Operator: Good morning. My name is Rob and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2012 Year-End and Reserves 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. Thank you. Ms. Jo-Anne Caza, Vice President of Corporate and Investor Relations, you may begin your conference.
Jo-Anne M. Caza - VP, Corporate and IR: Thank you, operator, and good morning, everyone. Thanks for calling in. Gord Kerr, our President and CEO will be summarize our fourth quarter and year-end results for 2012, including reserves this morning and Ian Dundas, Executive Vice President and Chief Operating Officer, will provide some additional color on our operation results for the year.
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. 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 available on our website at Enerplus.com.
Our financial statements were also prepared in accordance with International Financial Reporting Standards. 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 energy equivalent conversion ratio, which does not necessarily represent the current value equivalent.
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.
Gordon J. Kerr - President and CEO: Thanks for joining us this morning. I trust everyone has had a chance to review our new release that was put out before open to market. So, first of all, looking at the fourth quarter results I think it's safe to say that we beat the consensus of analysts on virtually all metrics. Our production was up 5% over the third quarter and our operating and G&A costs were down significantly and most importantly funds flow grew by almost 50% quarter-over-quarter.
These results helped us to achieve our revised full year target as well and we delivered on our annual production guidance producing just over 82,000 BOE a day and 9% increase year-over-year. This included a 21% increase in our crude oil volumes. The Marcellus production that was delayed in our third quarter shows up at year-end. Our extra production during the month of December was on target at 85,800 BOE per day.
Our capital spending and operating costs came in on guidance. Equity-based compensation costs declined which brought G&A costs in under guidance. Certainly a weak natural gas price had a significant impact on our business throughout 2012.
To put the natural gas price drop into context, our average realized gas price fell by approximately 35% versus 2011 and only a 15% of our net operating income in 2012 was from our gas assets. Now despite this, we actually increased our funds flow by 12% over last year and this is largely attributable to the significant increase in oil production, improved netbacks and gains on our hedging program.
As a result, our adjusted payout ratio improved and we expect this trend to continue in 2013 due to lower capital spending and improved natural gas prices. On the reserves front, total proved and probable reserves increased by over 7% in 2012. Our capital program replaced the 190% of production throughout the drill bit and in total, we added over 57 million BOE of 2P reserves, and 66% of those additions were from crude oil and represented a 283% replacement of our 2012 crude oil and liquids production.
Fort Berthold was the big contributor to our reserves growth. Our total crude oil and liquids reserves increased by 12% and they now represent 60% of our total 2P reserves. So if you contrast this to three years ago where oil and liquids accounted for only 50% of the total reserves. Our finding and developments were C$24.21 per BOE on a 2P basis and those numbers include future development costs. Remember, 66% of our reserve additions were from crude oil as you consider F&D.
We also continue to improve the focus of our portfolio during the year. We sold non-core assets in Manitoba and used a portion of the proceeds to buy an additional interest in our Sleeping Giant oil field in Montana and this had minimal impact on our production, but resulted in net proceeds of approximately C$100 million which we apply to our bank debt, and it's consistent with our strategy of increasing the focus in our asset base. When we include our acquisition and divestment activities our FD&A cost were C$22.92 per BOE in 2012, which we believe compares well in the industry.
We also updated our assessment of economic contingent resource associated with some of our assets. We've identified 364 million BOE of best estimate contingent resource, which is over 100% of our 2P reserves. Through our development activities, we confirmed it contingent resources to reserves at Fort Berthold, in the Marcellus, and in our Canadian crude oil assets. We also added a new estimate of contingent resource in respect of our Wilrich play, based upon our drilling success this year, and Ian will get into more details on this later.
Now although funds flow increased by 12% year-over-year, we did record a net loss of C$156 million for 2012, and this loss was a result of impairments recorded under International Financial Reporting Standards and are largely the result of lower commodity prices in principally natural gas and the fact that we have and will allow leases to expire, primarily in lower quality areas in Marcellus play. The impairments do not impact our funds flow, cash flow or our ability to fund capital programs or dividends.
Now as I'm sure most of you are aware, we took a number of steps to continue to maintain our financial strength this year and those steps included an equity issue, our long-term debt deal, the dividend reduction, along with non-core asset sales. We ended 2012 with conservative debt to fund flow ratio of 1.7 times, virtually unchanged from year-end 2011. We currently have about 740 million of room available on our C$1 billion credit facility.
So, with that, I'll now turn the call over to Ian to provide detail on our reserves and our key assets.
Ian C. Dundas - EVP and COO: Thanks Gord. Good morning everyone. As you heard we finished the year delivering strong reserve and production growth, particularly on the oil side, but more importantly on the back of improving cost structures. North Dakota continued to be our single largest focused area in 2012 and once again, we saw significant reserves and production growth. Production in the region increased by 50% year-over-year and we replaced almost 800% of production through our development activities, adding almost 34 million BOE of 2P reserves.
The F&D cost at Fort Berthold was around C$25 a barrel of equivalent including future development capital with the recycle ratio of two times. Now, although activity levels in North Dakota kept costs higher throughout most of 2012 we did start to see significant improvement in cost performance as we came out of the year and moved into Q1. In the last few months, we have been realizing cost reductions of approximately 15% compared to our 2013 targets. So, for our tight well which would be 9,600 foot lateral with 29 stages completed with highest strength (proven) that would translate into a cost saving of about C$2 million a well.
We're quite encouraged by the progress we're making in the cost in this project and my expectation is that we will likely be able to sustain this performance throughout this year. We plan to drill 20 to 25 net wells this year at Fort Berthold and expect production growth of about 30%. Although the primary target is Bakken, the Three Forks opportunity set continues to grow and will account for about one-third of our D&C activity this year. At current activity levels we have a drilling inventory in the region that should last five to six to years.
In Canada, crude oil and liquids production grew by 5% in 2012 through a combination of drilling and enhanced oil recovery projects. Our Canadian oil assets represent about half of our total oil production and are a significant source of free cash flow. Through our technical work over the past few years, we've identified a significant opportunity through improved oil recovery and enhanced oil recovery.
A good example of this is our project in Med Hat Glauc C. This is a field that is currently producing about 4,500 barrels a day of oil, net to our interest which is up 70% over the last year as a result of drilling activity, improved waterflood management and the initiation of a polymer pilot.
We added 5.5 million barrels of equivalent oil reserves in this field this year at a cost of C$ 14.25 a barrel. This year we plan to continue drilling and doing some facilities work and would also expect to make a decision on expansion of the polymer project. Even though we only started polymer injection last May, I'd say a production response has been quite encouraging.
Moving to natural gas; our natural gas spending in 2012 was focused first on lease retention in our non-operated Marcellus project and secondly, on advancing our understanding of key gas plays in Canada, like the Wilrich and the Duvernay. On the reserves front, we replaced a 111% of our natural gas production and increased our 2P reserves by 2% year-over-year. The majority of this increase came from the Marcellus.
Now despite Marcellus delays we experienced in the third quarter, we saw a rapid production build in the fourth quarter. Marcellus production increased to average 57 million cubic feet a day in the fourth quarter to the 43% increase from where we were in the third quarter and more than double where we were in the fourth quarter of 2011.
The current run rate for the Marcellus is over 65 million cubic feet a day. Much of the activity last year was focused on lease retention and as retention issues are being handled, we saw activity levels fall quite significantly. We now have about two-thirds of our core non-operated acreage held by production. We estimate that this year we will spend around half the capital level we spent in 2012, again, primarily focused in our non-operated position.
Our cost performance in the Marcellus has been slow to improve as activity has been driven by chasing land expiries, while managing capital in a low gas market. This combination is typically meant single well pads and less efficient operations. However, we are now starting to see some improvement. We expect we may see savings in the order of 10% over the next quarter or so.
We expect roughly 35% of our total natural gas volumes will be attributable to the Marcellus and our other U.S. properties in 2013. Our netbacks on our U.S. gas production are currently about 25% higher than our netbacks on our Canadian production, which will contribute to the increase in funds flow we expect this year.
The bulk of our natural gas spending in Canada was focused on the Wilrich in the Minehead area. We drilled two horizontal wells and tied in a third. Our drilling success last year has supported an additional 283 Bcfe of contingent resource in the Wilrich. When we look at our land position, we see the potential for over a 100 future drilling locations in this area.
Our activity continues this year. We recently completed our fourth horizontal well, which tested well. The well was flowing at over 12 million cubic feet a day when we shutted in after a 52-hour test.
Finally, we also drilled our first vertical delineation well in the Duvernay and we're able to confirm that we are in a liquids rich part of that fairway. We would expect to drill more vertical delineation wells this year to improve our understanding of this opportunity.
So, with that I'll turn it over to Gord.
Gordon J. Kerr - President and CEO: Thanks Ian. So, while it's been a challenging year in the equity markets, we have made progress in a number of fronts. As we move into 2013, I believe we're entering the year in a position of strength. We've improved the sustainability of our business. Our funding shortfall has improved dramatically and we expect to adjust the payout to be approximately 125% this year based upon current commodity prices.
We're spending 20% less capital this year. We made significant strides in 2012 advancing the development at Fort Berthold and the Marcellus and in our oil plays in Canada. Despite slower production growth this year, we anticipate funds flow will grow by about 8% and we're well positioned to benefit from a continued increase in natural gas prices.
We have a solid hedge book in place with approximately 60% of our net after royalty crude oil production hedged at over C$100 per barrel for 2013 and 28% of our gas production hedged at various price levels through 2013 as well. While the dividend cut was painful last year it has helped our sustainability going forward and we plan to maintain our dividend at the current level.
Our balance sheet is strong and we intend to preserve that strength. We will continue to rationalize non-core assets in the interest of improving our portfolio and providing additional funding. We're focused on improving the profitability of our business through increased focus and strong operational execution. We believe our 2012 results reflect our success and set the stage for future success.
So, with that, I'm going to turn the call back to the operator and we'll open up for questions.
Operator: Gregory Pardy, RBC Capital Markets.
Gregory Pardy - RBC Capital Markets: Wanted to jump into a few things. Just in the past, you've mentioned how many wells you've got in the Marcellus and I'm just curious how many net wells have you got drilled but just not yet completed our tied in rather, and what would the rough working interest on those be?
Gordon J. Kerr - President and CEO: Eric's do you want to take that question?
Eric G. Le Dain - SVP, Strategic Planning, Reserves, and Marketing: I think we're looking at somewhere in the order of over, if you look at drills and drills completed and not tied in, somewhere in the order still probably about a 100 plus wells in the portfolio that we are working on.
Ian C. Dundas - EVP and COO: Yeah, Greg the net number on those would be something like 10 to 15 net wells.
Gregory Pardy - RBC Capital Markets: Then this is just Marcellus, correct?
Ian C. Dundas - EVP and COO: Yeah, just on primarily non-op.
Gregory Pardy - RBC Capital Markets: What would your working interest there be?
Ian C. Dundas - EVP and COO: That was the net.
Gregory Pardy - RBC Capital Markets: I am sorry. Okay.
Ian C. Dundas - EVP and COO: Yeah, so they vary, the effective three partners out there, and working interest ranges from 30% to as low as 2% or 3% in some of those. So it averages close to 20%.
Gregory Pardy - RBC Capital Markets: Your operating costs in the fourth quarter were really low, I mean, there were the one-time severance charges in 3Q, but was there anything unique in terms of adjustments in 4Q OpEx wise?
Gordon J. Kerr - President and CEO: I'm going to let Ray Daniels take that question, Greg.
Ray J. Daniels - SVP, Operations: Not really, I mean the four main drivers that we saw in Q3 were either seasonal spend or one-offs. So the lease rentals and property taxes tend to be more in Q3 and then we had environmental and equalization cost from some non-op partner facilities in Q3. We did make some adjustments in Q4 and came in under our Q4 budget. But they were the main drivers that made the difference between Q3 and Q4.
Gregory Pardy - RBC Capital Markets: Then maybe just with the Bakken, just trying to get an understanding as to what the rough split in the program this year will be between the Three Forks and Bakken wells, or is there intermingling going on right now? Then, frankly, we're just trying to model this, so we just want to get your thoughts around productivity, I'm assuming the 500,000 barrels is for the Three Forks in terms of EURs, and then Bakken is the upper end of that at 800,000, but just anything you can provide us there would be helpful.
Ian C. Dundas - EVP and COO: Greg, it's Ian. I think the splits as I indicated would be about a third of the D&C activity focused on the Three Forks, so of the 20 to 25 wells, I think about a third of those Three Forks this year. We're still moving through this and there is a lot of moving parts relative to the actual density we're talking about, and whether it's Bakken or Three Forks. At the upper-ends of the 800s would be two long Bakkens in a 1,280 spacing unit. The lower ends would be the third and – the Three Forks wells in that same spacing unit. That's directionally pretty good. There is areas that don't look exactly like that, and there is some variability in there. We are still seeing some Three Forks that look a lot like a Bakken well, maybe a little more towards the northern part of the acreage block. I think directionally the two eights to the Bakkens and the two fives for the Three Forks based on a four-well per spacing unit development is a good way to think about it right now.
Gregory Pardy - RBC Capital Markets: The last question for me is with respect to your transportation on the Bakken right now, what percent would be going on rail, and then what percent is going by piping? Can you just give us a rough sense as to what the transportation costs are associated with both?
Gordon J. Kerr - President and CEO: Sure. I think the best person to answer that is, Mr. Le Dain here.
Eric G. Le Dain - SVP, Strategic Planning, Reserves, and Marketing: Starting in this February we're about 30% or so by rail and our rail is changing a little bit. But our full year total transport costs that's loading, unloading, rail, little bit of trucking to get to the rail head is probably about – between C$18 and C$20 a barrel.
Gregory Pardy - RBC Capital Markets: Then that's going to Gulf Coast?
Eric G. Le Dain - SVP, Strategic Planning, Reserves, and Marketing: That is going to the Gulf Coast.
Gregory Pardy - RBC Capital Markets: Then just by pipe?
Eric G. Le Dain - SVP, Strategic Planning, Reserves, and Marketing: By pipe we run on two key pipes right now. We run on Enbridge North Dakota going to Clearbrook's that's been in place of course for years. We also run out the Southwest end on the Four Bears Pipeline and we run roughly – because remember we're running of course our production from Montana as well as North Dakota through the Enbridge system and then we'll be – also we've taken capacity on the Enbridge Expansion that will flow North back into Canada and then back down into the U.S.
Gregory Pardy - RBC Capital Markets: Okay.
Eric G. Le Dain - SVP, Strategic Planning, Reserves, and Marketing: So we've had about 1,000 barrels a day going out in the West and we'll be somewhere around 7,500 going North and East.
Gregory Pardy - RBC Capital Markets: Last question for me is Just Ian you mentioned the C$2 million well savings on the longer laterals. So, are we now talking more like 10 million drill completed tied in on the long laterals?
Ian C. Dundas - EVP and COO: So, we're careful how we talk with this but a lot of people have different categories here. We talked about the all-in DC tie in every number we could think about relative to that component of that completion at the 12.9 number. I think when you – and that was in sort of – that's the targeted budgeted number if you will. That probably looks like a C$12 million or maybe a little less than C$12 million D&C in terms I think most other people would talk. So either one of those numbers we are pulling back, a couple of million bucks right now.
Gregory Pardy - RBC Capital Markets: It's strictly just, it's just fewer days in terms of completions, there's nothing else that's changing?
Ian C. Dundas - EVP and COO: No, it's been a lot of things. Like the performance started to improve towards the back half of the year, started to see improvement in the drilling side, days were falling. So our drilling performance has increased. Of late, the bigger changes have been on the completion. So we are clearly seeing some efficiency gains, but there has been a pretty significant improvement in unit costs in the area on the – just relative to cost services, but it's across the board, Greg. We are seeing it showing up everywhere. Ray is going to add some color.
Ray J. Daniels - SVP, Operations: Just a bit more specificity around that, the pumping cost and profit cost have gone down fairly dramatically and that's a large chunk of the savings and then we are seeing other services and materials come down as well to add up to that C$2 million.
Operator: Kyle Preston, National Bank Financial.
Kyle Preston - National Bank Financial: Just wondering if you can give us a bit of an update on your Duvernay and Montney joint venture initiatives there?
Gordon J. Kerr - President and CEO: I think, first of all as Ian mentioned we've drilled one vertical test in the area while and in fact, we just – we took (polymer). So we've said we determined we're in the window of the liquid-rich component of this play. We do have plans to drill probably a couple more verticals, and we're looking at obviously what's happening in and around us, so what that leave in I want to let Ian comment further in terms of where we're at in terms of joint venture activity.
Ian C. Dundas - EVP and COO: Carl, we're saying the same thing we said in December. Our budgets and our plans and our spending levels assume we will get a JV done. Doesn't mean we're not going to get a JV done, but that's what we're assuming will happen. We're in the process still on those projects. I'd say everything probably went a little bit slower towards the back half of the year foreign investment rules and everything I think slowed down the process a little bit. Now, that there is more clarity on that I think it's freeing up some people to think of what their plans are. We are trying to balance this equation right now because we do not need the money this year to advance on those plays, so we're balancing that with where these plays are and their stated delineation. As Gord said, in both of these plays we have one vertical well into each of them. When we look at our activity that we're planning this year combined with offsetting activity, which is increasing pretty rapidly both in the Montney and the Duvernay, we've lot of information coming our way. So, that's where we want to leave the people is we're really encouraged by what's happening in both of the plays and we're still working through that process.
Gordon J. Kerr - President and CEO: I think, just to add, I think you're very well aware, time is to a certain degree relative to tenure our friend here. So, we can pace things appropriately. Certainly we would like to bring in some funds associated with both of these plays in some form or fashion sale or joint venture. Ian mentioned the outcome of the Nexen deal I actually think that for us is quite encouraging because of course the spotlight was put more on the oil sands. Then of course the Encana deal, certainly doesn't hurt us in terms of deal or value in the play area. So we think there's great opportunity here. It's a matter of timing more than anything.
Operator: Dirk Lever, AltaCorp Capital.
Dirk Lever - AltaCorp Capital: I just wanted to follow-on what Greg was asking, and that has to do with the operating cost. So you came in at, around ballpark C$9.25. How do you see your cost structure going forward on the operating cost side? Let's kind of average it out a second, I understand that Q3 costs for property taxes, et cetera.
Gordon J. Kerr - President and CEO: First of all, we haven't changed the guidance that we've put out earlier this year, Dirk. So we are still holding to C$10.70 per BOE operating cost. Is there opportunity to improve? Well, I can tell you in terms of where we put focus and time it is to look at how we can improve in all of our areas in terms of cost, but right now we haven't moved off the C$10.70.
Operator: Roger Serin, TD Securities.
Roger Serin - TD Securities: Some of my questions have been answered, but I've got some modeling questions. Taxes were lower than we might have expected in the quarter. Have you got any change on guidance on taxes for '13?
Gordon J. Kerr - President and CEO: Rob, will take that question Roger.
Robert J. Waters - SVP and CFO: Roger, it's Rob Waters. Our current guidance is that we don't expect any material Canadian taxes in 2013 and on our U.S. operations we'd expect cash taxes to run at about say 3% of our net U.S. cash flow sort of revenues less cost. Yes, it came in a bit lower than 3% I guess in 2012, but whether it's 2% or 3%, it's sort of rounding error. Compared to last year, you might have seen higher cash taxes in the U.S. and I think that had to do with we sold some Marcellus assets and had a capital gain that we weren't able to shelter down there. So we did pay some capital gains tax in the U.S. if you are sort of looking at that 2011 compared to 2012. But I think we are back into 3% of U.S. cash flow for this year, in terms of a cash tax number. Roger, I'd just add one another thing, is that the taxes we are paying in the U.S., they tend to be AMT taxes which are the Alternative Minimum Tax in the U.S. So they can be recovered to the extent that we do pay taxes in the future, but there is a certain calculation you have to do that you have a minimum level of tax. So they are kind of like prepaying your tax right now.
Roger Serin - TD Securities: When I look at net revenue as being net of interest that you allocate or just funds from operations at our property level think of it?
Robert J. Waters - SVP and CFO: From tax perspective?
Roger Serin - TD Securities: Yeah, from a tax perspective.
Robert J. Waters - SVP and CFO: I think there'd be certain element of interest on both sides of the board in terms of our tax calculations in that. So you would think of it that way. But I just don't know I could tell you definitively how you're going to split that up, but you know what Roger, we could spend some great detailed time with you and try to help you on your modeling there.
Roger Serin - TD Securities: I have another question for Rob. So, what is economic relevant to our derivative settlement on senior note repayment? Look like cash receipt based on that, maybe should we take that offline?
Robert J. Waters - SVP and CFO: I'm not sure what you're referencing Roger. We could take it offline.
Roger Serin - TD Securities: I'm not sure what I'm referencing either, so we'd better take it offline. I got one other relevant question. Related to G&A guidance for next year, which is C$3.15, if I look at your mid-range of your production, so C$3.15 a BOE, like what you did in 2012 that would imply about a 15% increase in G&A cost from '13 over '12, is that just the way the numbers have come through or you're actually expecting to see a meaningful pickup in cash G&A costs year-over-year?
Robert J. Waters - SVP and CFO: As far as the cash, we've added step in our U.S. operations to help advance on the organization initiatives down there. When you combine that with the equity base, certainly we're looking for an improvement in the total based on equity performance. So, that's a good new story if we accomplish that.
Gordon J. Kerr - President and CEO: Roger, when you say G&A are you including what we call equity-based compensation expense?
Roger Serin - TD Securities: I was using the C$3.15 a number, and I don't believe I was including the equity-based comp on that. So, we can take that offline, Rob, when you explain all the other stuff to me.
Gordon J. Kerr - President and CEO: Yeah, actually Roger that does include the equity basin and it comes back to what I just said a moment ago.
Roger Serin - TD Securities: You think your stock price is going up?
Gordon J. Kerr - President and CEO: Well as you may think and this is where I was trying to get to because if you look at the details on the guidance it will have a split of 270 on the cash side and 45 on per BOE per equity-based comp.
Operator: There are no other questions at this time. I'll turn the call back to our presenters.
Gordon J. Kerr - President and CEO: Well, I want to thank everybody for joining us this morning. We're obviously – we're pleased with the results and the feedback we're getting so far is that the analytical communities are pleased and we're looking forward to 2013 in improving on all fronts. So, thanks for joining us.
Operator: Ladies and gentlemen, thank you for your participation and this concludes today's conference call. You may now disconnect.