Enerplus Corporation

Thank you, operator, and good morning, everyone. Welcome to our 2012 First Quarter Conference Call.

This morning, Gord Kerr, our President and CEO, will be summarizing the results of the quarter; and Ian Dundas, Executive Vice President and Chief Operating Officer, will provide an update on our operational results as well.

To answer some of your questions at the end of the call, we also have with us Rob Waters, our Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Operations; Eric Le Dain, our Senior Vice President of Strategic Planning, Reserves and Marketing; and Rod Gray, our Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information, and listeners should understand the risks and limitations of this type of information and review our advisory on forward-looking information found at the end of our news release issued this morning and included within our MD&A and financial statements filed on SEDAR and Edgar and also available on our website at enerplus.com.

1 conversion ratio. Following our review, we'll open up the phone lines and answer any questions you may have.

And we'll also have a replay of this call available later today on our website.

With that, over to you, Gord.

Thanks, Jo-Anne. Good morning, everyone, and thanks for joining us.

First off, I'm pleased say that the results for our first quarter were quite positive and, I'd say, generally on track with our expectations. We continue to see production growth as well as a stable funds flow relative to the fourth quarter of 2011.

And our capital spending was higher than planned for the quarter. We also executed on a couple of initiatives that will help preserve our financial flexibility over the coming year.

Now this includes the decision on our stock dividend program, and I'll share the results of the shareholder vote on this in a moment.

So let's start with the production. Our total production averaged 79,200 BOE per day during the first quarter, 3% higher than the fourth quarter of 2011.

Our oil and liquids production continued to grow as we had planned, increasing by 9% quarter-over-quarter. Oil and liquids production now accounts for 48% of our total.

This is a positive start to the year, and we continue to expect our annual production to average 83,000 BOE per day with an exit rate of 88,000 BOE per day.

Our development capital spending of $317 million was higher than originally planned due in part to the warm winter weather that allowed us to accelerate spending in some of our key areas and higher spending in Fort Berthold.

Approximately 68% of our capital was directed to our crude oil plays, the majority of which was directed to our Bakken play in Fort Berthold, North Dakota. We expect our pace of capital spending will moderate throughout the balance of the year, and we are maintaining our full-year development capital spending guidance of $800 million.

As I said earlier, our funds flow remained virtually unchanged from the previous quarter, at approximately $163 million or, $0.86 per share, despite natural gas prices being 33% lower than Q4 and crude oil differentials widening substantially late in the quarter. Our growing oil production during Q1 helped mitigate these events to deliver this strong result on funds flow.

We maintained our monthly dividend at CAD $0.18 per share during the quarter, and this resulted in a basic payout ratio of 65% of funds flow for the quarter.

With growing our production and continued weakness in natural gas prices, our oil and liquids production is generating the majority of our revenue. We continue to actively hedge our exposure to oil prices and have added substantially to our hedges for 2013.

Overall, we have hedges in place on 62% of our 2012 expected net after royalty oil production at a WTI reference price of approximately USD $96 per barrel. And we now have 42% of our expected 2013 net after royalty oil production hedged at approximately USD $103 per barrel at WTI.

We do not have any financial hedges on our gas production at this point in time. However, we do have fixed price physical sales contracts in place for 65 million cubic feet per day of our natural gas production at CAD $2.17 per Mcf through the end of October for this year.

Now as I mentioned in my opening remarks, we have taken a number of steps this quarter to support our balance sheet. If you include our capital spending in dividends, we spent over 260% of our funds flow this quarter.

This was as we expected due to the size of the capital program we have in place for 2012. To help manage this, we closed an equity offering in February that raise proceeds of approximately $330 million, and we used those proceeds to initially pay down our credit facility and provide funding for our capital spending program.

In April, we also announced a private placement of long-term senior unsecured notes of $405 million that we expect to close next week. These proceeds will also be used to pay down a portion of our bank line once the placement closes.

Through our 45% drawn on our $1 billion credit facility at quarter end and after our debt deal closes next week, we expect we'll have approximately 80% of our $1 billion credit facility available.

Now we ended the first quarter with a debt to trailing 12 months fund flow of 1.6x, including bank debt and senior notes. As announced at our annual general and special meeting of Enerplus shareholders this morning, our shareholders overwhelmingly approved the implementation of a stock dividend program, or SDP, for short.

That will be effective for our June 20, 2012 dividend program. Our SDP provides all shareholders with the option to receive stock dividends instead of cash dividends if they elect to do so.

We view this as a positive development as it provides certain benefits for shareholders and is now available to all shareholders. Whereas, our DRIP was only available to Canadian residents.

We expect the SDP could reduce the outflow of cash by about $70 million this year.

So with that, let me turn the call over to Ian to talk more about our operations.

Thanks, Gord. Good morning, everyone.

As Gord said, overall, we were pleased with our operating results for the quarter. The growth in our oil volumes drove overall corporate growth despite a modest decline in our gas production.

Oil and liquids were up approximately 3,000 barrels a day on a quarter-over-quarter basis, which was on track with our expectations. We're also encouraged by some of the results in our early-stage plays.

We spent $117 million in development capital during the quarter, 68% of which was directed to oil programs. We drilled a total of 34 net wells, 83% of which were oil, and also brought on 18 net wells, 86% of which were oil.

Operating cost for the quarter came in at $10 a barrel equivalent, that's relative to annual guidance of $10.40 a barrel. And G&A costs came in at $3.51 BOE, in line with our annual guidance of $3.55.

Our pace of capital spend is moderating over the course of the year as we now have completed the majority of our delineation activity and as spending is slowing in the Deep Basin and to some extent, in Fort Berthold.

Let me turn to the Fort Berthold. I'll give you some more details.

The majority of our capital spending this quarter was focused on our Fort Berthold Bakken oil assets, where we spent $138 million. Production increased by 28% from last quarter to average around 8,700 barrels of equivalent a day.

We continue to focus significant -- we continue to forecast significant oil growth over the course of the year from this project. We operated 4 rigs during the quarter, drilling 9 new wells in total.

In addition, we completed 5 wells and tied in 3.

As we've announced earlier, we've recently reduced our rig count to 3 rigs from 4, for which is part of our original plan for 2012, and expect this will also moderate our spending levels throughout the remainder of the year.

Spending levels in the quarter in this project were somewhat higher than we had initially expected due to a combination of increased activity on our non-operated acreage, as well as cost pressures on our operated program. Although we continue to target a $10 million drilling and completion cost for a long lateral well, we have not yet consistently realized those costs and expect that we're unlikely to consistently realize those costs levels until later in the year or early next year.

Near-term drivers that are impacting cost reduction include the completion of our second disposal well, which will impact both capital and operating costs positively as well as cost improvements we expect through enhancements to our completion design. Over time, we will also start to realize benefits from pad drilling, but as our 2012 drilling program is influenced by the status of drilling permits, as well as protecting some modest land expirees, we will not start to benefit meaningfully from pad drilling until next year.

At the macro level, we also believe overall inflation has now largely stabilized innovation. Although overall activity levels in the basin will likely remain high, we anticipate we will start to see pricing relief in certain services, specifically I think the first thing that's going to show up are improvements in frac spreads towards the latter part of the year.

Turning to our waterflood program. We spent $43 million on these assets in the quarter drilling 12 net wells, bringing 8 net wells on-stream.

Overall, quarterly production growth in our waterflood oil portfolio was 2%. Our activity was focused across a variety of plays.

A key focus area continues to be our polymer projects. Our first project at Giltedge continues to perform at expectations.

As we have previously announced, we began injecting polymer about a year ago and have seen positive oil cut response. A key to understanding full field economics will be when we see peak production, and that could be more than a year out.

However, to date, overall performance has been encouraging and it supports our decision to commence our second polymer project in Medicine Hat, where we will begin injecting polymer near term.

Turning to natural gas. Like many producers, we continue to face challenges in our business due to weak natural gas prices.

Over the remainder of the year, our gas direct spending is focused almost exclusively on lease retention in the Marcellus. Currently, we are not forecasting any gas shut-ins or curtailments.

However, we do continue to evaluate shutting an operated production and are monitoring activities associated with our non-operated properties. If prices remain at current levels over the next quarter or 2, we expect there will likely be some volume impact on both non-operated and operated properties.

Non-operated activity levels continue to slow in the Marcellus in response to weak natural gas prices and lower cash flows. We believe we have captured this slowdown in our capital guidance.

However, we could see some further reductions through the remainder of the year, which could also impact non-operated gas volumes. We also expect that we will start to see improvement in cost structures in the Northeast over the next quarter as the pace of gas-related activity continues to slow.

Our total Marcellus production averaged 28 million a day, up from 24 million a day last quarter.

Our non-operated spending of $37 million was largely focused on lease retention activities of our partners. We drilled 2.7 net walls and brought just over 2 net wells on-stream during the quarter.

Based on our non-operated drilling plans for the year, we estimate approximately 1/3 of our non-operated leases will be held by production by the end of 2012.

On the operated side, we invested $24 million focusing on delineation activities to position us for a recovery in gas prices. We drilled one well, completed another and finished up some seismic and facilities projects that will support future activity.

Our operating program is largely completed now as we speak.

As I mentioned earlier, we've seen some encouraging results in certain of our early-stage plays. In the Stacked Mannville, we tested a Wilrich well at Ansell that had a peak rate of over 30 million cubic feet a day.

Although the liquid content in the Wilridge is lower than we had initially expected, our results to date appear to point to a breakeven supply cost of well under $2 an Mcf. Given low prices, we have no plans for additional drilling in this area this year, but we will tie in as well so we can evaluate the resource potential in this project area.

In the Montney, we completed our first vertical well in our Cameron project. Overall results are encouraging and consistent with our initial expectations.

We encountered over pressured reservoir in both the upper and lower Montney, with liquids caught varying between 5 and 15 barrels per million cubic feet. We are now evaluating plans for this area and do not currently have plans for additional drilling this year.

In the Duvernay, we continue to consolidate our lands during the quarter Willesden Green area. We have been building our land position in this area over the last 12 months, and now we've assembled 72,000 net acres of a 100% working interest property in what we believe is the thing condensate-rich window.

Recent drilling results but offset operators are directionally quite encouraging. And at this time, we are preparing to drill a vertical well this summer with the follow-up horizontal likely to kick off early 2013.

So to sum up, we believe we've had a solid quarter operationally. We saw meaningful oil growth, some very encouraging results in our emerging stage plays.

And despite some cost pressures in the Williston, we remain on track for the year.

And with that, I will turn it back to Gord for some closing comments.

Okay, well, thanks, Ian. As I said earlier, we've kept our balance sheet healthy, and we have initiatives underway to help us manage debt levels as we go forward.

We are advancing on our plans to partner or potentially monetize some of our early-stage assets and have hired an advisor to help us in this regard. We also continued to rationalize some of our non-core, nonstrategic assets, and in the first quarter, we realized approximately $23 million of cash proceeds from such sales.

In addition, as I said before, we are targeting to bring in between $250 million to $500 million through a sale or a possible joint venture of underdeveloped plans and the sale of our equity holdings.

If we are unable to make progress on these activities and/or if revised commodity prices do not improve over the coming months, we are prepared to reduce our expected capital spending, and that will apply mostly in 2013. I would also consider reducing our dividend to preserve our balance sheet strength and financial flexibility.

At this time, I'm pleased to announce the promotion of Mr. Ed McLaughlin to the position of President of Enerplus USA.

Mr. McLaughlin brings over 30 years of oil and gas at experience to our team, and we're extremely pleased to have him oversee the day-to-day conduct of our U.S.

operations.

So to conclude, we continue to demonstrate our execution capability, and with our focus on oil and liquids-rich gas projects, we expect to continue to improve the profitability of our business going forward.

So with that, I'll turn the call back over to the operator for questions.

Three questions. First question, can you give me a sense of what you think your exit rate is going to be from Fort Berthold for 2012?

Ian Dundas, our Chief Operating Officer might take a shot at it.

I think we targeted -- we initially talked about 15,600 barrels of equivalent. Directionally, I think that holds, Roger, depending upon costs and how those materialize over the course of the year.

That could move around a little bit. But directionally, we're pretty encouraged by the growth that's happening there.

Okay. So if I'm doing the math right now, quite double from current levels.

Correct.

Correct.

Okay. We'll keep simple.

Second question. As it relates to your Duvernay activities, you've drilled one vertical.

Earlier in the year, you had talked about perhaps following that up in the second half of the year with either additional verticals or horizontals. Can you give us an update as to your current plans?

Well, let me -- but we haven't drilled on the Duvernay at this point, just to be clear. We talked about a vertical on our Montney, but go ahead Ian.

Yes. So Roger, just to be clear, we haven't drilled any wells.

We have had a fair amount of offset activity. Bellatrix announced a well recently that was just a little bit south and west of our acreage, and there's been activity on the east and southern part.

Originally, we had -- I guess, last quarter, we were talking with a possibility of 2 vertical wells largely because we've now seen offset activity, and we're learning from that. We think likely the best plan for us is one vertical well, likely towards the northern end of our acreage.

And as soon as things dry up, I think the guys are going to get that kicked off, that will evaluate that well. But the plan at this point would be to move after that to a horizontal well likely in the same type of area.

The timing on that probably early 2013 when we've had time to evaluate it.

Okay. My last question, I think, is, do you guys have a board governance policy that relates to term of office?

I knew you had a number of board members step down. And could you give us some color on that?

Yes. There is a policy in place and in fact -- this is a good term to use --it was a bit grandfathered in terms of -- it's an age-related policy.

So 2 of the directors would have basically been retiring. Of course, Don West was one of those directors, Harry being the other one, as a consequence.

And then, of course, Mr. Zorich and Mr.

Woitas also made their determination to retire for personal reasons and associated with their lifestyles, I think, more than anything, or their business activities.

Just on the hedging, I think you said it was about 27% of your summer gas hedged. Gas prices have come up a bit the last few weeks.

Are you looking to lock in any more?

Well, first of all, what we said was we have fixed contracts in place for about 27% of production from April through October, and that was at $2.17 an Mcf. So we don't have any financial hedges in place on the gas.

That will be a topic of discussion, but we haven't moved on anything there in the gas front.

Can you maybe give us an indication of what sort of the price it would take, at least on the gas side, where you'd be more comfortable with your current rate of spending and funding without having to make some of the changes that you highlighted in your comment.

Well, as far as comfortable on the level of spending I mean, this year, of course we trying to scale back our spend overall. We said we're not spending anything on the dry -- or the shale and gas in Western Canada.

And our focus has been on the Marcellus and largely to preserve acreage in that. If we start to see prices that move up past the $3.50 to $4 range, it really encourages us.

Ian already mentioned, for example, in our Stacked Mannville play area that the economics were really robust. But we're going to go to a slower pace there just to watch and see if what develops up on the price front, as well as activity around us.

So I don't think at this particular point in time, we have any plans to accelerate beyond what we're doing right now. But again, we're all looking to see what's going to happen on natural gas improvement on the price front.

And How much flexibility do you have in terms of spending in the Marcellus? I know you've got drilling commitments to hold your leases?

Is there more -- is there some CapEx that you can cut out of that over and above the drilling to meet your lease commitments?

Well, I think as we also indicated, we probably have about $19 million left to spend post this first quarter to meet our commitment of the carry obligation with our operating partner, Chief. There could be some reduced spend this year.

We're not really planning on reduction below the $150 million that we have there. And then, when we get out past the obligation, there's always a possibility you could go [indiscernible] on wells in that, but we believe suffering a significant value loss if we don't do it in a judicious way.

And our partners are paying attention of where they're drilling wells and the drilling spacing units that they're drilling into to preserve acreage position. So it's not like it's just to preserve acreage in the area.

So we may see some expiring of acreage as we move forward with our partners.

Gordon, it's Ian. Maybe I'll add just more one piece to that, too.

It's very, very dynamic particularly in the Marcellus right now as the rig count is falling and the guys are trying to preserve capital. And it's a multifaceted equation.

One of the other pieces that we haven't seen people really doing yet but I think are going to play in, on our -- when we look at our non-operated expiring acreage and we look at the expires next year. But 1/3 of those acres that are expiring, we've got an ability to deal with by extensions, so paying money to extend leases.

We haven't seen any meaningful uptick on that by our partners, but my expectation is we're probably going to. And so then it becomes an economic trade.

You pay some more money but effectively stop drilling 10 wells. So we're seeing it move quite rapidly around us.

But I guess, at this point, we think we have captured that in our numbers, but it is somewhat dynamic.

Okay. Well, thank you, everyone, for joining us this morning, and we look forward to our coming quarters.

Yes.

In the past, you sounded more sure about your dividend. What changed your mind?

Well, we're still paying $0.18 per share per month, Mary. But I guess the thing that's continued to move away from us in particular is natural gas prices.

And even from the beginning of the year, we've seen an erosion, further erosion of those natural gas prices, and that certainly has an impact for us.

We've indicated we have a number of initiatives we want to work on to provide additional support to our funds and, therefore, preserve that financial strength. So we just really are paying close attention as we go forward on how we manage the business.

In relation to one of the other questions, what gas price would you feel more -- would you feel like not saying that you might cut your dividends?

You're breaking up a little bit, but I think you're asking what gas price should we feel more comfortable at and we feel better about in terms where we go with dividends. And we won't just look at gas price in isolation, certainly.

But right now, we've been trading -- gas prices have been trading down below $2 [indiscernible] and also in the $2 range a little better than the NYMEX. So we'd look for improvements up more to the $3.50, as I said earlier to start to get some comfort, if you will.

And through our partners. But to be clear, even at $3.50 gas prices, we'd still be looking to monetize a portion of our equity portfolio and also joint venture potentially monetize a portion of our undeveloped lands.

But I don't think Gord is inferring at a $3.50 gas price, everything is fine and dandy. It's a challenge managing the balance sheet for the long term in this environment.

You talked that you actually have the flexibility, that you could cut capital spending, that you could sell some more assets. And I mean, the dividend is always up for review, I guess.

But has your priority changed? Is there dividend not last to be cut?

Is it second or third?

You're breaking up again a little bit, Mary. But I think you're asking if the dividend is the last thing to be cut.

I think that's not the way that we manage this business over the long term. We've looked and said what's the right investment of capital in the asset base, what's the right dividend level that we can support.

So we don't just look at one. I mean, if we don't continue to invest, for example, in our asset base, then we see a decline in the productions associated with it.

So it's not an absolutely simple answer. Having said that, we have been very clear in terms of the dividend is something that we believe is a strong value driver for our shareholders.

And we want to continue to keep it as a key component of how we bring value to our shareholders. Okay.

Good. Well, thank you again, everyone.

Have a great weekend.