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Executives

Gordon J. Kerr, President & Chief Executive Officer

Analyst

Peter Tateishi – Bank of America Merrill Lynch

Enerplus Corporation (ERF) Bank of America Merrill Lynch Global Energy Conference Call November 13, 2012 2:50 PM ET

Peter Tateishi – Bank of America Merrill Lynch

The next company on our schedule is Enerplus. Enerplus is a Mid Cap yield oriented oil and gas company. Key assets in the Marcellus and oil assets across Western Canada and North Dakota.

I’d like to introduce, Gordon Kerr, CEO and President.

Gordon J. Kerr

Thank you, Peter. Thanks for joining me. I’m going to talk a bit about the company from a profile perspective, then I’m going to talk about some of our key plays, and in terms of our strategy as we go forward.

First of all, in terms of the corporate overview, and with Enerplus it’s really about is the – we are looking to deliver what we’ve now labeled the modern growth for our shareholders, but also an income component. Our current yield is in the order of 8%, and over last few years we really worked to redefine our portfolio of oil and gas assets, and we think we’ve positioned ourselves in some of the best resource plays in North America, some of which offer earlier stage growth opportunity with both scale and scope in terms of the option value, and then producing assets that also generate cash flow and offer further development opportunity.

We have consistently worked to maintain financial strength in terms of keeping flexibility, so that we can execute on both our capital spend program as well as strengthen sales up for any M&A opportunities that come.

When you look at the corporate profile of Enerplus, we do trade on both the Toronto stock exchange and the New York stock exchange under the ERF symbol. Our current enterprise value is about $3.5 billion, and we’ve got a fairly healthy trading in terms of our stock and liquidity there.

For 2012, we announced that our guidance has been shifted down to 82,000 BOE a day equivalent, and if you listen to our call, lot of that has to do with the tie-in of natural gas in the Marcellus shale play area.

We expect that production through the course of the year, and we’re there now to be above 50% oil and natural gas liquids as well as 50% natural gas itself.

With regard to our 2012 capital spend program, we’re sticking with an $850 million spend for this year, and you can see that the waiting is largely to the oil and liquids plays that’s 75%. Post the Q3 or at the Q3 quarter end, our debt-to-cash flow or funds flow was about 1.9 times, and then we pointed the fact that we’ve entered into a transaction to sell our assets in Manitoba, if you put it in on a pro forma basis, would take us to about 1.5 times in terms of the leverage factor.

Just looking at where our assets are in North America, we hope number of waterflood properties in Central Alberta region, as I said we’re selling out of Manitoba here, but also extending over into Saskatchewan.

We have some new play areas up in Canada, the Montney, the Stacked Mannville and the Duvernay, and I’ll speak more to those in a moment. And then we have our interest in the U.S., we’ve been in the Bakken oil play in Montana going back to 2005, and we got into the Marcellus shale gas play back in 2009 when we did a structured financing deal, and we satisfied the carry obligations of that here in our third quarter.

In terms of what we look forward to in terms of growth, as I said, we did modify our projected outlook for annual average production this year, but what this is showing you is that since Q3, 2011, we’ve realized somewhere in the order of 11% growth, up to the third quarter of 2012, and notably as I said, an increase in our oil activity here, we are expecting annual growth this year, and again with that 82,000 and the next set in the order of 85,000 to 88,000 BOE a day equivalent. In the order of about 9% over the year, and 47% on exit.

Now we indicated the range here in terms of our exit again, back to principally the Marcellus shale gas play in the timing of those tie, but since fourth quarter of 2011 as noted here, we’ve grown our oil production by about 16%.

It has been and continues to be a key element of how we manage ourselves is to retaining financial flexibility. So if we look at what we did in 2012 to manage our balance sheet, first of all we did raise equity at the beginning of the year, $330 million of equity, we did a private placement of debt, largely here in the U.S. market with a 7 to 12 year term, at about a 4.4% coupon rate. We did reduce our dividend, we cut it in a half here with the July dividend payment, and we also implemented a stock dividend program, which expanded the access to not only our continuing shareholders under the old DRIP, but also to our U.S. shareholders.

Now, we also monetized our equity position in Laricina, which is an entity player and up in Canada, and we monetized that for $141 million. We’re basically with that disposition right out of the oil sands space and we reported in our third quarter, the economic gain was around $86 million on that disposition.

Recently, we also announced a transaction to dispose off our assets in Manitoba, the proceeds under that transaction which we expect to close at the end of the year are in the order of $220 million. And these waterflood assets while waterfloods are critical in the working interest there, they’re good assets, but in terms of worth though fit in our portfolio going forward, now we thought that this was good transaction to carry out.

Also we’ve recently renewed our syndicated bank line of credit, the billion dollar facility, again we go through a three year sort of term on the, non-term out, but term and in terms of the syndicated facility, so that has been renewed, and at the end of the quarter, we had about $700 million that was undrawn, and that’s before considering the proceeds that I just mentioned in terms of the Manitoba sale of assets.

Now, we’re also looking at our hedge position, and certainly we work to provide oil hedges, certainly prices have been more supportable in terms of work on the oil side of the equation, we have about 63% of our oil on an net of the royalty basis hedged to around $96 here for 2012, and then we’ve also put in place hedges for 2013 which represent about 58% of our production, and that’s before the disposition of the Manitoba assets, which if you read – they constitute about 1600 barrels a day of oil production, and that 2013 hedge is at a WTI reference price of just over $100.

On the natural gas front, we have very little of our 2012, natural gas hedge because where the commodity price has been, we have a few hedges that basically represent about 7% of the production to the final two months of 2012, but we’ve been starting to step into hedge positions for 2013. And as noted here, we have a combination of swaps and purchase puts that put a floor in the order of about 331,000 cubic feet of gas.

And I just tell you, and I think we indicated in our release that we would look as we move into the winter heating season here to put more natural gas hedges in place.

Let me turn to one of our key areas that’s been a growth area for us here over the last couple of years, and this is the Fort Berthold region within North Dakota. And in terms of what’s the play here, we hold approximately 70,000 acres in the play net to us. At year end 2011, we had 2P reserves in the order of just over 55 million barrels equivalent, and we also had assessed around 49 million barrels of contingent resource.

If you think back, and you looked at our contingent resource assessment, the prior year we had about 60 million barrels effectively moved into the reserve category and also shared with the – basically the Bakken, and then we added about 19 million barrels of contingent resource with respect to Three Forks formation here.

Now there’s been some recent transactions in the Three Forks relative to the Three Forks in its prospectivity. In that year end contingent resource assessment, we had about 35% of our acreage across the play area considered in the resource assessment, we think its greater than that, and we look to the future and right now based on that 19 million barrels of contingent resource together with our Bakken locations, we have about 130 plus. As noted here, our Q3 production we’re in quarter about 12800 barrels a day of production and we’re looking to increase that through the course of the year, up to the somewhere in the order of both 15000.

Never the late for this property, we think we can get up over 20,000 barrels a day of equivalent production out of this play area. In terms of well results, we currently have 66 net operated wells on production with two-thirds tied into gathering system, so we are in the process of connecting our wells on a – into a gathering system as we go and we expect to have four more wells producing by the end of the year.

We’ve actually done, I’d say some changes in terms of our collision approaches on the play area, and the reality is we weren’t happy with the variability that we saw coming out of some of those things. So for example, we’ve reduced the number of stages in terms of the fracs and we also played around a little bit with the amount of profit been delivered in there. But having said all of that we’re coming back to our completions in the order of 28 to 29 stages.

We’re actually seeing some improvements in our drilling rig days, in fact some of our pad well drilling and we’ve done one for well pad within the order of around 25 days, maybe even though a little better than, which sets the stage for into continued cost improvement. In aggregate, our view on the drilling side is about 5 million for drilling a Bakken long well and 6.5 million for the completion. And then we would factor in about another 1.1 million to 1.3 million for the tie-in and the connection at the well sites.

With respect to the Three Forks, we’re gaining confidence in the prospective of this particular zone. We have four wells with more than six months of production as we note here. They’re tracking the type curve. And we basically – we haven’t developed fully to type curve here, but what we’ve done is we said well, we’re going to limit it to about 70% of a Bakken long.

The best well is on pace to produce as we stayed here 100,000 barrels in the first year which would be comparable to a Bakken type well. We’re still assessing in terms of what to play here between the zones relative to communication what’s rig lateral spacing relationship with the rig vertical spacing relationship. For 2012, our drilling program was largely single wells for pad and a lot of that was driven by the retention of the leasehold, so making sure that we retain our leases. In between this year and next year’s spend program, we expect the majority of our production in the Fort Berthold region will be held by production.

And we’ll do this with a two rig program over the course of next year. So we started those beginning of 2012 by four rigs in place. We produced down to the two best rigs and we’re seeing the benefit of improved efficiency there in terms of rig time in execution.

And here is a couple of graphs just to give you some perspective in terms of what we’re seeing in terms of the well performance here. The way it work here that as we go out over time, the on the bottom and the cumulative production going up to the left hand axis. You can see that, we’ve got six wells in the Three Forks here and this is relative to a Bakken or short Bakken type curve.

And you can see that we’re seeing performance is coming out to the short Bakken type curve. Notably on the right hand side is the long well performance. So the wells that we’re drilling in the order of about a 9500 to 9800 foot lateral in terms of how Three Forks is comparing relative to our Bakken well experienced here. So we’re quite encouraged by what we’re seeing in the Three Forks and what is sets up for in terms of future drilling opportunities to preserve, capture and most importantly net economic value.

I just looking at the economics here. Again this graphing here is showing you basically in a red line a Bakken at 800,000 barrels of estimated ultimate recovery, a different well costs and what the rate of return would be on these wells at the forward curve and we’ve got the forward prices lease throughout October 11 and I think the curve come off a bit It gives you a sense in terms of where the returns are on these wells at the various cost scenarios. And again as I said, the Three Forks we’re basically staffing at about 70% of a Bakken long, time will tell in terms of what that may give us and when we do a fully developed type curve on the Three Forks.

And the only other thing I’d note maybe with respect to at this point production coming out of North Dakota as we’ve seen a lot of variability relative to the differential as a lot of things that play certainly with regard to delivery of crude not only out of North Dakota but out of Canada. We have I think taken a relatively conservative view. We factor in about a $17 haircut to West Texas intermediate pricing in terms of a field capture price on our Fort Berthold play area.

And again when we look at Fort Berthold relative to Enerplus, again we’ve had over 200% growth from Q1 2011 to Q3 2012. So again this stands with our broad if you will timeline in terms of developing this resource and bring cash flow forward. We just turn for a moment to our oil waterflood properties and again this is focusing on the properties that we will continue to hold within our portfolio closely Manitoba sale.

Large regional oil in place is one of the attractions of having these type of assets in our portfolio. The 2P reserves are book to about 26% recovery overall and 22% recovery to-date. We have a couple of key areas where we’re actually entering into EUR space as well as incremental oil recovery further an incremental oil recovery development and notably at our Med Hat Glau C property in the Southern part of Alberta.

We’ve actually been doing additional drilling and conversions of producers into injectors with additional producing wells drilled. And we’ve seen our production improved there in Australia, I think I’ve done it here in a moment in terms of what that looks like, Donald just tell you about it.

And the second area is over in Giltedge where we’ve been inject polymer for well over a year now. We thought early response that we’re seeing an incremental uplift in the production. And these two properties holds the largest part of our contingent resource assessment here 54 million barrels of contingent resource. I think about 45 million resize is an opportunity need to player.

In Biolarge, there low decline assets, they’re in the 10% to 12% type of range. We invest both 50% to 60% of the cash flow back into these properties to essentially maintain and we’re looking for marginal growth and certainly additional reserve capture here.

And with respect to what we seen overall on our Waterflood properties, this is what I’m talking about we’ll see some incremental growth, the low decline in these assets and they continue to deliver for us. And so that’s why we continue to invest in them.

And just turning to Marcellus for a moment here is the fiction of the acreage of the North Eastern Pennsylvania. And we have actually you know two operators here we actually have smaller working interests that are operated by to anybody who have chance to listen to speak about the direction and natural gas, mike want to understand we are also somewhat connected to a story albeit we’re small player relative to just speaking relative to other players here.

But we retained our acreage positions up in North Eastern Pennsylvania when I say retained, I mean the opportunity to actually best money alongside of our partners here to keep this acreage, certainly we haven’t retained everything through production at this point. I think as noted here we expect to have about two-thirds of this non-operated acreage held by production by year-end, but we sold out of a lot of the non-operated acreage in 2011 and we captured good value at that time. We really want to narrow our scope and our exposure if you will for the dry gas play area.

We continue to look of what we’re seeing, we’re seeing good results and maybe that partly the challenge that we have in terms of supply overall in the basin, but we’ll continue to invest with our partner albeit I would expect for 2013 when we come out with our guidance you will note that we are lower level of spend then we’ve experienced and supported in 2012. I think as I mentioned earlier also we fully met our regional carry obligation here within the third quarter of this year.

So I just give you an idea of what we are looking at and again this is broken down by some of the key counties within the North Eastern area of Pennsylvania and notable Susquehanna and Bradford, Wyoming and West Lycoming and to give you an idea of where the wells are coming out on average in these play areas within the pointing towards 6 Bcf type curve in the solid red line and 8 Bcf type curve in the solid blue line. And just what’s the key here, well, then when we look at rate of return of economics on let’s say depending on well costs and again this is giving you a procession of the EUR recovery relative to a capital cost line and then what kind of rate of return, we’d be looking at here on these wells.

And again run on the forward strip at October and you can see what those prices are. I think they’re probably reasonably in line with where the forward strip is right now. And if the well costs come in, the lower end obviously pushes your rate of return up notably, excuse me, but with an 8 Bcf well based on this curve and a $8 million well cost in that 15% to 20% kind of range. And I get ask question where the well costs coming in, well I stated coming in anywhere from the 7 to 8 right now, but there obviously pushes on to reduce cost down even lower yet. Certainly I know our operating partners are largely, strongly focused on that that initiative.

I just now touch on the deep gas opportunity that we have in our portfolio in Western Canada. For the last few years, we built our positions in some of this emerging place. Right now, we’re actually more in a development mode on the stack Manville.

We’ve drilled four, five wells there. We’ve had good results, in fact we’ve talked about some of them earlier relative to our expectations there. And we’ve also built out an acreage position up in the Cameron area up in the North Eastern area of Alberta. And we have about 33,000 net acres there is a lot of to the north and west is where Petronas progress original joint venture lands where and into the Southern east where additional lands have progressing and there is number of other players in this area.

I think the rock is fairly well under effective tax as drilled the critical test there and we’ve actually we’re looking for joint venture partnership on this, the other one note in terms of an emerging play is the Duvernay were down in the Willesden Green areas play. We believe that we are in the condensate liquids rich area within play area, but its early stage and more definition obviously become.

Here we hope 72,000 net acres of planned to 100% and give your context but now we are going to be think close to attention to what happens relative to – close to bring in joint venture partnership but I think they have about 300,000 acres and company out size 72,000 acres that’s players is very significant and scalable and we required a significant amount of capital it’s a successful.

So that’s good news and as also challenging that, so we are currently in a process to look for joint venture partners for our Montney opportunity as well as our Duvernay. I can tell you that is the process through it while we put them both in the same package if you will probably more than likely get somebody interested in the Montney versus the Duvernay and by vice versa.

So with respect to the Duvernay, a couple of key things are in terms of this players that emerges is looking we expect and we would look as a development profile that had about four wells perception and EUR in the order book 3.5 bcf our liquids content we are targeting some of the order of 75 to 100 barrels of NGLs both 75% of that within maybe the condensate makeup in that liquids content and 4.4.

The initial horizontal wells some of the order book $15 million so these are not to above and think you know this industry is proven over time and reduce the cost to get more into the development.

Good proximately in terms of very relative to the aggressive major pipelines and certainly that’s always important and it relative to being able to get production to market. And here is just the thermal maturity map for the play area, our lands highlighted in yellow, there’s been a lot of well activity around here in two small for you to see here but you’ll see it and I am sure many of you are well aware of what’s happening in there. Good thing about the Canadian environment given this resources buy and large held by the provincial crown, data comes off confidential status after a year.

So there are a number of wells in and around us that will better access to information here as we move to the backend of this year. We already have some of information out there and (inaudible) of us.

I think there is two wells that are kind of a note for us, one was delivering based on tests about a 190 barrels a day of liquids relative to gas, a million cubic feet a day gas and now albeit it was a small test volume of gas in which we sit with highly restricted. And then another one that was delivering about 120 per million cubic feet a day. So we’ll be watching this keenly. We drilled the vertical testing here. We’ve cored the well and we’ll setting core here over the next a little while to really buy and large determine the thermal maturity of the rock.

But let me just include about why Enerplus, well we are demonstrating our ability to grow production organically. We’ve got a significant inventory of both oil and gas opportunities in our portfolio. We’re in a strong financial position, which we’ve always worked to maintain. We’ve reduced our dividend but we think this is a more sustainable dividend. It’s very important to us that’s important to our shareholders. And we think we have a compelling value proposition to deliver relative to our peers. So that concludes my remarks, Peter open for question.

Question-and-Answer Session

Peter Tateishi – Bank of America Merrill Lynch

Perfect thanks Gordon. We’ll open the floor to question. And maybe I will start. Gordon I mean you went through a few key assets when you look forward into 2013 what where to capital get allocated and what provide its kind of the support for the based what the growth provides the growth and look at you excided in 2013.

Gordon J. Kerr

Well, again we will come up with our guidance here to in the month of December here. In our quarterly we indicated that we are spend probably about 20% less on our CapEx program moving into 2013. We will get allocation on capital certainly for vertical region will get allocation of capital to have a reduced spend relative to the Marcellus shale gas play area and we will continue to allocate capital towards our oil Waterfloods properties.

And then they are to advance on the additional incremental oil drilling as well as there your project that are underway those will be the key wants we will allocate the certain amount of capital certainly to our earlier stage assets that will be controlling that.

So for example in 2013, right now we were plan to drill at least one horizontal well within the Duvernay. And how that and falls will be depended and what we see in terms of joint venture funding the potential there and also obviously results that of the core analysis that we are doing right now and the vertical well.

So and there is a couple oil play area is that we have we’re holding acreage position and that we might look to drill one or to learning, that the key in Canada relative to the U.S. two is you can have more fusions relative to allocation of capital and the interest preserving your acreage position, I think grow well first and so it’s fully different of proposition versus in the U.S. where if you don’t drill, you can get cuts with those that acreage position. So we’ve gone through that a lot of that on our U.S. side of the boarder and we can have more patience in where we allocate capital on the Canadian side of the boarder, particularly with those new play and that’s what we’re planning to do.

Peter Tateishi – Bank of America Merrill Lynch

Okay, what went wrong, what went wrong this year that cost of dividend have to be cut in half and given current commodity prices using the sustainable at this level of natural gas and all that doesn’t increase.

Gordon J. Kerr

With regards to the first part of the question, what went wrong, we were actually looking for improvement in the natural gas prices to be straight. And that didn’t happen. And we saw also through the year, we were actually getting hit with the number of non-operated AFBs in the Fort Berthold region which increased our capital spend in that area that again the economics are robust but we could turn our back on that spending. But as far as the go forward on the dividend as I said, we’ve cut, we’ve made a meaningful cut to the dividend and we think that we’re in a good position to support that dividend as we move through 2013 and beyond.

And that’s a key focus for us. The other thing is that we did implement the stock dividend program which will allow our U.S. shareholders to participate along side our Canadian investors. And we think that with that program in place, some of that cash will largely be concert within the organization to support our CapEx spending and really we’re looking for modest growth as I said in 2013, this what we – we’re targeted for this year, and a lot of that again was – in the interest of value within the acreage positions

Peter Tateishi – Bank of America Merrill Lynch

Have you provided any guidance there regarding JVs in the close would you terminate the JVs like Q2, no activity or did they?

Gordon J. Kerr

No I wouldn’t answer, I get a little more information to the growth within the interest level in that so…

Peter Tateishi – Bank of America Merrill Lynch

Interactive process now. So as they tuned is very active process right now. Yes

Gordon J. Kerr

All right thank you.

Peter Tateishi – Bank of America Merrill Lynch

Perfect, thank you very much Gordon

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