completions are expected to increase that number to about 89,000 BOE per day.

There are also some additional strategic benefits from the increased capital, related to completions design and well spacing which Ray will touch on later. Although this is only a modest increase in activity, it will better position Enerplus for 2017.

We remain focused on spending within cash flow. And when we think about 2017, the benefits of our lower cost structures resulting in higher margins will position us to deliver growth through the year under the current sub-CAD50 per barrel 2017 strip prices. With that, I will turn the call over to Jodi to comment on our financial highlights.

Sure. Thanks. As Ian indicated, the two key financial takeaways are an improved balance sheet and improvement to margin as we continue to drive costs lower.

We have made significant progress and strengthen our balance sheet to the combination of CAD281 million in non-core divestments, and raising CAD220 million in net proceeds through our equity financing in May. In addition, we repurchased a total of $267 million of our senior notes of various prices between 90% of par and par resulting in a gain of CAD19 million year-to-date. As a result, our total debt net of cash was CAD674 million at the end of June -- down 45% since the end of 2015.

Our outstanding debt at June 30 comprised of solely of our US senior notes, offset by CAD49 million in cash. As well, our CAD800 million bank credit facility was undrawn at the end of the quarter, providing us with additional financial flexibility. Operationally, we had a strong second quarter and generated CAD76 million in funds [forward].

This was up 82% compared to the previous quarter. And was driven by higher oil prices, our ongoing cost reduction initiatives, and narrowing commodity price differentials. We have made good progress across the board on reducing our cash costs and improving our margin during 2016. When we compare our operating, transportation, G&A and interest expense to the same quarter in 2015, we have reduced our cost structure by CAD1.68 per BOE.

The majority of this reduction is related to our cash operating costs. Which were CAD7.20 per BOE in the quarter. The decrease was a result of our the cost savings including lower supply chain cost, optimizing repair and maintenance activity, and declining labor expense.

We also divested of some higher operating costs assets over the period. As a result of our cost performance to date, offset to some extent by our expectations for seasonally higher costs in the second half of the year, we are reducing our operating cost guidance to CAD7.90 per BOE, from CAD8.50 per BOE.

We're also seeing a reduction in both our G&A and interest expense. Which were down a combined CAD11 million in the second quarter, compared to the same period last year. Consequently, we are also reducing our G&A guidance to CAD1.95 per BOE from CAD2 per BOE as we continue to see additional savings result from lower staff levels.

Moving to commodity prices. Compared to the previous quarter, we saw 47% increase in our realized oil price to CAD46.48 per barrel. As a result of both improved benchmark prices and narrow differentials. In Canada, our light and heavy crude oil differentials narrowed by 16% and 7% respectively largely due to the wildfires on Northern Alberta. In the US, our Bakken differential improved slightly averaging $8.33 per barrel below WTI.

Our realized gas price was CAD1.49 for MCF in the second quarter. Which was 16% lower than the previous quarter due to the decline in benchmark, NYMEX and AECO prices of 7% and 41% respectively. Unlike the AECO basis differential, our Marcellus differential improved 16% quarter-over-quarter averaging $0.76 per MCF below NYMEX. This was a 45% improvement, compared to the second quarter of 2015. Although, recently, as NYMEX has strengthened, the Marcellus base differential has begun to widen again.

Turning to hedging, we continue to have good support from our risk management program of CAD21.6 million in cash gains during the quarter from our crude oil and natural gas hedges. We also added additional floor protection on both our oil and natural gas production. Currently, we're hedged on approximately 39% of our forecast net oil production for the rest of 2016 and 2017.

For natural gas, we're hedged on approximately 29% of forecast net volumes for the rest of this year and 20% forecast net finance in 2017. We reported a net loss of CAD169 million or CAD0.77 per share in the second quarter. Which was due to non-cash items including CAD149 million asset impairment charge and a CAD105 million deferred tax asset valuation allowance.

These charges are the result of the continued decline in the 12 months trailing average commodity [rate]. With that, I will now turn the call over to Ray to discuss our operations.

Thanks, Jodi. Capital activity in the quarter was largely focused in North Dakota, where we continued to run one drilling rig at [full buckle]. We put spent CAD30 million in the quarter in North Dakota drilling 4.6 net wells and bringing 7.2 net wells on-stream.

The average initial 30 day production rate of our operated wells in the quarter was approximately 1,450 barrels of oil equivalent per day. There were a couple of wells that we brought on-stream at the start of the quarter that are exceeding expectations. To frame a strong performance for you, these wells averaged over 1,200 barrels of oil equivalent per day and 1,500 barrels of oil equivalent per day in the third month of production.

We also continued to improve our drilling, completion and tie in costs which averaged $7.8 million in the quarter, down about 8% from Q1. These savings were due to improved drilling time, continued optimization of our completions design, and reduced water management costs. These costs represent a reduction of 26% from our 2015 average drill, complete and tie in cost.

Ian talked about the addition of CAD15 million we added to a capital guidance. This additional spending will all be directed to North Dakota. Where we will complete three incremental wells and pre-order facilities equipment for the 2017 program.

The cost forward economics for these completions are strong. With an average rate of return for the program at about 50% at CAD40 a barrel. And over 100% at CAD50 per barrel WTI. In addition to positioning us to reestablish growth, there are also strategic benefits from these incremental completions. As we will be testing tighter well spacing at 500 feet and evaluating modified completion designs.

This is all aimed at continuing to optimize development planning and well performance. As we expect to move to a larger program in 2017. I will also add that with the cost savings that we have realized driving higher cash flow, we continue to expect the 2016 capital spending and dividends to be fully funded through internally generated cash flow at current commodity prices.

Turning briefly to the Marcellus and our Canadian waterflood. In the Marcellus, we spent CAD9 million in the quarter resulting in 0.3 net wells drilled and 1.8 net wells brought on-stream. Despite the limited spending, production was up slightly in the quarter, at 195 million cubic feet a day due to some very strong well performance.

Of the seven gross on-stream wells participated in during the quarter, the average initial 30 day production rate was approximately 15.8 million cubic feet per day. These wells will generally longer laterals with an average length of 6,400 feet. There's no change in our forecast spending in the Marcellus where we expect full year spending to be approximately CAD20 million.

Capital spending in the Canadian waterflood was approximately CAD7 million in the quarter. And was primarily focused on waterflood optimization activity in southeast Saskatchewan. Overall, Enerplus is performing at a high level operationally. And we continue to deliver strong operational and capital efficiencies.

And so, with that, I will turn the call over to the operator and we will open it up for questions.

Certainly.

(Operator Instructions)

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

Your line is open.

Hello. Good morning. Good quarter again. Just a couple of quick questions here.

First of all, from a high level in terms of asset acquisition opportunities. In the past, maybe there had been a tone of potential in the [Montney], but there seems to be a loosening of assets in the Balkan right now. Is this somewhere where you would be focusing your attention at this point in time?

Patrick, I think if you think about portfolio strategy, a lot of things have to line up there. Operational strategy is high on that list. And so obviously, we will drill some of the best wells in North Dakota. Some of that's our acreage, and a lot of that is what we do. And so assets in North Dakota would fit really well geographically our skill sets.

We are also pretty focused on the quality. And the difference between tier 1 and tier 2 and 3 makes all the difference in the world. So there hasn't been a lot of quality. I think one of the other big challenges that's been going on in the market right now is a pretty bid ask disconnect when you look at the strip price and you look at what expectations are. So we are always thinking about things.

The trickier part over the last six months has probably been thinking about how you finance it. We have been pretty protective of our equity. And we thought we saw value in the stock that was not being reflected. We are starting to see some of that being reflected now.

We're also very focused on the balance sheet. It's been a lot of work to reestablish a very strong financial position. We are protective of that as well. So the Bakken could make sense, but it has to be the right asset with the right running room and the right economics.

Excellent.

In terms of the well economics here and productive results. Obviously, you've have, both on the cost and the IP front, made terrific progress over the last few years. The 1,450 BOE a day was down a touch from prior quarters, although you did mention that the second and third months were showing some strong results.

I'm just wondering. Are you seeing sort of attenuation in the decline profile? Or what is kind of driving these results here?

Well, you know, we are trying to give people a really strong flavor of the economics. And we're not hanging our type curves on the best well we have had. So we've bundled them. And we still talk about our high-end type curves at 1.2 million barrels, with gas on top of that, and our low end at 900,000 barrels.

We have obviously had a couple of wells that have outperforming those curves, so nothing going on. Those wells are very consistent with high-end type curves. And the ones Ray highlighted there are probably hanging in a little better than type curve. So I would say there is no read through based on those results.

Okay. And then any further commentary on the Three Forks versus the Bakken and how the economics are evolving there?

I guess for those who are not quite as close to it as you, as a general rule, Three Forks is a little bit worse than the Bakken across the Basin. But then depending on where you are, one of the best wells in the whole Basin is a second bench well we have. So there are some spectacular Three Forks out there.

I would say we're obviously in a lower spend environment right now. There is less activity. And so there is less going on relative to delineation. So the big question is -- there are not as much Bakken versus Three Forks in our acreage block. They are related to downspacing.

In our recent Investors Day, we highlighted a growing inventory, which talked about downspacing. A base case scenario for Enerplus is around four wells per zone. So in most of our acreage block, we've got two zones and then sometimes we have three. So that goes from 8 to 12 wells effectively.

Ray talked about one of the reasons we are doing one of these completions at the end of the year is to give us some data around the 500-foot spacing. So that's effectively doubled that density. So I would say, for us, it is really not as much a Three Forks Bakken distinction as the entities.

Now, that said, there are a few places in the acreage block where we don't have a lot of date for some of the deeper zones. So there's nothing going on at this second relative to that. But that will be some of our activity next year.

Okay. Thanks a lot.

Thanks, Patrick.

Your next question comes from the line of Greg Pardy, with RBC.

Your line is open.

Thanks.

Maybe just as a follow-up a little bit on what is going on in North Dakota. You mentioned a 2 mile lateral then, I think, in the release. Is that becoming, basically, the fairway for you in terms of lateral length? Or do you think there is more optimization that you can do?

And the $7.8 million in terms of DC and so on. Obviously, I could ask around stability; but do you think there's any further downside on that number as you just get better and joining these wells?

So we've drilled lateral links, I guess, three different times. We have drilled a couple of three-milers. We have drilled some one-milers and milers that we are referencing. When you look at the plan configuration, most of it sets up for two-mile wells, and we generally think two miles of the most optical economics.

So we're transitioning to that. And there are some places where we are doing some land work to turn one-milers into two-milers. But think two-mile laterals for most of what we do.

On the cost side, Ray talked last quarter about some changes. And said that we see 60% of those capital cost savings as sustainable. The best example of that is drilling times. A year and a half ago, 25 days spud rig release. Starting the year, we're budgeting 17. And we've got some down to 13. So that is clearly sustainable and is going to get better.

We haven't reached technical limits on that, although some of the early low-hanging fruit is gone. So the drive is to continue improve and drive costs. I think there is a fair amount of inefficiency in the system right now.

We are running a single rig. That means limited pad drilling and all of those efficiencies we don't have yet. So as we move to a bigger program next year, we will be able to get to some of those efficiencies. And it will be partially offset by some cost pressures as we start to see a pickup in activity.

Okay. That is helpful.

And then just to be clear, you're just going to lean on some of the documentary in terms of the completions you are talking about? Or is this actually going to lead to some backfilling -- i.e., more wells that you are going to be drilling? It doesn't sound like it if you're not changing the number of rigs you've got in the play.

Our guidance change was just ooching up our Q4 spend for a bit of facilities work and three ducks. Strategically, we are moving to a higher spend scenario in 2017. And that will likely involve picking up a rig next year. There is even a chance that could happen this year, although we're not planning for it.

We are strategically very focused on reestablishing grown. And the conditions to that are affordability and economics. Even under a sub [$50] world, affordability looks really good. The balance sheet is very strong. This collective change in cost and improved margin is really changing the picture for our Company.

And so things are certainly lining up to spend more money next year. We just haven't settled on exactly what that looks like. But I think as a base scenario -- and you can go back to our materials in our Investor Day -- think about Enerplus running a couple of rigs down there for 2017. Call that a preliminary look.

The last thing, Ian, is just on your spend. You boosted your spending program -- or the budget at least -- by $15 million. But you are typically spending under what we expected, at least during the first half. So have you essentially already kind of commenced significantly higher activity? Or is there still a chance that you will come in at that $200 million level for the year?

Well, that would be great if we hit $200 million. But we are trying to give real clear guidance. One of the big reasons that we have been lower year-to-date is things have been cheaper. We were $8.5 million in Q1 on these wells, and we're $7.8 million now.

So I guess if we can do things cheaper than $7.8 million, that will save us a little bit of money. But things are getting tighter. And I'd say today, we don't have any incredible ideas how $7.8 million is going to become $6 million this year. So I think that's a pretty good number -- that $215 million.

And if we can be a little more efficient, we will have a little bit of room there. But it's a pretty good number, and not a lot of padding built into it.

Yes, okay. Thanks very much.

Greg, maybe one other thing. We certainly don't get into an audit of this on a quarter-to-quarter basis. But we have had a little bit of an uptick, a little benefit from FX. So a little bit of that has helped us over the course of the year. So that moves our numbers around a little bit. But I think $215 million is a good number to think about.

Yes, okay, great. Thanks again.

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

Your line is open.

Thanks.

Ian, maybe you could characterize the level of focus in the organization around repositioning for organic growth versus adding new inventory through acquisition. And maybe to color it, is your own organic opportunity evolving enough to lower the urgency around or push out the need for acquisition?

Good morning, Jason.

Again, I will come back to the characterization at Investor Day. We see a deep inventory in the Company. And that has an ability to drive significant intrinsic value that hadn't been recognized (inaudible). And so very focused on unlocking that inventory.

Balance sheets strength was an important part of that. And the cost structure -- I think we're really in a good position to be up to grow organically for a very reasonable period of time. And so I think that is locked. These assets are understood. Our performance is strong and consistent and the balance sheet's there. So I think that is locked for us.

Is there an opportunity to add shareholder value through acquisition? Clearly. I think the reason we are in this position as a Company is we did that several times in the past.

And one of the challenges, as I said earlier when Patrick asked the question, was it was difficult to think about the practical reality of how you pay for those opportunities when we were focused on balance sheet strength. And we were complaining about a share price that we did not think reflected the value. Those things are starting to come into line.

So are the conditions lining up where it is maybe more practical, more possible? Potentially. But they come back to we still see opportunity in the stock. We still see an inventory, and we don't need to do anything. And in a market where everyone would like to talk about acquisitions, we all like to think about them, but not a lot has happened. (Inaudible) has been really, really significant. So we have got people thinking about it.

But equally, we are thinking about divestments. Part of the storyline the last three years has been simplifying and focusing our business by selling things that we didn't see fit our portfolio strategy. And we have made huge progress on that. We still see opportunities to tighten that up a little bit too. So we are focusing on both sides of the ledger. And it is all designed to make ourselves better, more focused, and add value today and in the (technical difficulty).

I think I asked because the valuation still seems to reflect some level of pushback on inventory. Whereas, pushback around operating performance, well results, balance sheet, historical per-share metrics -- there's a lack of ability to push back on that. But there's still a discount in the stock.

So I guess that's why I'm pushing on this point around inventory. Just to try to flush it out in terms of whether that is something that is reasonable to be reflected in the valuation or not.

Well, I have a bias on this. I don't think it is. I don't think our inventory has been fully appreciated by the market. I think people are starting to appreciate it.

And so we are not going to go do something that is dilutive to our shareholders to buy some future inventories. We're not going to do that. Do other companies have deeper inventories than ours? You can see out there. You can see that out there.

And so would a deeper inventory help? It might, depending on how you paid for it and depending on what that inventory was. So I come back to we can grow this Company at close to 10% a year if oil ooches its way up a little bit. And if oil stays in that sub-$50 that range, we will still grow the Company.

We don't think our valuation reflects that. And we are seeing that at the stock now. We are seeing that investors are coming to stock who are starting to recognize that. For many people, they were focused on balance sheet. That has now cleared the system, and the stock is performing pretty well.

There's another piece to this as well. We are not the simplest story in the world. I don't think we're all that complicated, but we're not the simplest. And so we've got $200 million a day of Marcellus volume that traditionally certainly hasn't been helping us much on cash flow. It hasn't been hurting us, but it hasn't been helping us.

With gas price strength and a reasonable differential picture there, that is starting to come into focus for investors. I really believe that the fundamental question, the fundamental thing for us in the last year, has been the math has not been crisp. The balance sheet wasn't as strong as we would have liked.

And the net back wasn't as strong as we would've liked. A lot of that has been Marcellus differentials in pricing. Those things are all now coming into focus. And you can see that in the net back, and the math has changed dramatically. Obviously, the balance sheet picture looks completely different.

So I think we are very well-positioned to grow organically. But most good companies keep their eye on that M&A market for opportunities that are good for their shareholders. And we do the same thing.

Yes, thanks. Fair enough.

Thank you, Jason.

(Operator Instructions)

Your next question comes from the line of Adam Gill with CIBC.

Your line is open.

Hello. Just two quick questions.

One on the 1,000 BOE a day impact from the additional spending in Q4, do you have an idea how this is going to impact Q1 production?

And the second question is related to Marcellus differentials. They were pretty tight in Q2, widening a bit in the third quarter. Do you think the benchmark pricing in the Marcellus is a good idea of where to trend your pricing? Or have you done some things to mitigate some of the additional pricing differential pressure that we are seeing in Q3 here?

Hello, Adam. I will deal with the production question, and then I will turn it over to Eric to talk about pricing in Pennsylvania.

We try not to get overly precise with an exit number because timing can move that around a lot. But directionally, 1,000 barrels of flush production in the quarter will contribute to the next quarter at a lesser level. Although, as Ray highlighted, we have had a couple wells that have hung in really quite well. So it is additive to Q1. We're (inaudible) approach it a slightly different way.

We have given people that exit number for a few reasons. And we did this at Analyst Day. And I keep coming back to that, but there were some pretty important things in that relative to our inventory. And relative to getting through this divestment work and letting people understand when growth happens again. So we see sort of bottoming out Q4; Q1 pretty flattish. That is sort of the dynamic, right? And then starting to build as we move through the year. That is what we said in the call.

If you get more granular than that, as we talk of spending money, we are talking of spending money in oil. And so we will start to see oil volume start to grow. We are not spending any money in Canadian gas. And so we see that continuing to decline.

And then the Marcellus story is relatively flat, we would guess, over the course of the year until pricing continues to strengthen up. And we would see spending start to increase maybe in Q4, a little bit into Q1 and Q2 as people gain confidence in the gas market out there.

And so relative to the Marcellus pricing question, Eric Le Dain will give you some color on that.

So the question was on the Marcellus -- are the Leidy and TGPs known before spot market price is reflective of what our portfolio realized? You actually saw in Q2 that they are not exactly reflective. We do have around 50% that is priced off other markets. And actually, in the summertime, we remain very positive on that Transco Non-New York north market.

But in the summer, it is a wider differential. Actually, you realize a lower net back than into the peer spot regional production market. So we could see that happening and having some influence the first month or so of this third quarter. And then those downstream markets that we attach begin performing again.

So it's not a perfect reflection, I would say. But it still provides a good directional indicator if you just look at the Leidy realized spot for the quarter.

Great. Thank you.

There are no further questions. I will turn the call to Ian Dundas, President and CEO, for closing remarks.

Well, thank you, everyone. We really appreciate your time today. As I reflect on the questions I got asked today, I will make a comment.

I refer people back to our Investor Day materials. Because there was a lot of stuff that came out there that really helped frame how we think about our strategy. How we think about growth in an improving market, how we thick about inventory in North Dakota. There's a lot of stuff sitting there, and I think you can see the connection between that and our quarterly results.

Our cost performance continues to improve. You see a meaningful percentage of that as being sustainable. We think we are very well-positioned to begin to reestablish growth, while still maintaining a commitment to our financial strategy. Which is keeping a strong balance sheet and living within our cash flow, living within our limits.

So thank you very much, and we appreciate your attention today. Have a good weekend.

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