Enerplus Corp (ERF) 2010 Q3 法說會逐字稿

Good morning. My name is Melissa and I will be your conference operator today. At this time, I would like to welcome everyone to Enerplus Resources Fund's third-quarter results conference call. (Operator Instructions). Ms. Jo-Anne Caza, Vice President of Corporate and Investor Relations, you may begin your conference.

Thank you, operator, and good morning, everyone.

I'd like to welcome you to our 2010 third-quarter conference call. Mr. Gordon Kerr, our President and CEO, will be summarizing the results of the third quarter in more detail this morning, and giving some additional information on our operations and our strategy. To help answer some questions at the end of the call today, we also have Ian Dundas, our Executive Vice President, and Rob Waters, our Senior Vice President and Chief Financial Officer.

Before we get started, please note that this call will contain forward-looking information. Listeners should understand the risks and limitations of this information and review our advisory on forward-looking information, found at the end of the third-quarter news release issued this morning and included within our MD&A and financial statements, which are filed on SEDAR and EDGAR and available on our website at Enerplus.com.

Participants are also directed to our website for a replay of this call, as well as other information on Enerplus. Investors can also call our toll-free investor line at 1-800-319-6462.

All financial figures referenced in 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 Gord's review, we'll open up the lines and answer any questions you may have. I will now turn it over to Gord.

Thanks, Jo-Anne, and good morning, everyone. I'd like to begin with the 30,000-foot view of our strategic execution to date this year, and then I'll discuss our operating performance for the quarter.

We've made excellent progress on repositioning our asset base throughout 2010. Year to date, we've acquired over CAD900 million of new growth-oriented assets, based mainly in the Bakken crude oil play in the Williston Basin and the Marcellus shale gas play in northeast United States.

These are some of the most economic resource plays in North America, and they add significant new growth prospects for Enerplus. We expect that as we execute our development plans, these new assets will provide meaningful improvement to our capital efficiencies and cost structures in the years ahead.

In addition to this acquisition activity, we've also made excellent progress selling non-core assets, the majority of which were nonoperated. By year end, we expect to have sold just over 10,000 BOE per day of production that did not fit into our long-term plans and were generally nonoperated, smaller working interests with limited development potential and higher cost structures.

The total proceeds from these dispositions are expected to be close to CAD500 million. As well, we were also successful in selling our Kirby Oil Sands lease for CAD405 million. Our investment into Kirby, including the original purchase price and the capital spent to delineate the lease, was in the order of CAD260 million.

Altogether, we expect to realize proceeds on our divestments of about CAD900 million, effectively funding our acquisition activities.

So, let me get into some of the details. In early October, we closed the acquisition of 46,500 net acres of land, largely undeveloped, in the Fort Berthold area of North Dakota. We had an existing land position in this area, and these leases are contiguous to those. We now have over 70,000 net acres of land at Fort Berthold that we operate, with an average working interest of over 90%.

We see the potential for both Bakken and Three Forks on these lands. We currently estimate there are 18 million barrels of proved plus probable reserves and 50 million barrels of contingent resource in the Bakken, based on two wells per section and a 15% recovery factor. We are currently drilling to test the Three Forks.

We also expanded our interest in the Marcellus by purchasing 58,500 net acres of land in West Virginia and Maryland. These new leases are in emerging areas with limited existing development. However, we believe that the geologic characteristics are similar to Fayette and Somerset counties in Pennsylvania. The leases are concentrated in Preston County in West Virginia and Garrett County in Maryland, with good tenure.

We now own a total of 70,000 net acres of concentrated, operated land where we'll control the pace of development, in addition to the nearly 130,000 net acres of nonoperated land in the Marcellus, and we see the potential for over 1,000 net future drilling locations.

Taking a look at our operating results for the third quarter, I am pleased to say that our business is on track to deliver our guidance. Production averaged 82,869 BOE per day during the quarter, which was in line with our expectations after adjusting for the sale of 2,500 BOE per day that closed in the quarter. And keep in mind that we have sold 6,000 BOE per day of non-core production through the first three quarters of this year.

Our operating costs have declined in 2010, at an average CAD10.28 for the quarter and CAD10.02 to date.

General and administrative expenses were also in line with our targets.

Cash flow was CAD203.6 million for the third quarter, up almost 25% over the second quarter. Production volumes were slightly lower compared to last quarter, although cash flow is higher. The increase is primarily as a result of working capital changes, including a tax recovery.

Year to date, our adjusted payout ratio, including capital spending and distributions, was 108%, and the balance sheet is still very strong with a debt to trailing cash flow ratio of 0.9 times.

About 60% of our capital spending so far this year has been directed to crude oil development opportunities, and we expect this oil-weighted spending to continue as natural gas prices continue to be challenged. We've invested CAD314 million year to date and have funded the majority of this from cash flow.

CAD128 million was spent in the quarter with 80% of that spent in our Bakken, Marcellus, and crude oil waterflood plays. 25 net wells were drilled, 85% of which were oil wells, and all but one of these wells were drilled horizontally.

Now I'd like to talk about a couple of our key spending areas. Our Bakken projects continue to be a key growth driver for us. Production has increased by about 50% this year, primarily because of our successful development program. We've spent CAD115 million on our Bakken properties in both Canada and the U.S., which included the drilling of 11.7 net wells.

Overall, we're very encouraged by the results at Fort Berthold, which is currently producing approximately 4,000 barrels per day. We drilled five horizontal wells during the quarter, three operated long horizontal wells and two short horizontal wells relating to our recent acquisition.

We now have nine wells drilled into the play, all Bakken wells, six of which have been completed. The lateral length of these wells has ranged from 4,300 feet with 12 frack stages for the short lateral wells, to 9,000 feet with 24 frack stages for the long lateral wells.

Production results are either meeting or exceeding our tight curve estimates. The first 100-day cumulative production from our two long lateral wells has totaled 101,000 and 91,000 barrels of oil, respectively.

Based upon a drilling density of two wells per section with an approximate 15% recovery factor, we estimate 130 to 150 future drilling locations. These would be a combination of long and short laterals, but we'd look to maximize the number of long wells we could drill.

We also believe this area is prospective for the Three Forks formation, and are doing some assessment work targeting this formation. We currently have two rigs active here, both drilling multi-well pads. We plan to add an additional rig at Sleeping Giant in Montana in December to drill one or two wells there, and then this rig will move over to Fort Berthold.

Access to service crews continues to be problematic because of the high industry activity levels in the Williston Basin. But we think we're in a good position to mitigate this, given our sizable land position and our anticipated increase in spending over the next three to five years. We're aiming to have long-term service agreements in place by year-end to ensure that we can execute our plans.

Gathering infrastructure is underway at Fort Berthold to allow us to capture the produced gas and additional crude oil volumes. We are currently trucking our oil in this area. However, we anticipate the first well tie-ins will occur late in the fourth quarter and continue into 2011. Our production from this area is expected to grow to over 20,000 BOE per day over the next five years.

On our Saskatchewan Bakken lands, we are doing appraisal work which includes drilling a number of delineation wells and shooting a 3-D seismic program. We have six wells drilled and completed on these lands, and I'd say at this time the results are mixed. We were able to drill another three wells during the quarter, but wet weather has slowed us down and made it difficult to access the sites. So completions have been delayed.

We are in the process of completing these wells now, and these results, along with the seismic information, will help us to evaluate the potential of these lands.

Activity in the Marcellus continued to increase this quarter. We are very pleased with the results to date. Production volumes almost doubled quarter over quarter to 11 million cubic feet of natural gas, and current volumes are now approximately 60 million cubic feet a day.

14 gross wells were drilled during the quarter, representing 3.4 net wells to Enerplus. Six gross wells that were drilled earlier in the year were also tied-in this quarter. Early results indicate these six wells are meeting our tight curve expectations with 24-hour test rates averaging over 6.2 million cubic feet a day. Another seven gross wells were completed and are currently awaiting tie-in.

As we discussed earlier this year, lateral lengths and the number of frack stages are increasing, with the most recent wells ranging from 4,300 feet to 5,800 feet, and 10 to 15 frack stages. As a result of the longer lateral length and increased frack stages, well costs are trending higher, but initial production rates and expected ultimate recoveries are increasing as well.

To date, 93 wells have been drilled. Lycoming and Susquehanna counties continue to be our most active areas, although in aggregate we've drilled wells in nine counties throughout Pennsylvania and West Virginia.

42 wells are on production, 15 wells are waiting on pipelines, and 36 wells are waiting on completion. Another 20 wells are being drilled or remain to be drilled in 2010 on our nonoperated lands, with most of the activity planned in northeast and south-central Pennsylvania and Marshall County, West Virginia.

Just as we've seen in the Bakken play, service companies are in high demand, and this has slowed our completion work. A number of wells were only partially completed during the quarter, and have now been scheduled into the fourth quarter of 2010 and into early 2011. As a result, some volumes anticipated at year-end may now come on production in early 2011. We have eight rigs running in the play, and expect an additional rig may be added before the end of the year.

Construction began on our first operated horizontal well in Clinton County, Pennsylvania, during the quarter. Being the operator is important for us strategically, because of the time to manage our assets effectively, control the pace of our capital spending, and also to make appropriate portfolio decisions along the way to maximize the value of the resource.

Our crude oil waterflood assets continued to be a core focus area, representing approximately 18% of our daily production. We've drilled 26 net wells this year, and have improved or expanded facilities to support future production growth. As a result of our capital investment activities, we expect that production volumes will be maintained year over year, excluding production we sold as part of our disposition program.

During the third quarter, most of our activities were at our Freda Lake Ratcliffe property in Saskatchewan. The Ratcliffe is a medium oil play that sits above the Bakken formation. The Freda waterflood has been on production for over 25 years, and horizontal drilling has changed the way we're thinking about this play.

This year, we've drilled six horizontal wells and have taken production from around 500 barrels per day at the end of 2009 to over 1,200 barrels per day currently, a 140% increase in production.

We've drilled three dual lateral wells and three single lateral wells, and so far, we're pleased with the results. The 30-day initial production rates on the dual lateral wells has been 200 to 300 barrels per day, and we're in the process of completing the single lateral wells. We expect initial production rates of over 100 barrels per day from these wells.

We have about six months' worth of data on these wells, and we're seeing better-than-expected decline rates. We've also upgraded facilities and increased the production and water-handling capacity in order to accommodate the new production volumes, as well as future increases in production.

We plan to drill another five single lateral wells in the fourth quarter, in addition to converting 11 wells to injectors. Our Saskatchewan land acquisitions earlier this year also added acreage with rights to the Ratcliffe formation. Based upon our current acreage position, we see two to three years of similar drilling potential in this area that should allow us to maintain production.

We also kicked off a horizontal drilling program targeting the Viking oil formation at our Gleneath waterflood. We've drilled and completed two horizontal wells during the third quarter. Initial test rates show that these wells could produce approximately 100 barrels per day once they're placed on pump, which is in line with our 30-day type curve. We plan to drill another four wells during the fourth quarter, and given some success, we believe there could be 20 to 30 future Viking drilling locations.

Looking out to the remainder of 2010, we expect annual production to average 83,000 to 84,000 BOEs per day, with an exit rate of 80,000 to 82,000 BOEs per day. This estimate takes into account the impact of the asset sales we have completed or expect to complete this year.

And as I said, availability of service crews remains a challenge and could slow down some of our activities in both the Bakken and the Marcellus. So while we are working to tie up services, we may be delayed tying in a few wells until the first quarter of 2011.

We've also got a very busy fourth quarter underway with close to CAD200 million of spending planned. We continue to expect to invest CAD515 million in development capital this year, and are maintaining our operating costs and G&A guidance at CAD10.20 and CAD2.45 per BOE, respectively.

Now with respect to our corporate conversion, we've announced our plans to convert to a dividend-paying Corporation January 1, 2011, subject, of course, to the approval of our unitholders. We've scheduled a special meeting of unitholders on December 9, 2010, in Calgary, and subject to a unitholder approval and obtaining all of the necessary regulatory approvals, we would convert to a corporation effective January 1, 2011.

We are proposing a straightforward conversion to our unitholders. We'll exchange one trust unit of Enerplus Resources Fund for one share in Enerplus Corporation. This exchange will be tax-deferred and will not trigger a capital gain or loss to our unitholders.

Our ticker symbols will remain the same, except we'll be dropping the .UN in Canada. Also, the conversion will not accelerate any compensation or incentive-based awards to any employees or directors of Enerplus.

We intend to continue to pay monthly dividends to investors after the conversion, and expect to maintain the rate of CAD0.18 per share through the conversion, although this dividend level may fluctuate in the future and, as it does now, will depend upon commodity prices, debt levels, capital spending, and other factors.

We will also use our available tax pools to mitigate our Canadian cash tax obligations, and do not expect to incur cash taxes in Canada for three to five years after conversion.

Our information circular has been mailed, and we ask our unitholders to vote in favor of the conversion. For more information on the conversion and how to cast your vote, visit our website at www.Enerplus.com.

So to conclude, Enerplus is delivering on the strategy we set out at the beginning of the year. We've made tremendous progress adding early-stage growth potential in two of the top plays in North America. We've become more focused and we've set the stage for future growth.

Our capital spending program is delivering results in our growth areas, as well as in our mature assets. We are managing our cash flow between distributions and reinvestment into the asset base, and we believe we have a good balance.

Our balance sheet continues to be in good shape, and this will help us to execute our plans going forward. And our focus is on the execution of our development opportunities.

With that, I'll now turn it back to the operator to take any questions from the audience, and I thank you for your attention.

(Operator Instructions). Cristina Lopez, Macquarie Securities.

Just a really quick question on costs overall in the U.S.. With the services really in hot demand down there, are you -- what are you seeing for an average long lateral in North Dakota? What is that costing you to drill and complete and tie in? And also in the Marcellus?

Cristina, overall what we're seeing is obviously a trending up of costs. Some of it is inflation-related, some of it will be dependent upon the length of lateral wells and the frack stages.

So, for example, as we look forward into 2011, we see costs, I'd say, on the Marcellus drilling come in somewhere on the order of about CAD6 million per well to drill, case, and tie it in. So, that's basically it there.

And again, in the Fort Berthold region, we're seeing somewhere in the order of CAD7 million to drill a well, but we're also looking at the use of high-strength proppant in our drilling over there. And again, it will be dependent on the length of lateral that we drill, as well as the number of frack stages. So, for example, over there we are looking at maybe 10 to 15 in terms of frack stages on the longer laterals.

And then, you also mentioned, in Saskatchewan, that you've had mixed results from your Saskatchewan Bakken drilling program. Are you able to elaborate a little bit more on the details, just sort of what the good and the bad have been from that program?

I'd say it's fairly early for me to comment on that. As I said, we've got a couple of the wells that have been drilled, we haven't been able to get back in to assess the results. And we are currently in the process of shooting a 3-D seismic program out there that will help us evaluate what we have and what the potential is.

So at this point in time, I'm going to basically leave it there.

Gordon Tait, BMO Capital Markets.

I just noticed in your press release today, you're getting pretty good results out of those wells at Fort Berthold, good 30-day and 60-day production rates. Do you think that might translate into higher EURs or an upward revision of reserves?

And then, secondly, you were talking about a well density of two wells per section. Might that increase if these results kind of continue to bear the rates you're seeing?

You know, like we say, I think, Gordon, we've got, like, nine wells into this play in aggregate right now. We are just in the process of testing the Three Forks.

We made the comment about two wells per section, and again, we may actually drill longer laterals there.

So, we're early, but I would tell you that we are strongly encouraged by the results, as you point out, and so time will tell what we can expand in this area. But we are early here right now, but it's certainly meeting our expectations. And the higher concentration and the absolute acreage growth that we now hold, I think, positions us very well for growth in that area. So we're quite excited about this play.

And you've made a lot of changes to your asset base, more production for sale, hopefully, by the end of this year. Do you see more asset sales next year?

You know, we've actually accomplished the major part of the disposition of the non-core. I mean, we identified properties that constituted about 14,000 barrels a day of our production.

So, we would still have a view to maybe move some of those assets out of our portfolio, but probably it won't anything beyond what we've already put in our disclosure. And again, we indicated that there's probably about another CAD140 million of sales that we expect to close in the fourth quarter of this year.

So again, we're going to continue to watch -- look at our portfolio of assets, and move out what doesn't fit with our strategy and retain those things that we believe do fit strongly with our strategy.

(Operator Instructions). Roger Serin, TD Newcrest/Waterhouse Securities.

First of all, I appreciate two things, the fact that you reported today and not in the last couple of days. And secondly, that you segment your information by play type, so thank you for both.

I've got two or three questions. Can you give us some guidance on 2011 cash taxes? U.S.?

Well, you know, I think -- well, our guidance overall has been that we will pay taxes in the order of 10% to 15% when we get out past 2013-2015 timeframe, but I would say that we'll see probably minimal cash taxes in the U.S. because of our spending plans there.

Okay, that's what I expecting. I just wanted confirmation.

You dreamed a little bit about the potential out of the Bakken, 20,000 barrels a day over the next five years. Can you give me a sense of the number of wells you think it will require to take that, and whether it will be reasonably linear?

Maybe I should let Mr. Dundas answer that question, because he was front and center on our acquisition activity, and I'd like Ian to take that one.

Hey, Roger. Does "lots" answer the question for you?

You know, it is early stage for us. I think, as you look at some of the performance and you go back to Gord's question, we are outperforming expectations at this point. What does that mean for ultimate reserve density and performance? It's early. It is pointing to directionally higher EURs; that doesn't necessarily mean more density.

So when we look next year, we're thinking it's a two to three rig type of program to kick off the year, and that looks like a well-ish a month, once you get this program up and running. It is pretty choppy right now, though, accessing services and getting completions in an efficient and timely fashion.

So as Gordon talked about on the call, we're looking at service agreements to sort of expedite and make that a more efficient program. Could I see that growing out in time? Possibly, and so I'd say -- you asked if it is linear. Linear-ish. The economics look very compelling right now, and if that continues to bear out, it's going to disproportionately attract capital and maybe accelerate that.

Okay, and so, just so I heard that right, are we talking about sort of 25 -- two to three rigs program would work to about 25 to 30 wells at the top side?

You know, that's directionally okay.

Okay. I just need to be close.

Well, and we'll give -- our expectation is to give more granularity on that as we roll out guidance next year and provide more visibility into our plans over a several-year kind of timeframe. These are big projects; they don't lend themselves to calendar descriptions, necessarily.

Just to clarify what Ian said, [in this] guidance next year, we're actually come out with guidance here towards the middle of December that will speak to our 2011 plans in more detail.

Sure. Keeping on the Bakken, you've drilled a few wells, and Cristina asked a few questions, but you've got a number of wells licensed. Do I get the sense from your sort of language, that you're going to hold back on drilling those until you get a little bit more completion data and some more production data and review the seismic?

So you are referencing our Bakken in Saskatchewan, and the answer to that is yes.

I was, and thank you.

And lastly, I believe, you've not really given us the same sort of blue-sky look at the potential out of the Marcellus as you just did on the Bakken, and I'm wondering if you'd care to share that.

I think, again, going back to some of our earlier comments in terms of the growth production of this area, on the nonoperated lands we have indicated that we would expect that our net production out of the joint-interest lands would grow to somewhere on the order of 100 million cubic plus feet per day over the next three to four years.

With regard to our acquirer date for each, there's, as I mentioned, very little activity at the moment. So, I don't want to get too far advanced in terms of our assessment here.

We were in the process of drilling our first well in Clinton County, and so I think we'll have a better assessment there after we drill that well, obviously. And then, when we come out with our guidance for 2011, we will be talking to some of our drilling plans for our other acreage down in southern Pennsylvania and maybe also into Maryland.

Okay. Just so I'm clear, that CAD100 million a day is net and the CAD60 million a day that you talked about in terms of production is growth -- earlier in the call?

Right.

Correct?

Right, relative to the (multiple speakers).

Current volumes.

Roger, one other piece that's really critical to that, I mean, obviously, we're deeply in control on the operated Bakken acreage and oil prices are strong, and so we are incented to move that as quickly as we can.

In the Marcellus, gas prices being what they are, combined with a large nonoperated position, you know, that commodity performance is really going to impact the pace of development. We know Chief will go slower in a CAD4.00 world than they will in a CAD5.00 or CAD6.00 world, and we're very supportive of not producing gas in a very aggressive fashion in these depressed environments.

So, how quickly it grows will really tie to the timing of price recovery.

Just to clarify, Roger, what I said earlier -- I'm not sure if you said 60. Earlier, I said our production is in the order of 16 million cubic feet a day net to us. So is that the number you were referring to?

Yes, I was. I thought -- you're about 30%-odd in that play, are you?

No, we're probably on average closer to a maybe 22%, kind of percent.

Okay.

So, so --.

Current is 16, working interest is about 20% to 25%?

Yes, so if you gross it up, you're in the ballpark as far as the gross is concerned. And you like to be close, so I think that will get you there.

Close enough. Thanks. That's all I've got.

Kam Sandhar, Peters & Co. Limited.

A couple of questions. First of all, you touched on this a little bit, but I'm wondering if you could elaborate a bit more on if you expect to spend, I guess, more money on your operated acreage in the Marcellus relative to what you've spent this year, as a split.

And then, my second lesson is just on Fort Berthold and whether your 20,000 barrel-a-day potential would include anything for the Three Forks, and whether or not you have any plans to test that over the next year or so.

Well, first of all, with regard to testing the Three Forks, I think I referenced earlier that we are currently drilling a couple of wells that are testing that formation. So we are already in the process of doing that.

And then your other question, you were asking about our spend levels on the Marcellus operated?

Correct.

We're just in the process of drilling our first well on our operated lands, and so if you're asking relative to 2011, again we will come out with guidance in mid-2011, but given that we've increased our operated interest, I think it would be reasonable to expect that we'll spend more in 2011 than we'll spend in 2010.

Okay, and, sorry, the other question I had was if the 20,000 barrel-a-day production potential would include Three Forks.

There might be a small increment in that number right now, but we'll (multiple speakers), so I think Roger was asking the question earlier about could we see something better? And we're obviously wanting to do some of the evaluation. But, yes, the most of it will come out of the Bakken right now, in terms of that number.

Kam, obviously if the Three Forks is there, and productive, it meaningfully impacts the scope of the resource. And then, that sets up a -- that whole decision of how fast you can [null rate] it, and when you hit a peak, and that appropriate build.

Okay. And one other question on Fort Berthold, could you elaborate a bit more on infrastructure constraints, not necessarily fracking equipment, but takeaway capacity, if there is any?

Well, as I said, we're just in the process of tying up some of the midstream agreements to take the production off the Fort Berthold lands and deliver them into pipeline systems.

Overall in the whole North Dakota area, there is a growing production base there and there are a number of pipeline companies that are basically considering coming forward with open-season arrangements. And we're certainly going to be looking at participating in that.

So, there is a growing production build overall in that area of the basin, and there is movement happening to basically increase the takeaway capacity. So, I think we're feeling pretty good about where, directionally, things are headed on that front.

Okay, thank you.

There are no further questions at this time. Mr. Kerr, I turn the call back over to you.

Okay, well, thank you, operator, and I thank everybody for joining us this Friday morning. We look forward to our future opportunities here, obviously, on the properties that we talked about already, but look for more mid-December. Thank you.

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