Enerplus Corp (ERF) 2009 Q2 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Enerplus Resources Fund second-quarter results conference call.

At this time all, participants are in a listen-only mode. Following the presentation, we will conduct a question-and-answer session. Instructions will be provided at that time for you to queue up for questions. (Operator Instructions). I would like to remind everyone that this conference call is being recorded on today, August 10, 2009 at 11 AM Eastern time.

I will now turn the conference over to Jo-Anne Caza, Vice President of Corporate and Investor Relations. Please go ahead.

Thank you, operator and good morning, everyone. I'd like to welcome you to our 2009 second-quarter conference call.

Gordon Kerr, our President and CEO, will be relaying the results of our second quarter in more detail and giving some additional information on our strategy going forward. To help answer some of the questions at the end of the call, we also have with us Garry Tanner, our Executive Vice President and Chief Operating Officer, 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 our second-quarter news release issued this morning as well as the risk factors included in our annual information form filed by SEDAR and EDGAR and available on our website at www.Enerplus.com. Participants are also directed to our website for a replay of this call as well as other information on Enerplus. Investors may call our toll-free investor line at 1-800-319-6462.

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 61 conversion ratio.

Following Gordon's review, we will open up the phone lines and answer any questions you may have, so I will now turn it over to Gordon.

Well, thank you Jo-Anne, and good morning, everyone.

As I said, for the first quarter, again I am pleased to report that our results for the second quarter of 2009 are tracking the full-year guidance we set out at the start of this year.

Now, certainly our cash flow has been negatively impacted by the significant drop in commodity prices as compared to this time last year, but our production levels, development of capital spending in operating and general and administrative expenses are all on target in view of the slower commodity price environment.

We've continued to maintain our discipline regarding our development spending and a strong financial position. Our production during the quarter averaged approximately 94,500 BOE per day, virtually unchanged from the first quarter of 2009. Production is down approximately 6% from the second quarter of 2008, and this reflects the lower development capital spending occurring in 2009.

Our production levels did benefit this quarter from an accelerated capital program during the winter drilling season, as well as production optimization and reduced downtime. However, due to the lower development capital activity planned for all of 2009, planned facility turnarounds in the third quarter, and the natural decline of our asset base, we are expecting production for the remainder of the year to fall from second-quarter levels. So we still expect to average approximately 91,000 BOE per day for the full year with an exit rate of approximately 88,000 BOE per day, based on our development capital budget of CDN300 million.

Now, in spite of the weakness in natural gas prices, we have shut in a very limited amount of natural gas production, less than 250 BOE per day. While we don't currently anticipate any additional shut-ins, we will continue to evaluate the economics of our production, and we will make further decisions as may be required.

Natural gas prices continued to weaken throughout the second quarter. As a result, we realized an average selling price of CDN3.49 for Mcf, a decrease of 65% from the same period last year.

Crude oil prices rebounded from their lows in the first quarter. However, they still remain significantly lower than the second quarter of 2008. We realized an average selling price of CDN59.80 per BOE during the second quarter, a 48% decrease from the same period in 2008.

Our risk-management program helped to offset some of the continued weakness in natural gas prices we experienced during the quarter. We realized cash gains of approximately CDN21 million on our natural gas hedges and approximately CDN22 million on our crude oil hedges during the quarter. For the remainder of 2009, we have downside price protection in place for approximately 25% of our natural gas production at an effective price of CDN7.60 per Mcf, and for approximately 27% of our oil production at an effective price of approximately USD98 per barrel based on current forward market prices.

Our cash flow was approximately CDN211 million or 42% lower than the second quarter of 2008, largely the result of a significant drop in commodity prices. Approximately 43% of our cash flow was distributed to unit holders during the quarter through monthly distributions which were maintained at CDN0.18 per unit. We also invested approximately CDN36 million in development capital, which was entirely funded from cash flow. Distributions to unit holders divined, combined with development capital spending during the quarter, totaled roughly 61% of our cash flow.

When we looked at the first six months of the year, our distributions in CapEx totaled approximately 83% of our cash flow. We continue to expect our full-year adjusted payout ratio to be in the order of 100%, excluding the impact of acquisitions.

On the expense side, operating costs were in line with our expectations and averaged CDN9.93 per BOE compared to the first quarter of 2009 with year-to-date op costs averaging CDN9.89 per BOE compared to CDN9.17 for the same period in 2008. Increased spending on regulatory requirements, higher power hedging losses and well maintenance were the main drivers for the increase.

We are monitoring our operations closely to prudently reduce costs where possible. However, we are maintaining our annual guidance for operating costs at approximately CDN10.65 per BOE on the basis of full-year average production of 91,000 BOE per day.

During the second quarter of 2009, cash and non-cash G&A expenses increased 13% per BOE to CDN2.49 per BOE compared CDN2.21 per BOE for the first quarter of 2009. This was largely due to transaction costs of CDN2.3 million related to our new Senior Notes offering. Excluding these transaction costs, G&A would've otherwise been CDN2.23 per BOE for the second quarter. As with our operating expenses, we are continuing to pursue G&A cost-cutting measures but are maintaining our guidance for G&A expenses at CDN2.45 per BOE for the full year.

Our development capital program for the quarter was significantly lower than the first quarter due to weakening gas prices, traditionally slower activity due to spring breakup, and the conservative approach we've taken to our spending. As I've already mentioned, we invested approximately CDN36 million during the quarter on develop activities, and our year-to-date spending has totaled CDN135 million.

Our shallow gas activities have been concentrated at Shackleton, Bantry and Verger with 105 net infill wells drilled year-to-date. The continued weakness in natural gas prices has, however, resulted in our decision to suspend further drilling at Shackleton. We do plan to leverage off of the drilling world to credit program implemented by the Alberta government to support our natural gas drilling projects in Alberta.

Our tight gas activity was centered at Tommy Lakes with the completion of a successful 14-well program earlier this year, including the first horizontal well drilled on our lands. The horizontal well is producing as expected with initial production rates of approximately 4 million cubic feet per day and reserve estimates of approximately 3.5 billion cubic feet, roughly 3 times that of a vertical well. We will be evaluating these results for further horizontal well drilling on the property.

Our tight oil development has been focused primarily at Sleeping Giant, where we had a drilling program earlier in the year and have continued with an active re-frac program. Given the strengthening of crude oil prices, we are reviewing expansion of our re-frac program and may possibly resume our drilling program in this area later this year. We also plan to drill for Bakken on the lands we drilled in southeast -- or pardon me, we acquired in southeast Saskatchewan in late 2008. The remainder of our capital program for this first half of 2009 has been on production optimization in various fields within our waterflood resource play and our conventional oil and gas assets.

At this time, we are maintaining our 2009 development capital guidance of CDN300 million. However, we will continue to review our spending plans in relation to commodity prices.

On the acquisition front, we continue to evaluate acquisition opportunities that will add meaningful growth in reserves and production, focusing primarily on tight gas opportunities in British Columbia and Alberta, tight oil opportunities in Saskatchewan and North Dakota, as well as shale gas opportunities in the United States.

In May, we purchased 25% nonoperating working interest in 44 sections of prospective Bakken lands for CDN25 million in southeast Saskatchewan, and entered into the material area of mutual interest agreement with an industry partner. The acquisition builds on our existing portfolio of Bakken prospects in Saskatchewan and Montana and will provide further growth potential for Enerplus in this play. The transaction adds 200 BOE a day of Bakken production currently, and we plan to participate in the drilling of seven gross wells during the remainder of 2009, spending approximately CDN5 million net to Enerplus.

In April of this year, we announced the deferral of our Kirby Oil Sands project due to inflated cost structures and weak commodity price environment. We continued to work on obtaining regulatory approval for the initial 10,000 barrel a day commercial project, and we expect to receive approval early in 2010. Based upon new data obtained from our 2008 seismic program, we have updated our resource assessment on this property. Our third-party independent engineering reserve engineers have confirmed an updated best estimate contingent resource of approximately 507 million barrels. This is an increase of 22% from the 414 million barrels best estimate given in 2008 and 108% higher than the original independent best estimate assessed when we purchased the Kirby lease in 2007. We believe there is further opportunity to increase the resource assessment in Kirby and long-term value in the project, and we will continue to monitor economic, regulatory and technical developments to be positioned to revisit our plans for Kirby at a later date.

With regard to our balance sheet, in June, we issued approximately CDN340 million in long-term debt by way of private placement in the form of senior notes with terms of 6 and 12 years. We used the proceeds from the senior notes to repay a portion of outstanding bank indebtedness, resulting in an increase in the unused print capacity on our bank credit facility to over CND1.3 billion at the end of the quarter. The placement of these senior notes provides us with greater flexibility in managing our long-term debt portfolio, as our existing notes are scheduled for repayment between 2010 and 2015. It also diversifies our credit sources by replacing short-term debt with the assurance of long-term debt commitments at reasonable rates. We continue to have one of the strongest balance sheets within the sector, with a debt to trailing 12 month cash flow ratio of 0.7 times at quarter's end.

Going forward and to conclude, let me reiterate points we've made previously in respect of our strategy. We believe there is an opportunity to improve our business during this period of economic recovery that will position us strongly for the future. We expect to leverage off of our strong financial position and acquisition experience to position us into additional strategic assets, both in Canada and the United States. We continue to screen transactions, targeting opportunities in tight oil, tight gas and shale gas plays that will provide us significant growth opportunities and superior economics.

We remain committed to managing our business prudently throughout these challenging economic times. We are keenly focused on reducing costs and increasing efficiencies on our existing asset base through disciplined spending of our development capital while preserving our drilling inventory for periods of higher prices with better economic returns.

We are also continuing the process of identifying existing assets that may not be core to our long-term business strategy for disposition at a later time.

As the implementation of the SIFT tax -- effective January 1, 2011 -- approaches, we are developing our plans for conversion to a corporation by late 2010 to present to our Board and ultimately to our unit holders. Our assets are well-suited to a distribution-oriented business model, and we expect to continue to pay a significant portion of our cash flow directly to our unit holders, even under a corporate legal structure.

So with that, I will now turn the call back over to the operator to take any questions from the audience.

Thank you. Ladies and gentlemen we will now conduct a question-and-answer session. (Operator Instructions). Andrew Taylor, Goodman & Company.

I'm wondering if I can just ask a question related to acquisitions. You clearly outlined, not only this morning but for some time now, your wish list with respect to proposed acquisition opportunities. I'm just curious as to if you can provide any sort of insight on how are you finding values in the market. Are you suffering from I guess the same challenge that Talisman faced where, just at the critical moment when they were expecting to be able to pull the trigger, equity markets opened up and everybody was able to refinance and so, as a consequence, there wasn't a lot or there was far less assets or distressed assets for sale? Any insight on what you're seeing in terms of proposed values or opportunities would be appreciated.

Well, first of all, Andrew, I would say we are not necessarily looking for distressed asset situations. I think, in the first quarter call, we indicated that there was still a gap between buyers' and sellers' expectations, but I would say that our experience is that gap is narrowing somewhat.

I think, in terms of the things that we are looking for, the opportunities are actually increasing for us. Having said that, we are also very disciplined, I think as you know, in terms of approach of making acquisitions. So we're not going to just jump in on things that might look like they are bargains but don't necessarily fit with our long-term strategic plans.

So again, I am quite optimistic that we will find the kind of transaction or transactions that will fit with our strategic plans. Hopefully, that answers your question.

Yes, thank you.

Gordon Tait, BMO Capital Markets.

A couple questions on your Sleeping Giant play -- what production are you getting out of Sleeping Giant now? How many horizontal wells and re-fracs are you planning this year?

Well, our production there is somewhere in the order of just under 11,000 BOE a day currently. As I mentioned, we are looking to potentially expand the re-frac program at Sleeping Giant. But maybe I could get Garry to comment a bit on the Sleeping Giant and where we see things going in terms of potentially drilling some additional wells this year.

So what we're focused on right now is how the cost structure is changing and where oil prices are shaking out. And so we are also trying some new technology. We are doing an interesting thing right now with our re-frac program where we are simultaneously frac-ing three wells that are in the immediate area of each other, so you get the energy of all three fracs going into the ground at the same time. We've done one of those. We are actually doing our second set of three right now, and we're watching the results there. But we are encouraged by the first set.

Then we are starting to do some multi-fracs as well. So we are looking at those three components; cost structures are coming down, oil prices stabilizing, and our technology continues to improve. So we will relook at things after this next set of tri-fracs and make our plans based on that.

What are you modeling for an uptick in production from that tri-frac program? Like what sort of extra production -- incremental production do you expect to see?

Yes, we were seeing, March, like 50 barrels per well on the re-fracs, and we are looking to see how much better we can do from that. Then we are -- on our most recent drilling, we've been averaging somewhere around 200 barrels a day.

Another piece that I guess that I could mention is the fourth well per section. So this would be on the same spacing as the third well, but it would be a leased line well. We are actually going to the state for approval to start lease-line drilling and we expect that hearing in October. That could open up another 50 or so locations.

I think the other thing is to keep in mind the number of re-frac potentials we have here. So while we have plans for a 12-re-frac program this year, there's over 100 potential re-fracs that we can do on the property. So every incremental barrel we add, both in terms of production and reserves, can be impactful to the play.

Okay. Then just lastly on Tommy Lakes, how many horizontal locations do you reckon you have?

Well, again, I will let Garry talk to it. We are just evaluating the results and doing some additional geologic work there to see where we can take it to, keeping in mind Tommy is a very developed play but I think there is some incremental value we can potentially see as a result of the horizontal.

Garry, why don't you give a little further comment?

Yes, so, as typical, we are seeing three times the reserves and rate for about twice the cost. So we expect this to open up some of the more marginal areas, which would be the northern side of the field and then the [trench] area which is on the north side of the river and quite a larger area. Then we see a few locations in the center of the field where we are having difficulty with the drain accessing the location. So with the extended reach of the horizontal well, we think there's three or four spots there.

So you add all that up and we are thinking there might be 10 or 20 horizontal locations in the areas that we would not have pursued with verticals. That would be on top of about 35 booked in-field verticals we have in the main field.

Given the current spacing we've got in the main field, it is unlikely we would go back in with horizontals. We will probably finish that program out with verticals.

Is there enough processing capacity?

Yes, what I would see is we will continue to keep that production flat for a longer period of time. We probably wouldn't see growth but we would continue to drill to fill and maintain the production the production that we've had for a number of years.

Thanks.

(Operator Instructions). Roger Serin, TD Securities.

I wonder if you could give me a sense if you had any downtime due to facilitate turnarounds.

Well, there would have been some, but it was -- I would say it's somewhat lower than we might otherwise have planned. We actually were able to continue operations and we shifted, as I said, some of it to Q3. That's why we expect to average more in the order of 91,000 barrels a day on a full-year average basis, and also combined with lower spending levels in 2009.

Do you think, Gordon, what sort of level of downtime do you think you will see in Q3, then?

Garry, do you want to -- as far as level is concerned, I mean I think there's a couple of thousand barrels a day that could be shut in for a couple of weeks at a given point in time; that will affect the third quarter.

Yes, and I would say, round numbers in Q2, we were probably 2000 barrels a day of downtime, and I would call 1000 of that as planned and 1000 unplanned. So planned would be tied to turnaround activity that we would anticipate and basically plan for. The others would be your typical downtime problems -- parted rods, compressor issues, that type of thing.

I think, going into Q2, you would see a modestly increased level due to planned turnarounds, although we have been doing quite a bit of work, doing diagnostic work in advance of those turnarounds where we are for instance looking at engine oils and such where we are more particular in this environment to save those costs. But I would say a modest increase in Q3 over Q2 downtime.

One last question, a little bit more generic. If you look at the drilling incentives in Alberta and BC and you look at your programs, what would be your top three programs (technical difficulty) point of view at roughly current commodity prices?

Well, I think some of our shallow gas development in Alberta could move forward. You know, this incentive program of course doesn't come without some degree of confusion. We've been working our way through that because of course it is based off your production profile in 2008, and the combined with how you're going to collect other royalties which is the key, and then what you get to the credit. That $200 per meter, it probably covers 20% to 25% of your costs on these wells. So it's meaningful and it's impactful and it will probably drive more of the shallow gas in Alberta.

If I could add to that, basically we almost get the shallow gas wells drilled for free. So it takes what would have been, at these lower gas prices, a pretty modest program and we are going to see probably 100% rate of return on this drilling. So we have suspended the drilling in Shackleton and we are moving into the Crown lands in Alberta.

Something noteworthy -- there's quite a bit of our land that is actually fee land, relative to the shallow gas, so we would be targeting the Crown land to take advantage of the royalty break.

Any other projects that sort of jump up as being dominant from an activity point of view?

The re-fracs in Sleeping Giant continue to be very attractive. Then I would say that typical optimization -- optimization is basically going into existing well bores and looking for opportunities to add perps, re-stimulate those kinds of things. Those typically are some of your best economics because it is more enhancing the existing production versus having to drill a new well.

Then the oil program itself, we are just starting to fire up the drilling rig again in Manitoba. We see some pretty attractive economics in our water floods. But we've wanted to let those service costs or the drilling costs come down, and we are seeing rigs go for quite a bit less and we're starting to see all of the incremental services tied to a new well coming off. Given where oil prices are starting to stabilize and those cost structures adjusting as we expected them to, more and more of those programs are becoming attractive.

Thanks very much, guys.

Robert Dickey, Dickey Capital Management.

Yes, I just want to thank everybody up there for their hard work, and I have kind of a strange question. I am a small money manager down here in South Florida, and I am looking at my fine copy of Baron's this morning. I wanted to know -- they are showing your earnings last year -- these would be in Canadian dollars, at CDN5.18 -- this is consensus estimates, and CDN0.29 this year and CDN0.13 for next year. Does that sound at all accurate or -- it doesn't really make much sense to me.

Well, I haven't seen the Baron's article. I mean, in the quarter, we actually had a small loss of CDN3.5 million, so I'm not sure what is driving their numbers.

Obviously, the key for us right now is the commodity price. We've seen the improvement in the oil price, but gas price has actually gone further down through the quarter. So depending on the view of prices that they are building into their numbers, that will really shape the earnings number.

Obviously these are net of all your distributions and everything else and your expenses, so anyway, okay, well, thanks for your color on that and have a good rest of the week.

Robert [Siegel], [Capital] Group.

Yes, good morning. Given the fact that oil prices have doubled or actually even more than doubled since the Company slashed its distribution in the first quarter, has any consideration been given to reinstating a portion of the distribution that was cut? If not, how much would natural gas prices have to increase before the Company would give serious consideration to reinstating a portion of the cut distribution?

Well, just to back up a little bit and be clear, the decision to reduce distributions wasn't made lightly but certainly in the context of the economic environment and what was shaping up in the commodity price front, it was determined that this was a move we had to make.

As I mentioned in the call, right now, we see our full-year adjusted payout ratio -- and that means our CapEx plus distributions combined compared to our projected cash flows -- to still be in the order of about 100%, so I can't tell you, at this point in time, that we can look at increasing distributions.

How much would prices have to improve? That again is a little bit of a tricky call. Based on what we see in the gas price front in particular, we are just going to hold at the CDN0.18 for this point in time. Again, if you saw significant increases in prices, in fact maybe not necessarily to the levels we saw last year but significantly up from where they are even right now on a combined basis, then I think then we could give consideration to an increase in distribution.

But right now, one of our principal drivers has been to keep our spending levels reasonable, relative to those cash flows, and also keep our financial strength intact so that we can take advantage of acquisition opportunities. We think this is just an opportune time to basically buy into additional assets that will fit with the long-term strategy of Enerplus.

Excuse me, so in another words, could I take that response to mean that, if even with safe natural gas were to climb back at roughly (technical difficulty) levels -- (multiple speakers)

You broke up on your comment on gas price, so I didn't quite hear.

No, I'm saying, let's say -- let's say (inaudible) to infer from your answer, in other words even if natural gas prices were to climb back let's say up to CDN6 and thus if oil prices to were to remain at the current roughly CDN70 level, that would bring commodity prices back to roughly 2007 levels when the distribution was roughly double what it is now. But am I let's say to infer that, even if natural gas prices were to stage a significant increase, is that the Company is placing a higher priority on acquisitions rather than reinstating part of the distributions that were cut?

Well, you know, again, we've had a history and a track record of making timely acquisitions. So I don't want to over-color it, but definitely it is part of our strategy to keep the financial strength and keep the cash flow available for capital spending. But if we saw significant increases -- and it would be a topic of discussion with our Board to see if there was enough potential to increase the distribution again. So I can't just land on one factor, too, to make that call. I mean, we consider a number of things in the context of what's happening around us.

Take for example our Kirby situation. You know, the oil prices have improved but we would be looking for stability in oil prices and cost structures before we could move forward on something like that. So it's very hard to just isolate on one factor and say, okay, that would be the driver to, say, make an increase in the distribution.

I might also throw out let's say one consideration for the Board, Mr. Kerr, is that, in other words, if there were a reinstatement of a portion of the cut distribution, one very possible positive byproduct of that might serve let's say to increase the share price, which has been basically let's say flat on its back for quite some time right now, which in turn obviously -- a stronger share price would enhance the Company's ability let's say certainly let's say to use its shares to make an acquisition.

Yes, I appreciate your comments. It's certainly something we talk about in terms of trying to find the right balance on things overall.

There are no further questions at this time. Please continue.

Well, I guess, if there's no further questions at this time, we conclude our call and thank everybody for joining us this morning and have a great day.

Ladies and gentlemen, this concludes the conference call for today. Thank you for participating. Please disconnect your lines.