Enerplus Corp (ERF) 2011 Q4 法說會逐字稿

Good morning, my name is Steve and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2011 year-end results 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.

I'll now turn the call over to Jo-Anne Caza, Vice President, Corporate and Investor Relations. Please go ahead.

Thank you, Operator, and good morning, everyone. I'd like to welcome you to Enerplus's 2011 year-end conference call.

Gord Kerr, our President and CEO, will be summarizing the results for the year, and Ian Dundas, Executive Vice President and Chief Operating Officer, will provide an update on our operational results. To help answer some of your questions at the end of the call, we also have us Rob Waters, our Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Canadian operations; Dana Johnson, our President of US Operations; and Rod Gray, our Vice President of Finance.

Before we get started, please note that this call will contain forward-looking information, and information on contingent resources and reserves. 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.

Our financial statements were also prepared in accordance with International Financial Reporting Standards, including comparative figures pertaining to 2010 results, and our reserves and resources were prepared in accordance with National Instrument 51-101. All financial figures referenced during this 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'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, I'll turn it over to Gord.

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

I think as many of you are aware, over the past three years, Enerplus has been undergoing a significant transition to improve the competitiveness of our business, and also to position us to provide organic growth combined with an attractive yield to investors. I'm happy to say that our 2011 results reflect progress on our strategy.

We had a significant improvement in our reserves, and finding and development costs this year, compared to previous years. We replaced 175% of our production and added 48 million BOE of proved plus probable reserves in 2011. Our total proved plus probable reserves after production and disposition has increased by 5% to 322 million BOE, with the majority of these increases coming from our oil properties. In fact, our oil reserves increased by 14% year-over-year, and we more than doubled our light oil reserves in our Fort Berthold property. We also replaced 100% of production in our waterflood properties. This included 800,000 BOE of reserves attributable to our polymer project at Giltedge, a very positive step for this project and the potential for future reserve adds in our oil waterflood properties.

Our oil and liquids reserves now represent 57% of our total 2P reserves, up from 53% a year ago. Like many others, we continue to feel the impact of weak natural gas prices. Our sale of a portion of our dry gas interests in the Marcellus in mid-2011 was very timely. We realized proceeds of approximately CAD568 million and crystallized a gain of CAD272 million on that sale.

Now as a result of that sale and the weak natural gas prices, our total 2P natural gas reserves declined by 5% year-over-year. We removed approximately 33 Bcf of 2P natural gas reserves due to economic factors. The decline in natural gas prices not only resulted in the removal of some of our natural gas reserves, but we also recorded a CAD334 million impairment in respect of our Canadian natural gas assets under IFRS accounting rules. Now as much as you'd like me to, I'm not going to get into an explanation of IFRS accounting. However, these impairments could be reversed in future, if, for example, natural gas prices improved from where they were forecasted at year-end.

Despite a 30% drop in the natural gas price forecast, the NPV before-tax of our reserves at a 10% discount increased by almost 10%. This is largely due to the increased light sweet crude oil reserves in our portfolio. Our all-in finding, development, and acquisition costs were CAD17.89 per BOE, including future development capital. This cost reflects the significant value we captured on our Marcellus sale.

Our finding and development costs were CAD26.26 per BOE, including future development capital. We experienced rising costs primarily in the Fort Berthold and Marcellus regions, which impacted our F&D costs. We also had approximately CAD150 million of capital spending in 2011 that increased our F&D, but did not contribute reserves in 2011. Over and above our 2P reserves, our best estimate of contingent resources, associated with our tight oil, waterflood and Marcellus resource plays, totaled 485 million BOE, representing 150% of our booked proved plus probable reserves. This is a decrease from 2010, due to the Marcellus sale as well as the conversion of 30 million barrels of Bakken contingent resources to reserves.

Notably, we added 19 million barrels of contingent resources associated with the Three Forks at Fort Berthold. So, in total, we have assessed 49 million barrels of contingent resources in our Fort Berthold play, 56 million barrels of contingent resources associated with our waterflood properties, as well as 2.3 Tcf of gas in the Marcellus.

We continued to add to our strategic land base in 2011 with a purchase of 133,000 acres of undeveloped land in Canada for approximately CAD112 million. The majority of this land was in emerging plays, including the Duvernay, Montney and Cardium. We now have approximately 380,000 net acres of strategic land that we believe will provide us with additional future growth potential.

Part of our capital program in 2012 will be to drill a number of delineation wells on these lands to assess their potential. So, in aggregate, we're very pleased with the progress we have made with respect to our reserve results this year. These results continue to support our strategy of increasing our exposure to new growth plays that complement our portfolio of low-decline, cash-generating assets.

So with that, let me turn it over to Ian to get into more detail on our operations, reserves and capital spending activities.

Good morning, everyone. Before I go into the details around specific assets, I want to provide a quick summary of our 2011 operating results.

As Gord indicated, we met our 2011 exit guidance of 82,000 BOE a day. This was a 6% increase over exit volumes in 2010. Average production was slightly below guidance at approximately 75,300 BOE a day, as we experienced execution delays during the first half of the year on key projects. We spent approximately CAD866 million in development capital spending last year, which was about 12% higher than our guidance of CAD770 million.

The increase was principally in North Dakota, where we have experienced cost inflation as well as incurred costs to pre-purchased equipment in connection with our 2012 program. Despite cost increases in North Dakota, we continue to see robots project economics, which I will discuss in a moment.

Spending was also impacted by weather, as we took advantage of an unusually mild December to accelerate spending -- largely drilling -- in several projects, including a number of our new growth plays. In total, we drilled 107 net wells in 2011, with 130 onstreams. Activity was focused on our oil assets, primarily the Bakken with 34 net wells, and waterfloods with another 34 net wells.

We also participated in the drilling of 16 net wells in the Marcellus, including four operated wells. Operating costs averaged CAD10.23 of BOE versus our guidance of CAD9.60. Although we experienced higher than anticipated power costs in Alberta, the majority of the increase is related to wells servicing cost, repairs and maintenance, much of which ties to higher-than-expected activity levels -- again, due to the mild weather in the fourth quarter.

Now I will review our progress on specific assets areas, starting with our tight oil play in Fort Berthold. The largest capital investment in our portfolio in 2011 was made at Fort Berthold, North Dakota, where we realized positive results from our efforts targeting both the Bakken and Three Forks. We spent approximately CAD290 million here last year, drilling 25 net wells and bringing 21 wells onstream. We ended the year with production at Fort Berthold at approximately 9,000 BOE a day, which was roughly double where we started the year. We also increased our 2P reserves by over 150% in this area, with F&D costs of CAD19.16 a BOE.

Our Bakken well results continued to outperform our initial expectations throughout the year. And as a result, we've increased our estimated tight well recoveries to 800,000 barrels for a long lateral well, and 400,000 barrels for a short lateral well, which -- both which represents the high end of our previous estimates.

We also brought five Three Forks wells onstream in 2011 -- one long lateral, which averaged 800 BOE a day, and four short laterals, which averaged 450 BOE a day. These are both 30-day rates. These results are consistent with our expectations, with recoveries that we would anticipate being about 70% of those compared to where our well has landed in the Bakken.

Work continues to determine how to optimally develop this field. Open questions remain regarding ultimate downspacing and well placement, including how to best exploit the Three Forks. Along these lines, we drilled a 4-well pad in 2011, landing wells in both the Bakken and Three Forks; and another 3-well pad with wells just landed in the Bakken. The long-term performance of these wells will impact the ultimate recovery, density, and obviously, capital required to develop the field.

We did experience increased drilling and completion costs during the latter part of 2011, in large part due to the frenzied pace of activity in the region. We're making a number of changes to our drilling and completion design, with cost savings expected from our saltwater disposal well. We're targeting a CAD10 million well cost for our long laterals by mid-year.

We plan to grow production at Fort Berthold to over 20,000 barrels a day by 2014, and would expect it to generate free cash flow in this region by next year. We plan to continue to increase our overall oil weighting. And in this regard, expect to spend approximately CAD350 million corporately on our tight well properties in 2012.

Similar to 2011, the majority of this spend, about CAD300 million, will be at Fort Berthold, where we plan to run 3 to 4 rigs, with the majority of our wells expected to be long horizontals. The economics here remain very compelling. A long lateral-type well, where we landed in the Bakken, is expected to return approximately 60% on our investment, with an NPV [TIN] of about CAD13 million, and a recycle ratio of around 4 times. We expect to increase our overall tight oil production by 30% to 22,000 BOE a day by the end of this year, and Fort Berthold will lead that growth effort.

Turning now to our crude oil waterflood assets. Our waterfloods remain a core part of our business, and make up a significant portion of our foundation asset base. They represent close to half of our oil production, and with only a 12% decline rate, help offset the higher decline rates and capital needs of our new growth properties.

Activities in 2011 focused on enhancing the value of this play type through both drilling activity and enhanced oil recovery techniques. We invested approximately CAD164 million, which included drilling 34 net wells, with the majority in the Ratcliffe, Viking and Cardium plays.

We continue to see promising results from our polymer project at Giltedge. We began injecting polymer in May, and experienced an increase in production by year-end. Based on these results, we are expanding the project area in 2012, and are evaluating the viability of polymer flooding the entire field. We believe a full-field polymer flood of our Giltedge assets could increase recoveries by about 7% -- between 7% and 14% of the original oil in place, or by 8 million to 18 million barrels, if successful. As Gord indicated earlier, based on these results, we have booked 800,000 barrels of equivalent 2P reserves attributable to this project.

We're also starting our second polymer project in 2012 at Medicine Hat and will begin polymer injection early in Q2. Approximately 34 million BOE of the 56 million BOE of waterflood contingent resource are attributable to enhanced oil recovery projects at Giltedge and Medicine Hat.

In 2012, we expect to spend approximately CAD150 million on our waterflood assets on a capital program designed to enhance our enhanced oil recovery and drilling projects. This capital spend would represent approximately 50% of the expected net operating income from these assets. We expect this capital program will grow annual waterflood production by about 6% to average of about 17,000 BOE a day this year.

Moving now to natural gas. We limited our dry gas spending in 2011 primarily to the Marcellus. We participated in the drilling of 16 net wells in the Marcellus during the year. However, due to delays in pipeline infrastructure, only 5.3 net wells were brought onstream. Despite these infrastructure delays, and including the sale of 5.4 million cubic feet a day of production, we were still able to increase Marcellus production by about 120% year-over-year, exiting the year at about 25 million cubic feet a day. Through our successful drilling activities in the Marcellus in 2011, we added 67 Bcf of 2P reserves. Overall, our total reserves of this regions are up 64% from 2012 -- from 2010.

This year, we plan to spend approximately CAD190 million in the Marcellus region, with approximately 80% allocated to our non-operated interests in northeast Pennsylvania. With the low natural gas price environment, we plan to prudently invest with our partners in the interest of retaining this valuable acreage, in expectation of future gas price recovery and/or cost improvement. The vast majority of our non-op spending is focused in counties where we expect EURs of between 7 and 9 Bcf. At the current floored strip, well economics are positive but are marginal.

Well results in northeast PA have continued to surpass our expectations, both in terms of initial production rates and declines. We expect our total Marcellus production to grow from 25 million a day at the end of 2011 to close to 70 million a day as we exit the year.

Turning now to our liquids-rich natural gas assets, in 2011, we spent CAD$91 million on our prospects in Alberta and British Columbia. We continue to delineate our stacked Mannville position in the Ansell/Minehead/Hanlan areas, drilling three Wilrich wells and one Bluesky-operated well. We drilled our first vertical Montney delineation well at the end of 2011 and are currently in completion operations.

To date, overall, well results have exceeded our expectations, with our most recent Wilrich horizontal testing at over 14 million a day at the back end of the year. Currently, that well is still producing over 12 million a day.

We also added to our Montney land position throughout 2011, acquiring approximately 17,000 acres in the Cameron area, taking our total Montney land position to approximately 33,000 net acres. In addition, we entered into the Duvernay shale play in 2011, and at year-end, held about 65,000 net acres of land in the Williston green region of central Alberta. We would expect to drill our first Duvernay wells later this year.

Results from our drilling activities were positive in this play type, as we grew production in our liquids-rich assets by more than 20% from 13,800 BOE a day to 16,800 BOE a day, as we exited the year. We do plan to take a measured approach to spending in our liquids-rich projects in Alberta and B.C. in 2012. Our plan is to invest approximately CAD80 million on both our operated and non-operated leases.

In the Montney, we plan to drill one horizontal delineation well; and, as I indicated, are about to commence testing operations of our 2011 vertical well. In stacked Mannville, we plan to drill two operated wells, targeting the Wilrich. Those will be horizontal wells. And as I said earlier, we plan to drill our first Duvernay delineation wells later this year as well.

Finally, a quick summary on what to expect in 2012. As we announced in January, our 2012 capital budget is CAD800 million. We believe it will deliver annual production growth of about 10%, with annual production of 83,000 BOE a day and exit volumes of 88,000 BOE a day. 70% of our spending will focus on our oil and liquids-rich natural gas project, with close to 40% of that directed to Fort Berthold. As a result, we expect annual oil production to grow approximately 7,000 BOE a day in 2012, and our average crude oil and liquids production will increase to 50% of total production corporately.

I want to re-emphasize, we are minimizing our spending on our operated dry gas projects, given the current outlook for natural gas prices. We do intend to continue to invest alongside our partners in the Marcellus as they drill to delineate and retain leases. Although natural gas prices are clearly under pressure today, the Marcellus continues to be one of the lowest cost dry gas developments in North America, and we want to preserve the value of our interests for the future.

Through a disciplined exploration program, we plan to invest close to CAD100 million to unlock the value of potential in our undeveloped land base in the Duvernay, Montney and Cardium plays, and in our operated acreage in the Marcellus, as well as advancing our enhanced oil recovery projects. This spending is not expected to contribute significant new production in 2012, although we expect it will set the stage for future production and reserve additions.

So with that, I will turn it back to Mr. Kerr.

Thanks, Ian. So I think, as you can tell, we have a busy program planned for 2012. We plan on building on the success of our 2011 activities, and we expect our cash flows will increase in 2012 as a result of increasing oil and liquids production.

To provide greater protection for our cash flow, we have hedges in place on 62% of our projected 2012 crude oil production at an average WTI floor price of approximately $96. We do not have any natural gas hedges in place at this time, and have no plans to put on hedges in this low-price environment. Based upon our capital spending plans and our current dividend of CAD0.18 per month, we fully expect that we'll outspend our cash flows, given where commodity prices are currently.

We exited 2011 with a debt to cash flow ratio of 1.6 times. And in order to preserve our financial flexibility, we recently completed an equity financing, raising CAD330 million net to help fund our capital spending program in 2012. After taking into account the proceeds from the equity financing, we currently have approximately CAD700 million of available credit under our bank credit facility.

We also have a number of other funding sources that we may utilize as we go forward to help fund our growth strategies. These could include the sale of some of our equity investments, the sale of non-cash flowing non-core assets, and also the use of term debt as well, with the significant undeveloped land portfolio that we have accumulated in new play areas. We may consider pursuing joint ventures or possible monetization of a portion of these interests, to help provide funding and potentially unlock the values in some of these lands.

We've remained true to our strategy, and we are starting to see proof in our results. Our focus going forward will continue to be on execution of our development opportunities and maximizing value for our shareholders.

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

(Operator Instructions). Greg Pardy, RBC Capital Markets.

I wanted to ask, just dig a little bit deeper into what you're doing with the Bakken and then shift to the Marcellus. And curious with the Bakken what the well count would be between the short laterals, long laterals? And then how many of those would be in the Three Forks? And then also interested -- I know you've given revised numbers around the EURs, but for the short laterals, what would you be looking at now, in terms of 30-day IPs and the same thing on the long laterals?

Hey, Greg. It's Ian. You're talking about 2012 program, right?

Indeed.

So, obviously, things can move around a little bit. The 2011 was skewed from a well configuration perspective to short laterals. A lot of that was driven from permitting and land issues. 2012, it's meaningfully reversed, so we'd see the large majority sort of 80%-plus would be long laterals. I'd say a similar percentage relative to Bakken versus Three Forks.

We've got some wells that we're actually completing right now that are Three Forks wells. But largely, we're looking towards a Bakken-dominated program this year. And maybe just a little bit of color on that. So, some of that ties to a view that we may well be accessing the Three Forks through wells that we landed and completed in the Bakken. So we've got some -- those multi-well pads that we completed at the end of the year, that are going to give us some data on that.

In terms of longs versus shorts, were you asking specifically about IP rates or maybe --?

Yes, just your -- I mean, you can do the math, right? You can back into the math. I think you're saying -- I think you've given some numbers around the Three Forks, so I could back into it. But I think we were somewhere around [1250] on the longs and, I don't know, [600] or [800] on the shorts, I can't remember exactly.

Yes, that's about right.

Okay. Just from a transportation perspective, obviously, a lot of concern now with the rising tide of Bakken crude and so on. Can you just -- how are you thinking about transportation out of the area? I think you're selling to aggregators or what have you, but can you talk about transportation logistics?

Well, actually, I think that people are well aware of the transportation out of the whole North Dakota basin is challenged. And there a number of projects that are under consideration, both in terms of rail and pipeline. We recently just put in place an agreement, if you will, a commitment to transport out by rail 6,000 of our production, 6,000 BOE a day of production, and then 4,000 into 2013. And this will help bridge the timeline towards some of the expansion of both additional rail and pipeline out of the area. So we've worked to shore up, and at the same time, keep some flexibility in that takeaway capacity, Greg.

Aaron Terry, Kayne Anderson.

I was hoping to see if you could maybe provide some color. It looks like EXCO is kind of discussed in the northeastern part of Pennsylvania, cutting back on Marcellus spending. Will that have any impact on what you guys are looking at as far as aggregate spending for 2012?

At this point, we've factored that into our guidance. If you look at our non-op program out there, we've got EXCO; we've got Chief, and we've got Chesapeake -- pretty good relationships with our partners out there. I'd say are in pretty constant dialogue, relative to plans, although things are moving quickly. At this point, our total Marcellus spent sort of reflects a view -- it reflects sort of everything they've said publicly. Could that change over the year? I guess it could change again, but right now, we're happy with that.

So that reflects EXCO with moving down from 4 to 2 rigs in the Northeast?

At a high-level, yes.

And as far as the operated program in the Marcellus, I understand where you guys are talking about general Marcellus costs. Do you see the same well costs on the operated program that you see on the growth side for the Northeast?

Similar, although you understand in each of our operated program is very delineation-oriented right now. One rig where we've moved it from central Pennsylvania to West Virginia, some unique coring delineation activity. So we don't really have a comparable run rate to compare to what is more of a development operation from a non-op perspective. It's just a completely different thing when you look at Chesapeake's operation and where they are, relative to what we're doing right now.

Oh, you know, looking forward, though, I would anticipate it to be quite similar. There are some specific uniquenesses, depending on where you are. But generally speaking, similar.

And would you -- are you going to try to target more of the liquids opportunities? I know Central Pennsylvania is much more dry.

Do you have any for sale? Clearly, we're restricting -- so everything we have to -- everything we have is dry in the Marcellus. Northeast PA, the best of the best, so you can make some money there. As you move out of those areas, it becomes even more challenged. So our activity is exclusively limited to delineation on an operated basis. In fact, that has been sort of where it's been for about the last year and a bit. So we don't see any meaningful development in the operated assets under current prices and current costs.

All right. Thank you, guys.

We would have a small amount of liquid-rich potential gas in our -- but it was part of the disposition package. But it was a small acreage position there.

Thanks, guys.

Greg Pardy, RBC Capital Markets.

Sorry, I got cut off somehow. Just one last follow-up. What are you seeing on just with the Marcellus wells, just 30-day IPs in Pennsylvania?

That's a good question. Mixed. It really does depend where we are. Actually, Dana -- maybe I'll turn this over to Dana Johnson, President of our US operations. He can give you a little more color on that.

Yes, there -- we're seeing 30-day IPs for -- depending on lateral length, of course. But in the Chesapeake regard, we've seen 30-day IPs in the 9 million cubic feet a day range. I would say the EXCO development in Lycoming County in the Northeast is coming in at 6 million to 7 million cubic feet a day are not uncommon IPs. And they are -- they're moving that into multi-well pad development at this point. So kind of a mix of that. But I would say those would be the averages.

Okay. And how many fracs would that be then, how many frac stages?

Well, typically, we're seeing in the mid to high-teens for the Chesapeake development; a bit longer laterals in the Lycoming and Susquehanna areas. Kind of think in terms of 5,000 to 6,000 foot lateral lengths; some a little less than that; some more. And then frac stages in the 12 to 15-stage range would be a good average.

Okay. Thanks very much.

Joseph Crawford, Enerplus [sic].

Who you actually with? Because we don't think you're with Enerplus.

No, no. I'm an independent investor. (laughter) And s such, I'm very concerned about the security of your monthly dividend, which is very attractive. None of you addressed dividends. Would you kindly do so now?

Well, what I actually said was that we're at CAD0.18 a month, and I'd just tell you right now we have no current plans to change that payment.

Thank you. That's all.

Cristina Lopez, Macquarie.

Just a couple of quick questions. One is with respect to the North Dakota program. In the press release, it states that you were targeting CAD10 million a well. And then it stated that by mid-year, you were hoping to get there. What are these wells costing you today?

Well, I think, as we indicated in our earlier release, Cristina, the wells, towards the end of the year, were costing in the order of CAD11 million-plus for long. And so the -- and some of that was driven by the level of activity. And Dana does have plans to work on the design of the wells as well as how many stages, what's the fracture approach that we take, in terms of what we use in that fracture approach.

Dana, do you want to add some more color on that?

Yes. The CAD11 million well, as Gord said, would represent our current costs for a long. We're doing -- taking some actions on the drilling side. We see some modest reductions on the drilling side. But the difference in getting to a CAD10 million well will take place predominantly on the fracs. We do plan on reducing stages and our modeling efforts supports doing that.

Currently, our longs are designed around sliding sleeve completions using 24 stages. We'll probably look in the 21-stage realm of that. We're also changing some of the hardware, moving to swell packers and away from hydraulic packers. And then testing here in the coming month, more of an intermediate strength proppant as opposed to our practice through -- since development here to use high-strength ceramic. So we're testing that and see line of sight to that CAD1 million cost reduction through the first half of the year.

And then my last question is on the Duvernay. You had mentioned the possibility of drilling Duvernay wells. How many would you expect by the latter half of this year? And is it looking like a Q3 or a Q4 drill program? And then that's it for me.

Hey, Cristina. We haven't officially decided yet. The smart money is probably on a couple of verticals right now. As you know, there's a lot of activity that's been going on. Indications are interesting at this moment.

We're down in Willie Green, which has had less activity than up in Wild River. The negative noise out there has been some of the drilling issues and the costs associated with that. And so we're just working through that risk assessment right now to understand what information is going to come to us. Would we go straight to a horizontal or do verticals make more sense? So I'd say at this moment we're thinking a couple of vertical wells is the smart thing to do towards the mid-to-late part of the year. But that -- it's under assessment right now.

Thanks, guys.

Gordon Tait, BMO Capital Markets.

Well, you just answered my question on the Duvernay. But could you maybe talk about what, if any, plans you have for the Mannville and the Cardium this year?

The -- sorry, stacked Mannville, so we have 2 wells planned. Have finished one pretty much and we're about to kick off the second one. And that's largely targeting -- operated here, and that's targeting the Wilrich. Pretty happy with the results that we saw towards the back end of the year, although lower liquids content.

So we'll -- right now we're thinking just 2 wells for that. And in terms of the Cardium, I indicated that some of the spend that we had last year was -- sorry, some of the increased spend was accelerating some of this delineation activity. Some of that's related to Cardium. And so I'll say we have plans to continue that activity. We're not putting a lot of clear disclosure on that right now, just given early stage and confidentiality issues and the like.

Is that an area do you want to maybe grow your land interest in?

Yes, we have a decent position. It's not dramatic, but we have a decent position. And a decent position with some success can turn into a lot of oil. So that's driven part of the emerging oil areas we've been talking about, plus we have some legacy positions that are -- we put a new set of eyes on over the last couple of years -- the Cardium specifically. And we've been running sort of 6 to 10-well kind of programs there and can see that continuing. We've had some good success.

Thanks.

You're welcome.

Eric Blessinger, Merrick.

Could you guys please just give an update in terms of how much of your capital budget you anticipate maintenance capital? And by that, I just mean to maintain date and offset based decline rates, based on your existing anticipation of capital efficiency per flowing barrel?

Well, that's a pretty tricky question, quite frankly, to answer. I mean, we've got an CAD800 million program, as we said. And for example, if you looked at our waterflood assets, we're looking to incrementally grow there. And we'll spend about 50% of the cash flow on that particular asset-base. And then on the growth assets, as we said, for the Fort Berthold region, we're looking for substantial growth there. So to try to separate that out as an absolute number is pretty difficult to do.

Great. Thank you.

I'm showing no further participants in queue. I'll turn it back over to Enerplus.

Okay, well, thank you, everyone, for joining us today. We're looking forward to our 2012 program and our execution, and continuing to deliver value to our shareholders. So, again, thanks for joining us.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.