Enerplus Corp (ERF) 2011 Q2 法說會逐字稿

Good morning, my name is Matthew and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation second quarter earnings conference call. All lines have been placed on mute to prevent any background noise. After the speakers remarks, there will be a question-and-answer session.

(Operator Instructions)

Thank you. Vice President of Corporate and Investor Relations, Jo-Anne Caza, you may begin your conference.

Thank you Operator and good morning everyone. I would like to welcome you to our 2011 second quarter conference call.

Gordon Kerr our President and CEO is out of the office this week. Ian Dundas, our Executive Vice President and Chief Operating Officer, will be summarizing our results for the quarter and providing further details on our operation activity. To help answer some of our questions at the end of the call, we also have with us Rob Waters, Senior Vice President and Chief Financial Officer, Ray Daniels, Senior Vice President of Canadian Operations, Eric Le Dain, Senior Vice President Strategic Planning, Reserves and Marketing, and Rod Gray, Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information. 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 second quarter news release issued this morning, and included within our MD&A and financial statements filed on SEDAR and EDGAR, and available on our website at Enerplus.com.

Our financial statements were also prepared in accordance with international financial reporting standards, including comparative figures pertaining to our 2010 results. Participants are also directed to our website for a replay of this call, as well as other information on Enerplus. Investors may also call our toll-free investor line at 1-800-319-6462.

All financial figures referenced during this conference call are in Canadian dollars, unless otherwise specified and all conversions of natural gas to barrels of oil equivalent are done on a 6 to 1 conversion ratio.

Following our review, we will open the phone lines and answer any questions you may have. I will now turn the call over to Ian.

Thanks, Jo-Ann. Good morning everyone. Appreciate you joining us this lovely morning on the markets.

Operationally, the second quarter presented a number of challenges for the industry, due to an extremely wet spring. Between washed out roads in North Dakota and flooded operations in Southern Saskatchewan, access to many of our leases was difficult at best.

We estimate the impact of these shut-ins and project delays will impact our annual average production by just under 1000 barrels of equivalent a day. Despite challenges our base production was solid. We produced over 70,000 -- 75,000 barrels of equivalent a day, which was essentially unchanged from last quarter. We also remained active on the acquisition and investment front during the quarter, closing the sale of a portion of our Marcellus acreage.

We still have a very meaningful position in Marcellus, but the position is more focused with a large holding -- core holding in northeast Pennsylvania, better tenure, and much improved controls since the assets we sold for were virtually all non-operated. We realized proceeds of CAD568 million on this sale, representing a pre-tax gain of CAD272 million, and used the proceeds to essentially eliminate our bank debt. This has left our entire CAD1 billion credit facility undrawn.

We have also been actively building our opportunity set in Canada, spending roughly CAD75 million this year, and buying close to 100 net sections of land in several emerging plays, which we believe our perspective for either liquids-rich gas or oil. Including a 60- section position in the Duvernay shale play in Alberta. We have also added to our position in the Cameron region of British Columbia, and now have 44 net sections of Montney potential land. We plan to drill some delineation wells on several of these prospects this winter.

We generated CAD132 million or CAD0.74 per share of funds flow during the quarter. Through the wonderful world of accounting, the CAD272 million gain on the Marcellus sale did not actually impact our funds flow financial calculation, although the cash taxes associated with the sale did. If you exclude the tax impact of the gain, our funds flow would have been CAD0.98 per share during the quarter, essentially in line with the street's quarterly estimates.

Our adjusted payer ratio was 185%, again without the tax expense, it would've been 138%. We continue to maintain one of the strongest balance sheets in the sector, with the trailing 12-month debts to funds flow ratio of 0.7 times. Capital spending excluding our undeveloped land in Marcellus Cary came in at CAD145 million for the quarter, with 14 net wells drilled.

The large majority of our capital was spent on drilling and completions in Bakken, Marcellus and Waterfloods, with 60% directed to oil projects trended -- we can see continuing for the remainder of the year. We expect to see a ramp up of drilling and completion activity in the latter half of the year, and just to bring this for you, we expect to bring on approximately 100 wells this year, two thirds of those are going to be in the second half. Obviously we see production starting to build as we exit the third quarter, but we anticipate facing the biggest impact of these on-streams in the fourth quarter this year.

And now getting into more detail on some of the key assets. I will start with the Bakken/Tight oil approach at Daria. We spent a total of CAD68 million on a play this quarter with the majority of that at Fort Berthold. We drilled a total of just under 8 net wells, 4 at Fort Berthold, 2 at Sleeping Giant, and the remainder being in Taylorton, Saskatchewan.

Bakken production averaged 12,700 BOE a day, slightly lower than Q1, again, due to weather-related difficulties of tie-ins and moving volumes. At Fort Berthold, we have been working on determining optimal well spacing. 3 of the 4 wells drills this quarter were short Bakken wells as we are testing various spacing configurations, designed to optimize field design spacing going forward. We expect this spell -- well spacing work is going to continue, which is going to result in about 75% of our wells this year be short laterals.

Moving forward, once we complete this design, we would expect that the majority of the wells being drilled will transition to the long laterals on a go-forward basis. We're also testing the Three Forks. We brought our first short well on stream during the quarter, and Three Forks well on stream in the quarter and expect it to complete our first long Three Forks test later this month. We will be in a position to talk more about these results as we move into the fall.

We now have 4 rigs running in Fort Berthold. 3 drilling today, and one just rigged up. We expect to maintain this rig count through 2011. 3 of these rigs are walking rigs, which combined with Forks' pad drilling will improve efficiencies in the play going forward. We have an aggressive plan for the remainder of the year, with plans to drill another 26 wells and complete and tie-in 22. All of our permits are in place for these wells and we're now working on securing permits for our 2012 and 2013 programs.

Despite some higher costs in the first half of year which were largely weather and start-up related, we are now starting to see improved operational efficiencies, and we continue to expect our well costs to hold at CAD6 million on our short laterals, and CAD8.5 million on our longs.

Construction of our gas gathering system at Fort Berthold continues to advance and we expect to be able to tie in volumes by the end of the quarter, which should enhance margins and increase production -- sales production by approximately 10% of the play. We now have 14 wells on production in the play, 6 of these wells have been producing for at least 300 days now.

4 of these wells are shorts, which have each recovered about 100,000 barrels of oil, which is about 45% better than our expected tight curves. 2 of the wells are longs, which have recovered about 175,000 barrels of oil each, again nearly 30% better than our tight curves. Obviously we are pleased with these well results and remain excited about the development going forward.

Clearly we are gearing up for a busy second half of the year, but we are in a strong position to execute this program, given the work we have done to secure permits, rigs and frac spreads. Current production in plays, just over 5,000 barrels a day, and we would expect to see this approximately double by the back end of the year.

Turning to our Waterfloods. Waterflood assets have some of the lowest declines in our portfolio and have been very beneficial in helping to stabilize production, particularly during times when weather is interfering with capital execution. Production from our Waterfloods average just over 13,000 barrels of equivalent a day during the second quarter, roughly unchanged from the first quarter.

We spent CAD19 million on our flood stream this quarter, with the majority of that spending focused on our polymer projects at Giltedge and Medicine Hat. At Giltedge, our polymer project is now fully operational. We began injecting our first polymer into the formation and have seen a response from 11 of our 16 wells.

It is still too early to make an assessment of the impact the polymer flood will have on our well production but to date the project is proceeding as expected. We will be in a better position to evaluate the impact of the project by the end of the year. If successful, we would expect to see production in the project area increased two to three-fold over the next 20months to 30 months.

Activities for the remainder of the year will be focused on our Ratcliffe play in Saskatchewan, where we expect to drill 11 wells, and in [Manitoba Cardium] where we expect to commence a 6-well program. We are also advancing on our second polymer project in Medicine Hat where we plan to begin injection early next year.

Shifting to natural gas. The Marcellus Deep Basin are the primary focus areas for our natural gas-related capital spending this year. We spent a total of CAD48 million in capital in the Marcellus during the quarter, participating in nearly 60 gross or about 5 net wells. The majority of our drilling activity was in the Northeast area of Pennsylvania.

All of our producing wells are in Bradford, Lycoming and Susquehanna counties, with current nex -- with net production post-sale at approximately 12 million cubic feet a day. Well costs in this region have risen slightly year to date and we expect to be between CAD6 million and CAD7 million for drilling and completions in this area. Looking forward, we are anticipating some efficiencies as pad drilling becomes a larger focus area for some of our partners.

The pace of play and actual infrastructure build out is still presenting challenges, to completing and tie-in the wells, and we have a significant backlog of inventory with 12.5 net wells either waiting on completion or tie-in. Despite the timing issues though, well performance continues to remain strong and we see quite attractive growing economics, even in the current price environment.

So just to frame this for you, our current EUR estimates in the area, and again I'm talking about the Northeast here, are in the 4.5 Bcf to 6 Bcf well range. Our early time production data though points to first-year production ranging from 0.7 Bcf to just over 2 Bcf, which is outperforming our expectations and arguably points to reserves at or above the high end of those EUR ranges.

But if you assume we are dealing with, let's say, 6 Bcf wells, today's pricing and a CAD7 million cost structure, drill well economics still point to economics in the 40% plus range. Quite encouraging for us.

Switching to our operating prospects in the Marcellus, we have moved a rig from Central Pennsylvania to our Kingwood project area in Preston County, West Virginia. We plan to drill 3 appraisal wells in this region, which will help to determine development plans going forward. We have just spud our first well in West Virginia this week.

Our activity levels with our partners are expected to increase in the second half of the year. Both Chief and Expo are running 3 rigs and we expect to participate in drilling over 25 net wells this year, with approximately 12 wells coming on stream.

Turning to guidance, if you look at our guidance for 2011, with the increased activity we're seeing on our non-operating projects largely, and also a result of some higher costs, we are increasing our capital forecast from CAD650 million to CAD770 million. Approximately half of this spending increase is due to higher costs associated with the wet weather, some cost overrun on a few projects, as well as some service cost inflation that we are expecting in Canada.

Notwithstanding the sale of some of our Marcellus acreage, our spending in this area is expected to increase from CAD160 million to CAD195 million, largely due to increased non-operating activity in Northeast Pennsylvania. We expect the increase in the Marcellus spending will replace the production volumes associated with the sale, and we are maintaining our 2011 exit forecast in the Marcellus of between 42 million cubic feet to 48 million cubic feet of natural gas per day.

85% of our total spending continues to be focused in our Bakken, Marcellus and Waterflood properties. Production and capital delays due to wet weather in the second quarter resulted in a negative 800 barrels of equivalent per day impact on our annual average production. In addition, as we previously announced, we've sold approximately 900 barrels of equivalent a day of average production in the Marcellus sale.

As a result of both of these factors, we're revising our annual average production guidance down by 2,000 barrels of equivalent per day to a new range of 76,000 to 78,000 barrels of equivalent per day. However, the additional capital spending in 2011 will enable us to maintain our exit production, and we have actually tightened the range of exit from -- to 81,000 to 84 -- between 81,000 and 84,000 barrels of equivalent a day.

Our forecast for operating cost and G&A remain at CAD9.20 and CAD3.45 per barrel equivalent respectively. We not revising our 2012 guidance at this time, although the additional capital spending in the second half of the year will result in additional volumes in 2012. We intend to update our 2012 guidance once we've worked through our budget process this fall.

Finally, I would like to welcome 2 new Board members to our Board of Directors, Ms Sue MacKenzie, and Mr David Barr. They each have a tremendous amount of industry experience and their insight will be valuable to our Board and our team.

Before I take questions on behalf of Gord and the entire executive team, I want to thank our employees for their hard work and commitment. We have tremendous opportunities within our asset base and we're very excited about the future for the Company.

With that, I will turn the call over to the operator for any questions fro the audience.

(Operator Instructions) [Paul Meyerhoff], Private Investor

Hello, my name is Paul Meyerhoff and I was wondering in the Marcellus, are you looking at the Utica level at all?

We are obviously paying attention to it. When we look at our acreage position, we don't think it is overly prospective for the Utica though. But it is interesting and I think it is a play we are paying attention to but we don't have a lot of exposure.

How much deeper is that Utica level from the Marcellus?

Modestly. That's all, I guess. Thank you.

Cristina Lopez with Macquarie Securities.

Hi, just a quick question on the land expenditures. How much of that land was -- how much of that CAD75 million was spent in the second quarter versus the first quarter? And could you give any more details on your Duvernay lands? If you see those as being inadequate in the liquids-rich oil or dry gas window?

Let's start, I guess with the Duvernay. We are obviously not talking a lot about this but I would frame our position as one being in the condensate window. With a lot of these things, you can't be overly precise and time will tell, but when we look at where we think the mo -- the better economics are going to be is close to the oil window but not right in it. The delineation activity will tell us, and sorry, your second question was how much was in the second quarter specifically?

I don't have -- it's Rob Waters, I don't have the second quarter but in the first half of 2011, so up to June 30, we had spent CAD59.5 million so call it CAD60 million on land. Then the top-up would be year to date, Christina. Yes, we had some additional acquisitions since June 30 that Ian's including in the CAD75 million.

And that you were saying that you're going to look at delineation activity. It was in the same sentence with the Cameron area of the Montney, with the Duvernay as well. So are you doing -- are you going to look at delineating in 2012 both the Duvernay and your Cameron position for the Montney, or one versus the other? What is your drilling exposure to both those coming to 2012?

Yes.

So you're going to drill both?

The -- I think the precise language was this winter, not 2011. If you stand back, we have a few prospect areas that are pretty interesting to us, and we're going to delineate more than one. If you talk about Cameron specifically, I think that one we can be pretty clear on. We're going to drill a well there back into the year or early into next year.

If you look at some of the other areas we are talking about, some which we've named, some which we did not, we've talked about delineation activities. Likely that's going to be some drilling, could be this year, could be next year. Some of that -- there's a lot of activity going on in some areas. We have offset activity where we might have partners drill in advance of us, which is not necessarily a bad thing. I'm not trying to be too obtuse but it is a bit of the reality of where we are on this

I think that is all from me at this point. Thanks so much.

Thanks, Cristina.

Roger Serin with TD securities.

Morning everyone. Let's keep on the land theme that Cristina started. So of the CAD75 million, how much was spent in Canada?

All of it.

Can you give me an average land cost? I prefer dollars per acre, but dollars per (inaudible) is okay.

You're dating yourself there. CAD1,000 is a nice round number to use.

Is that an acre?

Yes, sorry. I learnt the metric system in grade 9, so --

I am not even going there. Current volumes. What is your current production?

Today?

Or this week, or yes, early August?

We don't often go there, Roger. I say a little under the quarterly average. There is a lot of volatility on this but a little under the Q2 average.

Okay. You are, at least by your advised capital spending, moving CapEx around a little bit, which is understandable. It does look like though that you are spending a little bit less on your recent guidance on the Bakken. Is that really just weather-related on Bakken/Tight oil? Is that more weather-related and did I do the maths right?

I'm sure you did the math right, Roger. But what is happening here is largely quite easy to understand. Non-operating spending in the Marcellus and non-operating in the Deep Basin is larger than we expected. So our partners are coming at us with very interesting development opportunities. Typically they have liquids associated with them, and/or they're Northeast Pennsylvania that have good economics, and so we're participating in those.

That's a lot of the cost increase. When we look at our operating projects on the oil side, the non-delineation stuff, we are doing our best to increase those expenditures, so there is expansion of capital in Canada, and the Ratcliffe and Pembina. And then I'd say we are plus or minus on track for the original plan in Fort Berthold.

Things are moving around a lot there and it a few more shorts than longs. Generally speaking it is the same plan we had.

Actually Roger, the original guidance was CAD300 million in the Bakken in Tight oil for 2011. Now we are looking to spend CAD3.25 million.

That's true but you snuck a CAD360 million in there somewhere along the way. So the last guidance I had was CAD360 million for the Bakken as I was looking at. That's why I asked the question.

I think Gord did that.

I think that is a good answer. Okay, I think the last question I have is, you talked a little bit about new oil plays, and there was said separately then the Duvernay discussion, so could you elaborate a little bit more on what you mean by that?

A little bit. I think we've been pretty clear, Roger, that we have been looking to bring new and emerging opportunities into the portfolio. The focus is not on dry gas because we have a lot of that. We really need some form of liquids and/or preferably oil component. So that's where the focus is.

We're giving specifics to the extent that we are on the Duvernay, and then a little teaser that a few other things we've started to build that are more oil prone. And we are also telling people at this point it's in Canada and that's where we're keeping it right now.

That would be pretty big. One last, in line with that, so you raised your CapEx, you gave good guidance on why the CapEx is up. If you stand back a little bit would the CAD75 million on land, was that kind of a budgeted number, or is that new, and what do you think you're going to spend on this year as part of the now revised CAD770 million?

Sure. When we started the year and we looked at our plans, we had a -- I will call it a plan, an internal plan to spend around CAD80 million on undeveloped land in and around core areas and adding to new positions. We've been able to execute on that and we see additional opportunity in front of us.

We don't budget for this and opportunities will be what opportunities are. We will come forth if we spent a lot more than that but directionally it would go up a bit over the back end of the year as we see some more opportunity in and round us. Obviously our financial flexibility is meaningfully enhanced post Marcellus sale.

Thank you for the time, and thank you for not releasing this late last night Jo-Anne.

My pleasure, Roger.

(Operator Instructions) Gordon Tait with BMO Capital Markets.

Good morning. I just wanted to ask a bit more about the Bakken. I think that the end of last year in Q1, the Saskatchewan properties were not really meeting your expectations. I think it's fair to say that the results were a little bit disappointing.

And I guess in Q2 with the wet weather, you would not really get a chance to do a lot of work there, but I'm wondering going forward, if that's -- if those are areas and properties you continue to put capital in? Or when you speak of the Bakken, are you thinking more further south, around Fort Berthold and some of the other core properties that you operate down there?

So our Bakken/Three Forks, that directed spending is largely in North Dakota. If you move north the border to the Freda/Ratcliffe, sorry the Freda/Skinner/Neptune trend, clearly the Bakken in that area has not met our initial expectations. But what we have seen is the Ratcliffe has -- which is always a known zone, a secondary [ballot] if you were, it seems to be looking a lot more interesting than we initially thought.

Our focus in that area, really our Bakken wells are turning into largely Ratcliffe wells. The team's done a lot of work trying to understand what the Bakken opportunity there is, and although it's been -- although it is disappointing and more conventional that initially we thought it might be, there's still opportunity there.

We're working through what the most sensible way to understand that is. The Bakken sits below the Ratcliffe so we're pretty modest and on the money. You can take your vertical down and test it and see what you're dealing with. That will be -- form part of our plans. Largely our numbers are all driven on this Ratcliffe development there.

Okay, and then I guess at Deep Basin, you are sitting on a lot of buying power. So strategically, Deep Basin's an area you're going to be more active in?

That is a very good question. There is a lot of opportunity we see there. We have captured some of it, so obviously delineation activity and understanding what we've captured to date is going to be a part of the plan. I think Deep Basin, traditionally if you think about it, Stacked Mannville kind of areas, we're going to continue to spend money there and a lot of the increased spend has been non-operating. Partners coming at us plus some of our own stuff as well. You could arguably put our Duvernay prospect in a broad Deep Basin pocket. So we're looking at all of these things.

We see opportunity there, and I am not going to be too obtuse about it, Gordon, but I think we have transitioned from having very, very, very clear portfolio objectives that we talked about with painful precision because it was so intimately linked to our strategy. Now, I think we have more choices in front of us and a little more opportunistic, and it's not just acquisition-oriented, is acquisition combined with understand the opportunities we are already have.

We have capability, we have presence, it has some scope to it. Try to understand exactly how large that scope is. So we're paying a lot of attention to it. I'm not going to promise you that we are going to complete a large acquisition there right now. I think it's going to be opportunity-dependent.

It certainly sounds like an area that is on your radar screen and we could see you more active in.

Absolutely. The reason people are paying attention to Deep Basin is pretty easy to understand. Although infrastructure in areas is starting to get filled up, you do have infrastructure, land tenure is good, you have a royalty structure that is conducive to making a bit of money on a low gas price royalty, you have liquids contribution there. So all of that says, it is an interesting place to be.

And it's a reasonable expense or as a third leg of our stool for a long time. We would have been talking a bit more about it last year but we were spending more money -- we were spending a large amount of money in the Marcellus on non-operative projects, a lot of which were delineation oriented.

And that was always part of the plan, that was just -- that had implications to where else we could allocate capital. And now that the Marcellus is cored up really quite nicely, large, vast majority of money is spent in areas where we have good economics so that all makes some sense to us. And the balance sheet is strong, so that is giving us some more flexibility and one of the reasons why now we're getting the teams a bit more money in Canada is to start to drill and understand the opportunities we've captured. We're -- typically we've had better tenure and a little more time on our side.

Okay, thanks.

Eric Busslinger with Marret.

Hi gentlemen, just wanted to get a handle onto the 2012 numbers. I apologize, I have missed that earlier, I'm on two calls here. Just with the revised guidance, with (inaudible) prices where they are and cash flow likely to come in, maybe modestly above this year's levels, assuming the capital program is on a similar level to the dividends on a similar level, how are you intending to bridge the gap with the increased debt, or potentially further asset sales?

How is the other call going? We have I will call current guidance relative to 2012. In our current guidance, CAD675 million of spend gives us growth close to 10% on a production basis on a 6 to 1. Quite meaningfully, more cash flow growth because of the volumes that are coming on this stream, and increased oil rating. We actually see relatively significant increase in cash flow year on year.

Relative to your question about -- which actually puts us in a mode that is far closer to balanced relative to dollars in and dollars out, assuming the current distribution, the dividend and the like. We had some interesting choices in front of us though right now, and as we make a purposeful decision to wait several months before we update those numbers, we have an opportunity to spend more money, a very economic place. We have a balance sheet is very strong and can allow us -- give us the flexibility to do that if we so choose, and I think provide us growth numbers that clearly in line with the expectations we've set out already, and potentially larger.

If there is a funding shortfall, I think we have some choices of how we deal with that. We do have some non-cash flowing assets still in the fold that we have talked about historically. A good example of that would be our stock in Laricina. We have 4 million shares in the stock based on last issue. That's CAD200 million which could easily cover a large amount any potential shortfall.

I would tell you, in some respects it looks a lot like where it was last year, where we had been very clear with this spending overage, but with growth coming around it and a balance sheet that's strong. The thing that has given us even more choices is this Marcellus sale, which is more than CAD0.5 billion in our jeans which gives us some more flexibility.

Great, thank you.

(Operator Instructions) There are no further questions at this time. I will turn the call back over to the presenters.

With that, thank you. I know it's an interesting day in the markets. I appreciate everyone's attention and joining us today. So hope you enjoy the rest of your day. Thank you.

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