Enerplus Corp (ERF) 2014 Q1 法說會逐字稿

Good morning ladies and gentlemen. My name is Aaron and I'll be your operator today. At this time I would like to welcome everyone to the Enerplus Corporation 2014 first-quarter results conference call.

(Operator Instructions)

I'd now like to turn the call over to Ms. Jo-Anne Caza, Vice President Corporate Relations. Ms. Caza, you may begin.

Thank you very much, Aaron. Good morning everyone. Thanks for joining us this morning. Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our results for the first quarter that we released this morning. Ray Daniels, Senior Vice President of Operations, will also give some additional detail on our capital spending and our operational performance in the quarter. We also have Eric Le Dain, Senior Vice President of Corporate Development Commercial and Rob Waters, Senior Vice President and Chief Financial Officer, on the call today.

I'd like to point out that our financials have been prepared in accordance with the United States generally accepted accounting principles. We made this change at year end as more than 50% of our shares and more than 50% of the book value of our assets under international financial reporting standards were held in the US. All discussion of production volumes today is on a gross basis -- or sorry, a gross company working interest basis. And all financial figures are in Canadian dollars unless otherwise specified. Conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 energy equivalent conversion ratio, which does not necessarily represent the current value equivalent. Information we are discussing today contains forward-looking information.

Listeners are asked to review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be found at the end of our news release issued this morning and included within our MD&A financial statements filed on SEDAR and EDGAR and available on our website at www.enerplus.com. Following our discussion we will open the phone lines and answer questions you may have and we'll also have a replay of this call available later today on our website. So with that, I will now turn the call over to Ian.

Good morning everyone. And thanks for dialing in this morning. We delivered another strong quarter of production and cash flow growth for investors in Q1. Production was ahead of our expectations at 98,821 BOE a day, and represented a 5% increase over average volumes in the fourth quarter of 2013. The increase was due to record production in the Marcellus, which averaged nearly 180 million cubic feet of gas a day and drove the production mix in the quarter to 58% natural gas. We experienced some production interruptions and delays in our capital spending due to extreme winter weather conditions in both Canada and the US. Despite these challenges, our crude oil volumes were maintained quarter-over-quarter.

Capital spending of CAD218 million was slightly less than planned, particularly in our US oil assets. Although our drilling program was relatively active, we only completed 11 net wells in the quarter, 2 at Fort Berthold. We continued to see strong well performance, particularly from Fort Berthold region and in the Marcellus. Well results year-to-date are some of the best we've seen out of each of these plays. We've continued with our high density tests and also some very encouraging production results on our first lower Three Forks test that Ray will give you some additional color on.

Despite the weather, our full-year capital remains on track. We are, however, increasing our capital spending forecast from CAD760 million to CAD800 million to account for the change in the exchange rate, given that 60% of our program is spent in the US. We continue to see strong capital performance and expect to sustain the capital efficiency improvements of last year of less than CAD30,000 for on-stream flowing barrel.

We benefited from the increase in both AECO and NYMEX natural gas prices. Our realized natural gas price was over 50% higher than in the fourth quarter. We also saw a significant narrowing of crude oil differentials in both Canada and the US. These changes drove 35% improvement in our corporate netback before hedging compared to last quarter. With the growth in production volumes and the increase in commodity prices, fund flow was up 22% over Q4 to CAD220 million, or CAD1.09 per share. With the ongoing improvement in the sustainability of our business over the last year, we elected to eliminate the discount within our stock dividend program in order to reduce the dilution associated with the program. That changed was effective with the April dividend payment and we saw a drop in participation from approximately 23% on average in the first quarter to 10% in April.

Our previously-announced non-core asset sales closed in the quarter, generating proceeds of CAD117 million, which included proceeds from the sale of our GORR interests in the Jonah field and the final payment relating to the sale of our Montney assets. These proceeds, along with the increase in funds flow, resulted in a further strengthening of our balance sheet. We ended the quarter with a debt to trailing 12-month fund flow ratio of 1.3 times, with over 80% of this term debt and only a small amount drawn on our bank line. So with that, I will turn it over to Ray to talk more about our operational results for the quarter.

Thanks Ian. The cold weather you mentioned did cause some production downtime, and some capital program delays in both Canada and the US. Despite this we continued to advance programs across all of our core areas. We brought 11.5 net wells on stream during the quarter, down from 19 net wells in Q4. This reduction was in part the plan and in part due to weather-related delays.

In North Dakota we continue to run two rigs and were able to maintain production volumes quarter-over-quarter, despite the weather interruptions. We continue to be encouraged by our North Dakota well performance. We command the first high density spacing test by bringing on three wells of a seven-well pattern at the Fur Bearers pad. There are two Bakken wells spaced at approximately 1,400 feet that came on-stream in late December, and a third well that came on-stream in January runs equidistant between these wells, but is 60 feet deeper in the Three Forks first bench.

In the first 90 days of production, one of the Bakken wells produced 115,000 barrels of oil and the second 108,000 barrels of oil. These are impressive rates, particularly given the sustained performance we continue to see. The Three Forks well produced 31,000 barrels in the first 30 days, an average of over 1,000 barrels a day. We have just completed an interference test of these three wells and the results are currently being analyzed. But as you might imagine, we are very encouraged with the performance we have seen to date.

The other well brought on-stream in Q1 was a short Bakken well. This well produced 32,000 barrels of oil in the first 30 days, an average of almost 1,100 barrels a day; our best short well to date, and was our best well per lateral foot. I say was because in early April, we brought on two long horizontal wells from the Snakes pad, located on our northern-most acreage up near the Antelope extension, that are now our best wells to date. We knew this was a good area, and one of the objectives from drilling these wells was to test the lower bench of the Three Forks.

So we drilled one well in the Bakken and one well in the lower bench of the Three Forks. The Bakken well has produced 64,000 barrels of oil in the first 26 days of production. That is an average of almost 2,500 barrels a day. The lower bench Three Forks test has produced 60,000 barrels of oil in its first 26 days, an average of 23,000 (sic - see press release, "2,300") barrels a day. These cumulative production rates make them the top performing wells we have drilled from an IP30 perspective, and also are some of the best wells ever drilled in North Dakota.

We are excited about these results. We know this area is very productive based not only on our own well results, but also the results from other producers in the area. However, we know the lower benches of the Three Forks are not productive across our entire acreage block and we have additional drilling coming up in the remainder of the year that will help improve our understanding of the lower zones. The key technical change driving this better performance is the increased intensity of our frac, which is delivering higher production rates. We are targeting about CAD12 million per well, and these wells are coming in on target.

In the Marcellus production continues to perform well. We averaged 188 million cubic feet per day during quarter one, up almost 10 million cubic feet a day from our exit rate in December. Similar to what we're seeing in North Dakota, frac optimization is driving improved well performance. The amount of sand per foot has increased from 1,500 pounds to between 2,500 and 4,000 pounds and the number of frac stages has doubled. On-streams to date in 2014 with our partner Chief, have achieved average 30-day IP rates of 15 million cubic feet a day, with 2 wells producing over 20 million cubic feet a day in their first 30 days. Our Marcellus production now accounts for over 50% of our corporate gas volumes.

Our realized price increased to $4.06 per Mcf in the quarter, and our netback was CAD2.86 per Mcf. With the increase in NYMEX pricing and production volumes, the Marcellus generated about CAD46 million of net operating income in the first quarter, resulting in approximately CAD50 million of cash flow in excess of our capital spending. We continue to see the effects of supply growth in the region. We have long-term contracts and a transportation to market point on approximately 80 million cubic feet a day, which is helping to mitigate our exposure to these widening differentials. However, roughly 55% of our volumes are not contracted. We saw an average of CAD0.88 -- an average discount of CAD0.88 per Mcf in the first quarter, and April is looking to be in line with the first quarter.

In Canada we continued our development across our waterflood portfolio during the quarter with activity at the Medicine Hat Glauc C and Pouce Coupe Boundary Lake properties in Alberta, and in Southeast Saskatchewan where we targeted the Midale and the Ratcliffe. In addition we kicked off a large program in the Brooks area targeting the Mannville where we expect to drill about 20 wells this year. Our polymer project in Medicine Hat continues to perform well, and we believe is a commercial success. We're preparing for our second polymer injection project, which we expect to implement in 2015.

In our Canadian deep gas assets, we continued to advance our program in the Wilrich and we have also drilled and completed two horizontal Duvernay wells in the Willesden Green area year-to-date. One Wilrich well was brought on-stream late December and three others were drilled in Q1. Of these four wells one was not tied in, two wells were completed and came in around a type-curve and we will complete the fourth well after breakup. We're letting the Duvernay wells soak a few months and expect to bring them on-stream in Q2 and Q3. We'll be in a position to talk about these well results in the second half of the year.

This sums up our operations activities for the quarter. Our capital program is on track with full-year plans before any currency adjustments. And we are well positioned to deliver approximately 10% production growth year-over-year. I will now turn the call back over to Ian.

Thanks Ray. Q1 was another quarter of strong, consistent execution for our Company. We expect to deliver on our plans throughout 2014 with a focus on capital discipline and strong execution. Natural gas volumes are performing ahead of expectations, driven by the strength in the Marcellus, and our oil program is accelerating after tough weather in January and February. We are maintaining our production guidance. However, we expect it to track to the high end of the range given the strong start to the year. With the Marcellus outperformance, it's driving our natural gas weighting higher to 56%. In total we continue to expect we will deliver about 10% growth in production year-over-year.

Reported capital spending is increasing slightly, due to the weakening Canadian dollar and some modest increases in our non-operated spending. If you will recall, approximately 60% of our capital is allocated to our US assets and its denominated in US dollars. As well the weak Canadian dollar is certainly helping our revenue. We are now forecasting approximately CAD800 million, up from CAD760 million previously. Again, I'm referencing the capital. Operating and cash and general administrative costs are unchanged from our original guidance. Cash equity-based compensation expense will increase from CAD0.25 per BOE to CAD0.45 per BOE due to the increase in our relative share price. To date in 2014 our share price has appreciated approximately 25%.

On the people side, I want to take a moment to discuss Board and Executive changes. As you may have noticed, we also announced this morning that Doug Martin, our Chairman, is planning to retire at the end of 2014 after serving the shareholders of Enerplus for 14 years. Mr. David O'Brien is also retiring from our Board and will not be standing for reelection. Doug and David have been instrumental in guiding the Company through not only various commodity price cycles, but also our transformation over the past few years. I would like to thank them both for their contributions. Doug will step down as chairman on June 1 and will remain on the Board until the end of the year.

Mr. Elliott Pew, who is currently a Board member, will replace Doug in the role of Chairman. For those who don't know, Elliott is a geologist. He has extensive experience within the oil and gas industry, particularly in the shales. He was EVP at New Field Exploration, leading the company's exploration program, and was a co-founder of Common Resources. He currently sits on the board of Common Resources II. He has a deep technical and commercial background that will serve Enerplus well.

In planning for these changes, we added two new Board members last quarter, Ms. Hilary Foulkes and Mr. Michael Culbert. Both of these individuals are well known in the industry and they each bring more than 30 years experience in oil and gas. With their knowledge and expertise, it will continue to strengthen our board. At the executive level, Lisa Ower is joining us in the role of Vice President Human Resources. Lisa also brings a wealth of experience to the table and has held similar positions in a number of companies. I welcome our new Board members and Lisa, and look forward to their contributions in helping shaping our future.

On a final note, we do plan to host a session on June 18 focusing on our North Dakota operations and the opportunities we see in the Bakken and the Three Forks formations. A webcast will be held from 10 AM to 11:30 Mountain Standard Time and is open to anyone who is interested. We hope it will make for an enlightening 90 minutes and I encourage you to register for it. Full details will be sent out next week.

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

(Operator Instructions)

Greg Pardy from RBC Capital Markets.

Thanks. Good morning. Just wanted to dig in a little bit into your backlog.

And maybe just to start with the Bakken. How many wells did you drill in the Bakken in the first quarter, so the 30.5 net?

How many well did we drill?

Yes, in the Bakken -- of the 30.5 net horizontals that you drilled, how many of those would have been in the Bakken? Or sorry, just in North Dakota?

That's five net wells, which would effectively be five gross wells as well.

Okay. And then Ian, what is your -- what does the tie-in, so drilling and just tie-in schedule look like through the second, third and fourth quarters? I'm just trying to -- I know you've gotten off to a slower start, but assuming you're going to gather momentum as the year goes on.

Sure. As you can imagine, there's always moving parts around that. But I'll turn that over to Ray to give you a little bit of color.

Greg, thanks for the question. So we have got seven tie-ins in Q2. Sorry, we have got five tie-ins in Q2.

There was two in July that I was counting there. And then in Q3 we have -- sorry, we have seven tie-ins in Q2 and we have seven tie-ins in Q4.

Okay.

Greg as you think about this, I'd anticipate a reasonable build in oil volumes as we move into the sort of second quarter. Sort of flattish and then popping up again as you move through the third. Sort of steady-ish kind of growth.

Okay. So seven in Q2, nothing in Q3?

Not as planned right now.

Not as planned. Okay. And then seven in Q4. Okay. That's fine.

And these will be -- these will be predominantly long reach and then Bakken and first bench at the Three Forks?

Yes.

Okay. That's fine.

And then just on, with the Marcellus now I typically ask you guys, how many wells do you have drilled, net wells that you've drilled, completed, but not yet tied in?

17.6.

Good precision, Ray. Thanks for that. (laughter)

And then what are you thinking in terms of exit rates in the Marcellus? I mean I know obviously it's non-ops so you can't predict per se, but your numbers are really strong so I'm trying to get a sense as to what do you look like going into next year.

It's a very good question. So the Marcellus, we were producing 170 million a day last December. And with really limited on-streams in Q1 we've grown it. So you can see the well results are -- they continue to impress. And so depending upon how that unfolds, that really can move the numbers in.

I would say my expectation is we're growing. My expectation is we're growing as you think about leaving the year relative to the Marcellus. That can move around a lot though.

I think if you step back, Greg, we're targeting corporate growth in that 5% to 10% kind of range. And the last couple of years it's been gravitating to 10%. And that outperformance in the Marcellus has been a decent part of that. So I don't see how that's going to -- I think that's going to continue for a while.

Okay. Great.

And then last question is just with respect to Marcellus egress. You're going to be -- so you'll be able to -- no issues, I guess in terms of moving your gas physically.

Recognize that the good chunk of it is uncontracted. So we're really just looking at an ongoing fairly wide basis, but physically you're still going to be able to move it. Is that a fair assessment?

That's a fair assessment. Let me turn it over to Eric Le Dain to give you maybe just a little more color on this though.

Greg, it's Eric here. We don't see any issues with the physical movement at this time.

But we do see, as you know, a price difference between the spot sales and our contracted volumes. But we are obviously watching it all the time with our partners, on both the gathering side and linked into the interstate pipelines, and we haven't seen any issues at this point.

Okay. Great. Thanks for that.

And the last question is just on the capital. I understand that most of it then was FX-related, but you're going to hold the line, right?

Like you guys have exercised great capital discipline in the last few years, you're going to hold the line this year right, on that kind of a number? On the year-end number?

We're not changing our guidance. And at this moment we don't have plans to.

I think the key for us is to have a plan that makes sense that we can afford. It doesn't rely on equity. And so we'll -- I don't know what your numbers will be, but depending upon how you think about the gas price and the oil price, you can create some pretty stout cash flows over the course of the year. So we'll see how that unfolds. The gas price stays in, there'll be more cash in the system. We've got a lot of opportunities and we want a plan that makes sense.

So at this moment very comfortable with where we are and very comfortable with holding the line. Things can obviously move around a little bit based upon non-op, but at this point I'm really comfortable with the program we have and I think it's going to give us pretty attractive growth.

Great. Thanks very much all.

Thank you.

Aaron Bilkoski from TD Securities.

Hi guys. Good morning. I just have a few questions.

I'll start with the general one. How much production in Q1 do you have to meet with shut-in due to weather?

Probably several thousand. I mean we would have had days where there was more than 8,000, 2 to 3 gas and oil on some instances through third party outages and trucking issues. Then you had a little bit of a delay issue on top of that as well.

Okay. If I moved on to the Marcellus, Greg touched on this, but do you guys have a revised full-year average Marcellus target? Like 120 to 140 seems pretty unrealistic now if you're going to talk about year-over-year growth.

We've said 180.

Okay. And on a gross basis in the Marcellus, how many wells did you tie-in in Susquehanna and Bradford? I'm just getting to how many wells comprise that average that you posted.

That was seven wells, seven gross wells.

So we had 2.3 net wells that were tied in, in the Marcellus, and I'd tell you that probably 2.2 of them were in Bradford Susquehanna.

Okay. And on the pricing side in the Marcellus, what price discount to NYMEX are you receiving on the volumes that aren't being shipped under a long-term contract?

In what time period?

Q1. It was CAD0.88 back on average, but I'm just trying to get a split between, the discount between what was shipped on contract and what was shipped not on contract.

Probably -- Q1 was a bit unusual because the volatility, as you know, at the market points was so significant. But in general, the marketed contracted is coming in at about half the basis differential of the un-contracted, or call it spot sales.

And we're seeing that in, for example, April all of the market data is out there now, Dominion South and other contracted market points is roughly that same relationship, half of the spot.

And would you guys have the opportunity to lock in more long-term takeaway contracts? And what price would you be looking at doing that at? Would it be still CAD0.40 back?

We're always looking at our contracting strategy there including long-term takeaway, which can have quite long terms of 10 years and so on. But it really depends where your contracting out at this point depends on the full tolls, if it's a transport physical related deal.

On the financial side, we can still contract out a few years on the Dominion South-type points, but it's not a very liquid market for past a year on the spot sale points of Marcellus -- Marcellus zone 4 or [Lydee]. And we just don't -- we're not interested at this point in contracting financially to fix the basis because the market, as you know, is quite negative about basis in this area.

And the reality in the day market is a bit different, and is more representative of what we see in terms of the supply/demand picture. So we just don't see any real value in term financial contracting. But on the physical side, we're always looking at that and we're always talking to our customers in the area and looking at arrangements that might move out more than one year, or part of a year.

Perfect. Thanks. Two more questions. These are both in North Dakota.

Am I correct to assume that there is no second bench Three Forks locations booked in the 2P or the 2C reports?

You are.

And the final question is, I realize it is kind of early and I'm asking you to speculate, but what proportion of your North Dakota acreage do you think is prospective for second bench? Just orders of magnitude, 10%, 20%, 30%?

I might have written the TD note slightly different this morning. (laughter) So we are quite confident it does not extend in a commercial way to the southern portion of the acreage. And we have proven we have it right at the northern portions of the acreage.

And so it is difficult to know where that transitions. If you look on a map you can draw a line that sort of takes about one-quarter of our acreage -- there's a possibility you could see one-quarter of the acreage, but we don't know yet.

There is some more data coming to us from third party, actually non-operated that we're participating in that we would anticipate gives us some data. We're drilling right now, actually. So this is encouraging and it's difficult to say exactly how meaningful it is.

Okay. Fair enough. That's it for me. Thank you guys.

Thanks, Aaron.

(Operator Instructions)

Kyle Preston from National Bank.

Thanks. Good morning guys.

Just one general question here, somewhat related to the last question Aaron asked, but more relating to your downspacing initiatives in the Bakken and North Dakota there with the high density well pads you've done to date and the success you've had there. Can you give an indication of how much more confidence you have you in those 150 potential downspacing locations you've identified in the past?

We have an extreme -- sorry, so let's just make sure we're on the same page. If you look at our 2P report and our contingent resource estimates, that has just under 150 locations in it.

That's that seven-year inventory at the current pace of development. We have an extremely high degree of confidence in those locations.

And we believe with a high degree of confidence, they are going up. The number of locations is going up. And we'll give people some flavor and hopefully some quantification of that as we talk to people in June with maps and details and the like.

And if and when would you look at accelerating that program, just given the success you've seen?

I think acceleration, if it happens, is probably a 2015 kind of thing. Right now we're running two rigs.

Actually at this red hot minute we're running three because we're transitioning out of one into another. We're able to get all of the information we want with the pace of this program. It provides a financial picture that makes sense to us. It's affordable, those sorts of things.

As we are able to sort of talk about a broader inventory and quantify the scope of that, I think that then sort of lends you into a conversation about how much inventory do you have, should you be accelerating that with, obviously with the added benefit of present value acceleration, does that financial plan make sense? What are the other alternatives we have as well?

We've got a lot of interesting things going on in the Company. But I think from a timing perspective it's really a 2015 budget kind of conversation.

Okay. Sounds good. Thanks a lot, guys.

Thanks Kyle.

And we have no further questions in the queue. I'll turn the call back over to the presenters.

Well thank you everyone. Appreciate you calling in this morning.

And hope everyone has a great day and a good weekend. Thank you very much.

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