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Enerplus Corporation (NYSE:ERF)

CIBC Whistler Institutional Investor Conference Call

January 24, 2014 12:10 ET

Executives

Robert Waters - Senior Vice President and Chief Financial Officer

Analysts

Jeremy Kaliel - CIBC

Jeremy Kaliel - CIBC

Okay everybody. Well, we will get started with our next presentation of the morning. Our next presenter is Enerplus. And we are very happy to have from Enerplus, Mr. Robert Waters, Senior VP and CFO with us today to present. Robert is going to give a short formal presentation and we are going to settle down by the fire for a little bit of a chat. My name is Jeremy Kaliel, I am the analyst at CIBC covering dividend paying intermediate E&Ps. And it will be my pleasure to moderate this event, but I will hand it over to Robert.

Robert Waters

Okay, thanks. Thanks Jeremy. Enerplus had a very good year in 2013, but it really wasn’t something that crept up on as we have been working hard to lay that groundwork for the last three or four years at Enerplus and it’s been a long time coming for us. We have significantly – we have significantly repositioned the portfolio. We have become a much more focused company focusing on fewer properties with better economics, better scope and scale. We have invested in some top tier oil and gas properties that will, I am sure, we will talk about later. We have sold a lot of non-core properties significantly repositioning the portfolio. And we did all of that and all the while through that transition, we have kept a very conservative balance sheet. And as I speak to you now, we continue to have a conservative balance sheet.

Now, the shareholders are starting to realize that the benefit of that repositioning. With the portfolio that we have developed and the skills that we brought in to our organization, we are seeing much more a disciplined capital allocation. We are seeing cost control on our capital spending. We are seeing increased production and all that translates into as increasing capital efficiency, which is the Holy Grail in the oil and gas business. So we are improving our efficiency, production is increasing, costs are dropping and that means we are increasing cash flow and cash flow per share. And so what that drives is it improves sustainability, not only just for our dividend, but for the whole business model that Enerplus is about and the business model is to deliver sustainable profitable growth and income to investors. So combine that, this year 10% production growth is projected, our dividends currently running at about 5.7%. And so if we can consistently deliver that year-in and year-out, we think that, that is a low risk wins investing in the oil and gas industry.

In terms of the portfolio itself, we are focused now on four core areas. And people that haven’t followed Enerplus for a number of years, we would be surprised to know that 50% of our production is coming out of the U.S. right now. These four areas represent about 90% of our net present value on a reserve basis. We expect to produce about 98,000 BOEs a day in 2014, that’s the midpoint of our guidance. About 48% of that will be crude oil and liquids. And two-thirds of the liquids will be light oil. So, oil, U.S. oil and natural gas now represents over 50% of our production is attracting about 60% of our capital spending. These are the growth engines of Enerplus right now, Williston Basin oil, more specifically North Dakota Bakken oil and on the dry gas side, Marcellus shale gas. We have lots of running room yet to go on those properties.

In Canada, we have eight operated waterfloods. Those are mature assets, but what we like about those is those are the cash cows of the company. We can reinvest only about 50% of the cash flow that they are kicking off and still get single-digit production increases. And what’s even better is they have a very low decline rate, a 12% average decline rate. So that compensates for the high decline we are seeing in some of the growth engines. And overall, Enerplus as a company only has a 24% to 25% average decline rate, which is pretty low compared to many of our peers.

And finally in the Canadian Deep Basin, we have large land holdings and some emerging plays such as the Wilrich and the Duvernay in Williston Basin. And those plays we have just begun to delineate. So that’s what we look like now in terms of the asset base. We have been delivering organic growth. No longer are we dependent on acquisitions to replace production. That’s a big step change for Enerplus. Expect 10% production growth this year, 9% per share production growth. We are growing both oil and natural gas production. We are spending about $760 million in CapEx. More importantly though is the cash flow and we expect to grow our funds still by 5% even despite the fact that crude oil is in backwardation and natural gas prices and we will talk about differentials in a few minutes can be challenging at times more because of the productivity of these plays that we are in. So in spite of the fact that we are 50% natural gas, we are still achieving this kind of cash flow growth.

And as I said before, we have maintained a strong balance sheet and financial flexibility throughout the whole turnaround story. Originally, when we got into these early stage plays, we were outspending our capital and there were a lot of questions about the sustainability of our business model, of our dividend, how are we going to fund that funding shortfall. We were able to do it through a combination of the sale of non-core properties oftentimes making significant gains in terms of what that property had originally cost us. We also right-sized our dividend. Our dividend is now about 30% of our cash flow, which is a very reasonable, manageable level to us. And of course, the increasing cash flow and efficiencies is certainly helping us in bringing down that adjusted payout ratio to the point that we are now in the phase that we believe our business model is sustainable.

And so maybe just to conclude a few keywords here. In terms of what we bring to the table for competitive advantage, a very focused portfolio compared to what it used to be, we have got some top tier resource plays with significant running room in them. We have got a lot of discipline around our capital allocation process now and in fact we are seeing the benefits of that with our capital efficiencies running below $30,000 per flowing barrel last year and we are projecting it for this year as well. A low corporate decline, significant inventory of organic grow and a strong balance sheet. And so we think that all comes together in a model that delivers profitable growth and a sustainable dividend consistently.

Thank you. Now I will sit down for my fireside chat.

Question-and-Answer Session

Jeremy Kaliel - CIBC

Yes, I am (indiscernible) by the fire.

Robert Waters

Yes.

Jeremy Kaliel - CIBC

So I will get the Q&A rolling here, but as always we do encourage questions from the floor, so just raise your hand if you would like to try to ask your question. So Rob, first question, I mean many investors would consider Enerplus that the template would turnaround, could you comment on what you think the key things are that have changed Enerplus, where the Enerplus is executed on maybe like how does the new Enerplus compared to the old one? And when was it evident to you that the company was turning for, at what point?

Robert Waters

I think I hit on a lot of the things. The basic thing is just changing your portfolio of assets and high grading it, selling non-core assets, but not shrinking the company to do that but reinvesting the proceeds back into top tier properties that are going to deliver you first quartile economics and good F&D and good recycle. I think that’s key. And before we invested in North Dakota, Bakken and the Marcellus, we actually studied all of the resource plays in North America. And so our technical team at that time picked those two places having the most potential. And I think now when you see the results from it, certainly that the community would agree that the Marcellus is one of the top dry gas plays in North America. And the North Dakota, Bakken is also one of the top crude oil plays. So we got it right there. But it’s not just adding new assets to the portfolio you have to dispose of the non-core properties that you are not going to spend capital on them because they don’t meet your capital hurdles.

The other thing you know is improving capital efficiencies. Quite honestly, if you can get to the point where your costs are dropping because of the completion technology and the pressure that you can put on the service companies to reduce costs and just doing things better and you get higher production. As I say that’s just music to our ears in terms of the oil and gas industry because that’s what it’s all about capital efficiencies. And we are seeing that. Some of it’s the nature of these plays and some of it’s the talent that we have brought in over the last five years in the company. And with that it just naturally generates higher cash flow and sustainability I would say.

When did we see a turnaround like I can speak for myself we could see it turning around in 2012. And if you think of it, you look at our stock price, that year was not a good year for us, but we had confidence, because we could see the productivity in the Bakken, we could see the productivity in the Marcellus. And at the time the market was penalizing us because we had to increase our capital guidance a bit because of the inflation that was happening in these early stage growth plays and they penalized us for example in the third quarter of 2012 because we had to reduce our production guidance because we said that for example the Marcellus was being delayed in terms of tie-ins and completion. And – but it was just a delay. It was a timing issue. These problems you have in early stage assets and sure enough come December and January of 2013 not Marcellus production showed up big time and it’s continued to show up. And even today it’s showing up big time. So we had faith back in 2012 and we knew that this was going to work.

Jeremy Kaliel - CIBC

And in the Marcellus in particular, could you talk a little about the current pricing environment like what do you realize price that’s currently in the Marcellus and what’s your outlook for natural gas prices and NYMEX prices going forward?

Robert Waters

Right in the Marcellus we are sort of a victim of the success of the play and that there is a lot of gas being produced like it’s we are drilling 12 Bcf to 13 Bcf wells and not only as they are coming on very strong they are staying strong longer than a lot of people expected. And so you have a lot of gas that’s built in that North Pennsylvania area. We use to – when we first got into the play sell our Marcellus gas as a premium to NYMEX because you are right up against the big New York market. And now in the third quarter last year we haven’t released our year end results. It was a $0.50 negative differential to NYMEX.

We’re projecting that, that differential will widen out. This year we’re projecting in our guidance we’re assuming negative $0.75 for this year and next year. But eventually we do anticipate that with additional pipelines and additional off-take capacity that, that problem will dissipate and we’ll see a dropdown to negative $0.30 in three years. So it is a challenge that usually and we are in the dry gas Marcellus, so normally you’d say my God there is a 75 hit - $0.75 hit your economics. But – what you don’t appreciate is just this year productivity of the wells that overcomes that difference. So if you’re realizing and I’m a little out of date on my NYMEX pricing so excuse me like a 4.40 NYMEX price. We would say around the end of the year you’d probably see differentials in the minus $0.60 to minus $0.65 in the month of December on that and so that certainly takes it down. Our royalty rate in the Marcellus would probably be running about I’m guessing in the mid 20% and our op costs are running at about I would say $0.66 per Mcf. So in the third quarter our netback or operating netback sort of what we’re seeing before G&A is something in the fact of a $1.70 still.

And to give you some idea of the economics of the play, if you are drilling 12 to 13 Bcf wells there and you assume like a $4 NYMEX with a $0.75 negative differential. Those wells would give you a rate of return of 40% to 60% still. So that’s why there is so much gas being produced in the U.S. right now and that’s why gas prices are low is you can make 40% to 60% return drilling dry gas, even despite the fact that you got a negative 75% dip.

Jeremy Kaliel - CIBC

And could you remind us how much you plan to spend on the Marcellus? I’m sorry.

Robert Waters

Well we’re planning to spend about I’d say $125 million roughly, near the end of the year we actually bought more Marcellus and incremental working interest in the wells that we already own. So it’s up slightly from last year, so spending about $125 million.

Jeremy Kaliel - CIBC

Any questions from the floor? Yes.

Unidentified Analyst

(Question Inaudible)

Robert Waters

Yes. The question – sorry the question is do we try to hedge this and hedge that differential and it’s really hard to hedge the differential, I’m talking about the differential that Marcellus gas as to NYMEX and so it’s really hard to hedge that. There is dynamics in Marcellus than that it has two trunk lines going through at least where we are in the Marcellus, the Tennessee and the Transco. And I’d say that people that are up on the Tennessee have an even harder problem because there is more gas getting locked up there and the differentials can be a lot worse than $0.75. We have about 85% of our gas that’s linked to the Transco which has relatively better differentials and we have about 50% of our gas right now that we have firm pipeline capacity on.

And obviously as our production rises in the Marcellus we got to watch that and make sure that we continue to have capacity on the pipelines to move it out of there. It’s a problem that will get fixed eventually. We think it’s a two-year problem. And in terms of just overall gas hedging maybe I will hit that too. In terms of hedging we have about 59% of our crude oil hedge for this year at about $94 WTI and we have no oil hedges for next year. It’s hard to hedge when the oil prices in such backwardation right now. On our natural gas side, we have about 34% of our natural gas hedge this year at about a NYMEX $4.14 average price. And just a little bit of AECO hedge. And we are not out with our year end results, so I have to be a bit quiet, but we have continued to layer-in some gas hedging into 2015 just taking advantage of where the prices are now, but it’s not material, it’s just layered in gradually over time.

Jeremy Kaliel - CIBC

And outside of the Marcellus and for Canadian gas prices, specifically we have seen a strong recent recovery (indiscernible) is now below the five year average, I mean how does this recovery in AECO prices affected your plans for 2014 spending at all?

Robert Waters

I would say no, it hasn’t. When we set the budget for 2014, we actually assumed prices internally that were slightly lower than what you are seeing on the forward market right now, but not overly lower. We are very careful not to increase our capital spending a result of what might be a short-term weather event, like we love this Polar Vortex, don’t get me wrong. But we don’t know how long that’s going to last and we also are wary of the productivity of things like the Marcellus. So we haven’t seen enough run time on this recent gas price increase to really make us change. We did increase our capital spending by about 11% this year, but that was more driven off the fact that we had a good cash flow year last year. We were able to sell some non-core assets and so we felt we had a little bit of walking around money and we wanted to drill some delineation wells in the Duvernay and the Wilrich to be honest with you and we thought that we could increase our capital spending a bit this year and achieve that without really creating a problem in terms sustainability. So that was more driven off of other things other than just this temporary gas price and hopefully it’s not temporary but increased.

Jeremy Kaliel - CIBC

Well, maybe keying on those two assets, the Wilrich and the Duvernay could you – starting with the Wilrich just elaborate what your recent well results have look like at Antelope? How big inventory you think you might have, and what your plans are for ’14?

Robert Waters

Okay. So the Wilrich is and very in around Ansell area Minehead. The Wilrich is a dry gas play like the free condensate would only be about 7 barrels to 10 barrels per million. So it’s a dry gas. We have drilled about four wells into it and two of those wells is sort of within our type curve expectations, which I would guess run at about 5 Bcf to 7 Bcf well. But then the other two wells were significantly above the 7 Bcf well. And they continued to perform well. So we have got these two wildcard wells that are performing very well in terms of productivity.

And so in 2014 we have plans to go in and complete five wells in the Wilrich. Some of which were drilled last year, the tail end of last year. And we are also going to drill three more wells and those will probably be completed into 2015. And so I think the drilling has just begun and we don’t have any well results out of the Wilrich. If we get wells that beat the 7 Bcf type curve there, they are very economic. Like I think our Wilrich would probably be running probably a 40% return if you can get a 7 Bcf well. And I think the challenge with the Wilrich is also to control the cost of drilling and completion of wells. And so we would be targeting about $7 million drill and complete cost there. And so that is sort of something that you will have to wait and see. We don’t – we haven’t drilled the wells that’s something a catalyst for this year to watch.

On the Duvernay, we are out looking for a joint venture for the Duvernay a while ago and we got interest in it, but at the end of the day we are in the Willesden Green area, not in the Kaybob area. So we are south of Kaybob where all the action has been. The feedback we got is this would be a lot easier if you were to drill some more wells into your property. We have three vertical wells into our Duvernay section that are not on production, they are essentially test wells and they would indicate that we would be in the liquids rich window. In the Duvernay you don’t want to be in the gas window because it’s not economic, you are not getting condensate. You don’t want to be in the oil window on the other side because you don’t have enough gas lift to get the oil out of the ground. You want to be in the middle. Right now everyone is trying to define where that middle is that – and you are looking for 75 barrels to 200 barrels of free condensate per million. And so we have currently drilled our first horizontal producer, it’s in – it’s just being completed as we speak. The good thing about the – where we are in Willie Green is there are facilities there unlike Kaybob and so we expect to get it tied in fairly quickly. And then we have also started drilling the second horizontal producer now. And I think it’s just in drilling stage.

So I would say that probably by mid-year we should have some Duvernay, Willesden Green production results. And in there the things to watch for is what’s the free condensate level are you in that 75 to 100 barrels per million and also what’s your productivity, because if you can get something in the range of 4 million a day would be ideal and the economics are extremely strong on that. And we have 85,000 net acres of Duvernay, we owned 100%. We are in at about $750 an acre. And so if that works to frame it for you, four wells per section that’s 300 to 400 horizontal drilling locations on our land that we own right now. And to put that in dollars, that’s for approaching $5 billion of capital spend to develop that play. But just to manage expectations, we are into our first horizontal producer wells this year. So that is another thing to watch for, I would say.

Jeremy Kaliel - CIBC

Now, if you are completing that first horizontal now, is there a chance that we are going to get some results out of you from that at year end results?

Robert Waters

No, because when they completed and again I am the CFO, I think they like to let the wells sit for a while and there is all kinds of special science they do the well and then they wind. And typically, we like to get some runtime on these types of wells before we start talking about them publicly. And so I would say you are more likely to hear about it sort of July-August.

Jeremy Kaliel - CIBC

Okay, sorry, I will be watching that closer.

Robert Waters

There are – there have been some competitor wells in the Willesden Green Duvernay that are now being public that are quite interesting. And I think you published on them, yes, but it’s still a very high risk play and that’s why we are only drilling two wells right now. We have a very measured approach to risk at Enerplus and we go about things in a measured way and tend to drill it, study it, and we are very, very disciplined on economics. If we don’t get that condensate, we really have to look at is this a play we want to stay in.

Jeremy Kaliel - CIBC

Okay. Maybe shifting gears and talking a bit about your North Dakota Bakken play, could you talk about your latest results where your current production level is at Fort Berthold and maybe what we can expect to the (indiscernible)?

Robert Waters

Yes. I can’t tell you the current production, because that’s getting close to year end recording, but I will tell you our guidance is to increase Fort Berthold production by I think it’s 33% on average. So we expect to average 22,000 BOEs a day out of Fort Berthold in 2014, so significant growth there. It’s going well like we have got two rigs running. We will drill 20 to 25 wells in that play this year. What I really like about Fort Berthold is that not only that we have got – the production is increasing per well and I will go into that in a minute, but the costs are also coming down, again cost coming down, production increasing, that’s capital efficiency. We are getting more bank for our buck. The reason why the production is increasing is we changed our completion design, we used to use more expensive ceramic proppant and we are following the lead of one of our competitors in the region that was using much cheaper white sands, ceramic cost about $0.50 a pound and white sands about $0.04 a pound. But what they are doing is they are doing way more frac stages than we used to and they are pumping a lot more fluid and proppant in. And as a result of that and we have got about six wells, six or seven wells following that new completion methodology. Our 30-day IP rate is up 55% on those wells and so significant out-performance in terms of our type curve. And it’s still early days, we have about maximum 200 days of run room on the first well, but we like what we see.

In addition, the cost of drilling and completing wells has gone down in Fort Berthold, because we put everything out to tender and there is lot more services in there than they were in the early days of the play. And so in general, the cost per frac stage is down about 15%. So if you do the numbers, we have got about 20% improvement in capital efficiency there. And so that’s going very well. And then on top of that, we are now we – we have see competitors drilling into the second and third bench of the Three Forks. And where we are in Fort Berthold, we know that there is Bakken across our whole acreage. We know that there is a first bench of the Three Forks across our whole acreage, but it’s probably 70% as productive as the Bakken, but our competitors have been drilling down into the second and third levels of the Three Forks in getting success.

We have been coring wells across the acreage and although we don’t think we have second and third benches down in the south part of our acreage certainly in the Northwest, it looks very interesting on core. And we actually have our first well now being completed, I believe into the second bench of the Three Forks right now. And so if we can open up those horizons, second and third bench even if it’s in the north, just in the Northwest portion of the play that adds significant resource that we weren’t expecting. Also we are drilling our first – a lot of our competitors have been increasing the density of drilling on a spacing unit. And we have just been assuming two Bakken wells, two Three Forks, four wells for spacing unit, some of them are going to eight wells for spacing unit. We are doing our first test right now of a 7-well spacing unit. And we are working on the first three wells of that. We are going to get them on and see how they produce and then do the other four and we will monitor that.

If you can downspace on the Bakken, it doubles the amount of drilling locations you have. And so there are some powerful things that early stage that we are starting to work on. And the good news is the benefit of going slow and just keeping two rigs running is you get to see what your competitors are doing and you see what they do wrong, but you also see what they do right and you can emulate them and then you can tune it up to your properties and what you are doing. And that’s really what we have been taking advantage of. So it’s quite exciting like downspacing opportunity, lower Three Forks opportunity and a better completion design there.

Jeremy Kaliel - CIBC

We are almost out of time, but I want to squeeze in my favorite question. What catalyst should investors have on our radar screens for Enerplus in 2014?

Robert Waters

I think you got to watch, well, watch for our year-end results and watch for our year-end reserve report, watch for the results of these two Duvernay wells until we get the gas productivity and the liquids content we are looking for, watch for the results out of the Wilrich, are we going to – are we in a sweet spot of that play and we are going to get some high productivity wells there, watch Fort Berthold for the downspacing tests that we are doing and for the lower Three Forks bench we are doing and watch the Marcellus like does it continue to surpass the expectations in terms of productivity of that play. And also maybe I’d say a lot of people saw our stock run in 2013 and I get asked a lot of questions in the one-on-one is it did I miss it as it’s already run. I would just point out that the stock is responding, because we have been increasing cash flow per share. When you compare our values to our peers, we are still at a very low value. And what we have to do is continue to deliver in terms of meeting or beating our guidance and continue this capital discipline and continue the path we have been on. And I think we have to earn investors’ trust. And that takes time, we acknowledge that. We have had four good quarters under our belt. And so our team, our management team is very focused on to continuing that trend of delivering that guidance before.

Jeremy Kaliel - CIBC

Great. Well, let’s look out for 2014.

Robert Waters

Sure. Well, thank you for your attention everyone.

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