Enerplus Corp (ERF) 2012 Q4 法說會逐字稿

Good morning. My name is Rob, and I will be your conference Operator today. At this time, I would like to welcome everyone to Enerplus Corporation 2012 year-end results and reserves conference call. All lines have been placed on mute to prevent any background noise. After your presenters' remarks, there will be a question-and-answer session.

(Operator Instructions)

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

Thank you, Operator, and good morning, everyone. Thanks for calling in. Gord Kerr, our President and CEO, will 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 operating 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 the 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 represent the current value equivalent. Following our review, we will open up the phone lines and answer any questions you may have, and we will also have a replay of this call available later today on our website. With that, over to you, Gord.

Well, thanks for joining us this morning. I trust everyone has had a chance to review our news release that was put out before open of markets. 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 achieve our revised full-year targets as well.

And we delivered on our annual production guidance, producing just over 82,000 BOE a day, a 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 showed up at year-end. Our exit 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 cost 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 15% of our net operating income in 2012 was from our gas assets. 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 will replace 190% of production through 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 biggest 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.

If you contrast this to three years ago, where oil and liquids accounted for only 50% of our total reserves, our finding and development costs were CAD24.21 per BOE on a 2P basis, and those numbers include future development costs. And remember, 66% of our reserve additions were from crude oil as you consider the F&D. We also continued 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 CAD100 million, which we applied to our bank debt and is consistent with our strategy of increasing the focus in our asset base. When we include our acquisition and investment activities, our FD&A costs were CAD22.92 per BOE in 2012, which we believe compares well in the industry. We also updated our assessment of economic contingent resources associated with some of our assets. We have identified 364 million BOE of best estimate contingent resource, which is over 100% of our 2P reserves.

Through our development activities, we converted 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 to our Willrich play, based upon our drilling success this year. And Ian will get into more details on this later.

Although funds flow increased by 12% year over year, we did record a net loss of CAD156 million for 2012. And this loss was the result of impairments recorded under International Financial Reporting Standards, and are largely the result of lower commodity prices and principally natural gas, and the fact that we have and will allow leases to expire primarily in lower-quality areas in the Marcellus play. The impairments do not impact our funds flow, cash flow, or our ability to fund capital programs or dividends.

As I am 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, a long-term debt deal, the dividend reduction, along with non-core asset sales. And we ended 2012 with a conservative debt to funds flow ratio of 1.7 times -- virtually unchanged from year end 2011. We currently have about CAD740 million of room available on our CAD1 billion credit facility. With that, I will now turn the call over to Ian to provide more detail on our reserves and our key assets.

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 CAD25 a barrel of equivalent, including future development capital, with a recycle ratio of 2 times. Now, although activity levels in North Dakota kept costs high 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 type well, which would be 9,600-foot lateral, with 29 stages completed with high-strength [provent], that would translate into a cost saving of about CAD2 million a well. We are quite encouraged by the progress we are making on the costs in this project, and my expectation is that we will likely to be able to sustain this performance throughout this year.

We plan to drill 20 to 25 net wells this year in Fort Berthold, and expect production growth of about 30%. Although the primary target is the 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 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 50% of our total oil production and are a significant source of free cash flow.

Through our technical work over the past few years, we have identified a significant opportunity through improved oil recovery and enhanced oil recovery. A good example of this is our project in 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 water flood 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 CAD1,425 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 would say 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 they Willrich and the Duvernay. On the reserves front, we replaced 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.

Despite Marcellus delays we experienced in the third quarter, we saw a rapid production build over the fourth quarter. Marcellus production increased to average 57 million cubic feet a day in the fourth quarter, which is a 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 in 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 50% of the capital level we spent in 2012, again primarily focused in our non-operated position. 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 has 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 US properties in 2013. Our netbacks on our US 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 Willrich and 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 Willrich. When we look at our land position, we see the potential for over 100 future drilling locations in this area. 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 shut it in after a 52-hour test.

Finally, we also drilled our first vertical delineation well in the Duvernay, and we are 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. With that, I will turn it over to Gord.

Thanks, Ian. While it has been a challenging year in the equity markets, we have made progress on a number of fronts. And as we move into 2013, I believe we are entering the year in a position of strength. We have improved the sustainability of our business, our funding shortfall has improved dramatically, and we expect our adjusted payout ratio will be approximately 125,% this year, based upon current commodity prices.

We are 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 are 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 CAD100 per barrel for 2013, and 28% of our gas production hedged at various price levels through 2013 as well.

Although 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. The 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 are 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 am going to turn the call back to the Operator and we will open up for questions.

(Operator Instructions)

Greg Pardy, RBC Capital Markets.

Good quarter. I wanted to jump into a few things. Just in the past, you have mentioned how many wells you have in the Marcellus, and I am curious how many net wells have you got drilled but not yet completed? Or tied in, rather? And what would the rough working interest on those be?

Eric, do you want to take that question?

I think we are looking at somewhere in the order of over -- if you look at drills and drills completed and not tied in, it's somewhere in the order of about 100 wells-plus in the portfolio that we are working on.

Yes, Greg, the net number on those would be something like 10 to 15 net wells.

Okay. And then, this is just Marcellus, correct?

Yes. Just -- primarily non-operated.

Okay. And what would your working interest there be?

That was the net I was giving.

Oh, I'm sorry. Okay.

So, they vary. The Marcellus, in effect, we have 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%.

Okay, perfect. Your operating costs in the fourth quarter were really low. I know there were the one-time severance charges in 3Q, but was there anything unique in terms of adjustments in 4Q, OpEx-wise?

I am going to let Ray Daniels take that question, Greg.

Not really. 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 an 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.

Okay, thanks for that. And then, maybe just with the Bakken -- 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? And then, frankly, we are trying to model this, so we just want to get your thoughts around productivity. I am assuming the 500,000 barrels is for the Three Forks in terms of the EURs, and the Bakken is the upper end of that at 800,000. But anything you can provide us there would be helpful.

Greg, it's Ian. Yes, I think the splits, as I indicated, would be about one-third of the D&C activity focused on the Three Forks. So, of the 20 to 25 wells, I think about one-third of those Three Forks this year. We are still moving through this, and there is a lot of moving parts relative to the actual density we are talking about and whether it's a Bakken or a Three Forks.

At the upper ends, those 800,000s would be two long Bakkens in a 1,280 spacing unit. The lower ends would be the third and the fourth Three Forks wells in that same spacing unit. And that is directionally pretty good. There are areas that don't look exactly like that, and some variability in there. We are still seeing some Three Forks that look a lot like a Bakken well, actually, maybe a little more towards the northern part of the acreage block. But I think directionally, the two [800,000s] for the Bakkens and the two [500,000s] for the Three Forks, based on a four well per spacing unit development, is a good way to think about it right now.

Okay, perfect. And the last question for me is just with respect to your transportation on the Bakken right now, what percent would be going on rail and then what percentage is going by pipe? And can you give us a rough sense as to what the transportation costs are associated with both?

Sure. I think the best person to answer that is Mr. Le Dain here.

Starting in this February, we are about 30% or so by rail. And our rail is changing a little bit. But our -- probably our total transport costs, that is loading, unloading, rail, a little bit of trucking to get to the railhead, is probably between CAD18 to CAD20 a barrel.

Okay. And then, that is going to Gulf Coast?

That is going to the Gulf Coast.

Okay. And it's by pipe?

And by pipe, we run on two key pipes right now. We run on Enbridge North Dakota going to Clearbrook, and that has been in place of course for years. We also run out the Southwest and on the Four Bears pipeline, and we run roughly -- because remember, we are running of course our production from Montana as well as North Dakota through the Enbridge system. And then, we will be -- also, we have taken capacity on the Enbridge expansion that will flow north back into Canada and then back down into the US.

Okay.

So, we have about 1,000 barrels a day going out the west, and we will be somewhere around 7,500 going north and east.

Okay, okay. And then, last question for me is -- Ian, you mentioned the CAD2 million well savings on the longer lateral. Are we now talking more like CAD10 million drill completed tied in on the long laterals?

Yes. We are careful how we talk about this, because lots of people have different categories here. We talked about the all-in DC tie-in, every number we could think about, relative to that -- going into that completion at the CAD12.9 million number. I think when you -- and that was in -- that is the targeted budgeted number, if you will. That probably looks like a CAD12 million or maybe a little less than CAD12 million D&C, in terms of how most other people would talk. And so, off of either one of those numbers, we are pulling back CAD2 million right now.

Okay. And it's strictly just -- it's fewer days in terms of completion? There is nothing else that is changing?

No, it has been a lot of things. The performance started to improve towards the back half of the year. Started to see improvement in the drilling side and some days were falling, and so our drilling performance has increased. Of late, the bigger changes have been on the completion. And so, we are clearly seeing some efficiency gains, but there has been a pretty significant improvement in unit costs in the area, just relative to cost services. But it's across the board, Greg. We are seeing it showing up everywhere.

Okay. Listen, thanks very much.

Ray is going to add some color.

A bit more specificity around that. The pumping costs and proppant costs have gone down fairly dramatically, and that is a large chunk of the savings. And then, we are seeing other services and materials come down as well, to add up to that CAD2 million.

Okay. Thanks again, all.

Kyle Preston, National Bank.

Congratulations on a good quarter. Just wondering if you can give us a bit of an update on your Duvernay and Montney joint venture initiatives there.

Yes, I think -- first of all, as Ian mentioned, we drilled one vertical test in the area. In fact, we just took [Coramer]. As we said, we determined we are in the window of the liquids-rich component of this play, and we do have plans to drill probably a couple more verticals. And we are looking at, obviously, what is happening in and around us. So, with that lead-in, why don't I let Ian comment further in terms of where we are at in terms of joint venture activity.

Yes, Kyle, we are saying the same thing we said in December. Our budgets and our plans and our spending levels assume we won't get a JV done. It doesn't mean we are not going to get a JV done, but that is what we are assuming will happen. We are in the process still on those projects. Everything probably went a little bit slower towards the back half of the year, the foreign investment rules and everything I think slowed down the process a little bit.

Now that there has been more clarity on that, I think it's freeing up some people to think about what their plans are. We are trying to balance this equation right now, because we don't believe -- we do not need the money this year to advance on those plays. And so, we are balancing that with where these plays are in their state of 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 are planning this year combined with offsetting activity, which is increasing pretty rapidly, both in the Montney and Duvernay, we see a lot of information coming our way. And that is what we want to leave with people, is we are really encouraged by what is happening in both of the plays. And we are still working through that process.

I think just to add, and I think everybody is 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. The -- 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 oilsands. And then, of course, the Encana deal certainly doesn't hurt us in terms of view of value in the play areas. So, we think there is great opportunity here. It's a matter of timing more than anything.

All right, thank you.

Dirk Lever, Alberta Capital.

Good results. I just wanted to follow on what Greg was asking, and that has to do with the operating costs. You came in at -- around ballpark, CAD9.25. How do you see your cost structure going forward on the operating cost side? And let's average it out. I understand the Q3 costs for property taxes, et cetera.

First of all, we haven't changed the guidance that we put out earlier this year, Dirk. So, we are still holding to a CAD10.70 per BOE operating cost. Is there opportunity to improve? Well, I can tell you in terms of where we have put focus and time, it is to look at how we can improve in all our areas, in terms of costs. But right now, we haven't moved off of the CAD10.70.

Okay, and is there -- okay. I will leave it at that, then. Thanks very much.

(Operator Instructions)

Roger Serin, TD Securities.

Some of my questions have been answered, but I have 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?

Rob will take that question, Roger.

Roger, it's Rob Waters. Our current guidance is that we don't expect any material Canadian taxes in 2013. And on our US operations, we would expect cash taxes to run at about, say, 3% of our net US cash flow. Revenues less cost.

And yes, it came in a bit lower than 3%, I guess, in 2012; but whether it's 2% or 3%, it's a rounding error. Compared to last year, you might have seen higher cash taxes in the US. 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. And so, we did pay some capital gains tax in the US, if you are looking at 2011 compared to 2012. But I think we are back into 3% of the US cash flow for this year, in terms of a cash tax number.

Okay. Moving on to --

Roger, I would just add one other thing, is that the taxes we are paying in the US, they tend to be AMT taxes, which are minimum -- the Alternative Minimum Tax in the US. 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.

And would I look at net revenue as being net of interest that you allocate, or just funds from operations at a property level, think of it?

From a tax perspective?

Yes, from a tax perspective.

I think there will be a certain element of interest on both sides of the board in terms of our tax calculations and that. So, you would think of it that way, but I don't know that I could tell you definitively how you are 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, we want you to come over. (laughter)

I have another question for Rob. What is economic relevant -- or derivative settlements on senior note repayment? There was a cash -- looked like cash receipt based on that. Should we take that offline?

I am not too sure what you are referencing, Roger. We could take it offline.

I am not sure what I am referencing either, so we had better take it offline. (laughter) I have one other relevant question. It relates to G&A guidance for next year, which is [CAD3.15]. If I look at your mid-range of your production, so CAD3.15 of BOE, I look at 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 are you actually expecting to see a meaningful pickup in cash G&A costs year-over-year?

As far as the cash, we have vetted stuff in our US operations to help advance on the organization initiatives down there. When you combine it with the equity base, and certainly, we are looking for an improvement in the total based on equity performance. So, that is a good news story if we accomplish that.

Okay. (multiple speakers) Sorry?

Roger, when you say G&A, are you including what we call equity-based compensation expense?

I was using the CAD3.15 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.

Yes. Actually, Roger, that does include the equity-based, and it comes back to what I just said a moment ago.

So, you are putting -- you think your stock price is going up.

Yes. Well, that would be a nice thing. (laughter) That was what I was trying to get to. If you look on the details on the guidance, it will have a split of CAD2.70 on the cash side and CAD0.45 on the -- per BOE for equity-based comp.

Perfect, that is what I needed.

And there are no other questions at this time. I will turn the call back over to your presenters.

Okay. Well, I want to thank everybody for joining us this morning. We are obviously -- we are pleased with the results and the feedback we are getting so far, as the analytical community are pleased. And we are looking forward to 2013 and improving on all fronts. So, thanks for joining us.

Ladies and gentlemen, thank you for your participation. This concludes today's conference call. You may now disconnect.