Enerplus Corp (ERF) 2010 Q1 法說會逐字稿

Good morning. My name is Chris and I will be your conference operator today. At this time, I'd like to welcome everyone to the Enerplus Resources Fund first quarter results conference call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session.

(Operator Instructions). Thank you. I would now like to call over to Jo-Anne Caza, Vice President of Corporate and Investor Relations. Please go ahead.

Thank you, Operator, and good morning everyone. I would like to welcome everyone to Enerplus's 2010 first-quarter conference call. Mr. Gordon Kerr, our President and CEO, will be summarizing the results of our first quarter in more detail and giving some additional information on our strategy going forward.

To help answer some questions today at the end of our call, we also have with us Mr. Ian Dundas, our Executive Vice President, and Mr. Robert Waters, 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 first-quarter news release issued this morning and included with our MD&A and financial statements 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 may also call our toll-free investor line at 1-800-319-6462.

All financial figures referenced during this conference 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 will open the phone lines and answer any questions you may have. I will now turn it over to Gord.

Thanks, Jo-Anne, and good morning, everyone. So let me start off by saying that we are in the midst of transitioning Enerplus into a growth and income-oriented oil and gas producer. Adding more early-stage assets into our portfolio is critical in achieving the growth elements of our strategy.

I am pleased to say that we continue to make progress in this regard. We have successfully increased our land positions in our early-stage resource plays, including the Marcellus Shale gas play in Pennsylvania and West Virginia, the Bakken tight oil play in Saskatchewan and North Dakota, and the Deep Basin tight gas play in Western Canada.

In the Marcellus, we acquired another 10,000 net acres of land since year-end, spending approximately CAD50 million and secured our first operating position in this region. This increases our land inventory to approximately 136,000 net acres.

We expect to drill our first operated well toward the end of 2010. Results continue to meet or exceed our expectations with respect to production rates and contingent resource assessments. I'll go into more detail on these points in a few minutes.

In April, we purchased approximately 100,000 net acres of undeveloped Bakken land in southern Saskatchewan for CAD117 million. This land is contiguous to our existing acreage and we now hold 100% working interest in 142,000 acres of undeveloped land in the Freda Lake/Neptune area of Saskatchewan.

We have also added 8300 net acres of undeveloped land in the Deep Basin Fairway. This increases our holdings to approximately 34,000 net acres of undeveloped land where our focus is on the Montney and stacked zone potential in the Mannville.

We are currently evaluating the results of two test wells drilled in this play area.

We are continuing with our plans to sell non-core conventional assets with production above 14,000 barrels a day equivalent. We continue to expect to sell a portion of these non-core assets and realize at least CAD200 million this year from these dispositions. We also plan to redeploy these proceeds into new early-stage resource play acquisitions and development.

Our strong financial position is an important element in transitioning our asset base. We ended the first quarter with our entire CAD1.4 billion credit facility undrawn. We maintained a debt to 12-month trailing cash flow ratio of only 0.7 times, one of the lowest within our peer group.

With respect to our operational results, we are very much on track with the guidance we provided in December. Production averaged 84,719 BOE per day during the quarter and we continue to expect annual production will average 86,000 BOE per day and that we will exit the year at 88,000 BOE per day. This does not include the potential impact of any acquisition or divestment activity that may occur throughout the year.

Cash flow from operations was CAD1.07 per unit, which is unchanged from the fourth quarter of 2009. We paid out 51% of our cash flow through our monthly distributions of CAD0.18 per unit and when we add in development capital spending in the quarter, our adjusted payout ratio was 101% of cash flow.

Operating and general & administrative costs also remain on track to meet our annual guidance. And with respect to development capital, we spent CAD95 million in the quarter with 56% of this invested in Bakken tight oil and crude oil waterflood projects.

We drilled 137 net wells in the quarter with the majority of these being shallow gas wells that took advantage of the Alberta drilling royalty credit program. Most of our natural gas spending, however, was on our Marcellus and tight gas assets where we spent CAD30 million.

We continue to expect our capital spending to be CAD425 million in 2010. However, we may reallocate more money to crude oil projects depending on the opportunities we see in our growth plays throughout the year.

With respect to our activities in the Marcellus, even though Pennsylvania was hit with record snowfall, 12 gross wells were drilled in the Marcellus during the quarter, 2.7 net to Enerplus. These wells were drilled across seven counties and we now have six rigs running in the play. The heavy snowfall did cause some delays in completions in pipeline work, however, activities are back on track.

Drilling costs continue to meet our expectations at CAD4.5 million. Drilling days have trended lower than we initially expected even though we are drilling longer horizontal wells with more frac stages than initially planned. Lateral links at the horizontal wells have ranged from 2,500 feet to 5,200 feet with 7 to 10 frac stages per well.

We also drilled our first multi-well pad site with five wells.

We are very excited about the early results we are seeing in the Marcellus. 24-hour test rates for the last 10 wells drilled were 4.5 million cubic feet per day. The best well in the Northeast development area tested at 8.2 million cubic feet per day and the best well in the Southwest area tested at 7.1 million cubic feet per day.

Enerplus's share of production from the Marcellus averaged 2.7 million feet -- million cubic feet per day during the first quarter. And as of May 1, volumes have increased to approximately 6 million cubic feet per day. There are currently 19 wells on production comprised of 15 horizontal and 4 vertical wells and another 39 wells waiting on tie-in and/or completion. And our working interest in these wells is approximately 20% on average.

We continue to expect to exit year end with volumes of over 18 million cubic feet per day from the Marcellus.

We are also excited with the progress we have made in increasing our Bakken oil potential. We have acquired 108,000 net acres of undeveloped land in this play since the end of the year. We now own a total of 170,000 net acres of undeveloped Bakken prospective land in both Canada and the US.

As I mentioned at the start of the call, southern Saskatchewan is now an exciting and meaningful tight oil prospect area for us. In the last six months we drilled and completed three Bakken horizontal, multistage frac wells in our 100% operated Freda Lake/Neptune region. Early test results are positive and we do plan to contract two rigs that will help us further delineate the potential on these lands and develop this play.

Given the similarity in well depths and reservoir quality to our joint-venture assets at Taylorton, we expect similar type curves for successful wells on these new lands. We believe the economics of these wells will be attractive and expect that, ultimately, we could develop the play with up to four wells per section on a risked basis.

We also drilled three gross horizontal wells with a 50% working interest at Fort Berthold in North Dakota during the quarter. We currently have 2 wells producing and initial 24-hour test rates look good at approximately 1,100 BOE per day per well. We expect to have another 3 to 6 wells completed by the end of June. Based on the results so far, we may direct more capital into this region during the rest of the year.

Finally, development work continued at Sleeping Giant, Montana. We drilled 5 gross, 3.5 net wells during the quarter and all of these wells are currently on production. We are encouraged by the production rates from these wells and are studying these results in conjunction with an analysis of the entire field. We still expect to drill an additional 4 operated wells and 2 non-operated wells at Sleeping Giant during the balance of the year, but we will be evaluating our plans in relation to our field analysis work and our other development opportunities, including refracs.

As we stated at last year end, we expect to hold a Unitholders Meeting in December subject to our Board of Directors approving our conversion plans. We expect to convert to a dividend-paying corporation effective January 1, 2011.

As we have previously stated, we do not expect to adjust our monthly distributions as a result of this conversion. However, we cannot guarantee distribution levels because of the volatility of commodity prices and the uncertainty of future acquisitions and divestments. We expect to use approximately CAD3 billion in tax pools to provide shelter from cash taxes in Canada for three to five years after we convert to a corporation.

The actual period of this shelter will be impacted largely by commodity prices, acquisition or divestment activity, production levels, and capital spending. After this period, we would expect to be taxable at an estimated rate of 10% to 15%.

So to conclude, we are committed to a strategy that offers both growth and income to our investors. We expect to continue building on our early-stage growth opportunities in the Bakken tight oil, Marcellus Shale and Deep Basin tight gas resource plays. We also remain focused on developing our core cash generating properties and continually improving our operations.

I think for not only myself but the rest of my executive team, management staff when I say that we are all excited about the opportunities ahead for Enerplus and our investors.

So with those comments, I will now turn it back to the Operator to take any questions from the audience.

(Operator Instructions). Gordon Tait from BMO Capital Markets.

Good morning. Couple of questions on your -- just on the production capital spending summary you provided. It looks like, from what I can see, that the shallow gas, you are not putting a lot of capital with your shallow gas properties. Are you just expecting those, the production area to fall? Are you aiming to maintain it? What is your strategy there?

Well, strategy is one thing, Gordon. As far as production, yes, we are not getting as much capital into the shallow gas. So we are expecting some declines, relative to that.

With respect to the strategy going forward, we still think there's good opportunity. But quite frankly at current prices it's a challenge to invest in those assets.

We have, as I said earlier, invested in some of our shallow gas. And certainly it has been supported by the Alberta Drilling royalty credits that we can gain with that drilling. But we will be looking at the reservoir and what we can get. Certainly an improvement in gas prices will help us to advance again on the shallow gas.

And then on your Bakken tight oil play, it looks like the IP rates in the North Dakota side are pretty high -- at least the 24-hour IP rates. What is the difference in cost? The drilling costs per well between the say on the Saskatchewan side, your Bakken play on the Saskatchewan side versus your North Dakota?

Well, first of all, over all, you are into a deeper area of the Bakken south of the border for starters. And then, it is going to be dependent on how much or what the completion strategy is on a particular property. In other words, how many -- what's the lateral length of the wells that you're drilling in that.

Generally you are probably looking somewhere in the order of about CAD2.4 million for a well in Saskatchewan. Again depending on frac stages in that and then south of the border, it is anywhere from say CAD4.5 million to CAD5.7 million. Again depending on the lateral length. So for example in North Dakota the lengths will vary somewhere between say 44,000 to 9,000 foot lateral lengths and that will be determining the costs.

So on the higher-end you are talking about the longer lateral length with probably more completion stage, or frac stages in the completion work.

And then on the Saskatchewan Bakken, what were the 30-day IP rates on those three Bakken horizontal wells?

We are actually very early in this. I think in our release we indicated that we are in the breakup period right now. So we are waiting actually to get back on the lease to really see what we've got here. So too early for us to even talk about that, honestly.

Okay and one last question.

There's been some talk, I guess, over the US, some of the counties in Pennsylvania and other places where they have -- where shale gas is being produced and some of the regulators. Are there any regulatory issues do you perceive coming that would prevent you from developing that shale play there, as you see it?

Oh you know, I mean, there are always different regulatory challenges. I'd say generally that there's nothing that's staring us in the face right now or that we contemplate. I think a lot of the concerns have been raised north of Pennsylvania in the New York State area. And, again, I think a lot of that has to do with where is the watershed line relative to potable water within the state of New York principally.

So we don't see any great issues there. The one thing is that the activity level is heating up obviously in this Marcellus Shale gas play. And that's putting a burden just on the regulators in terms of times to get work done.

But by and large, as I said earlier, plans are on track and we are progressing. So --.

Eugene Lipovetsky from Zimmer Lucas Partners.

Hello. Just one quick question on some on some of those new Bakken wells in the US that you're drilling, in Fort Berthold -- what is the percent gas cut of the total hydrocarbon stream from these wells?

Well, it is relatively low in the grand scheme of things. So you know it's not really a big factor in our thinking in terms of developing this play. There is some gas that is currently in play.

But as we develop this out, I think we will be looking at what we can do to conserve it, but it's not the big driver here.

So you are flaring the gas currently?

Currently it's being flared.

Roger Serin from TD Securities.

I wonder if you could give us a little information on guidance? Maybe from Rob on the cash taxes in the US. I mean, you are not paying any in with your capital program. Do you expect not to pay any for the next couple of years?

Roger, I think we say that we expect -- -- we don't go out a couple of years from the US, but for this year and next year it's probably about 5% of our US cash flow, which would be the effective tax rate. But in the first quarter I don't think we paid any US taxes, but over the course of the year we would expect to be at 5% or slightly under that.

I think the other part of this is that we will be dependent on whether we advance capital again on some of the play development there, but in other words, you know the Fort Berthold region is something that obviously we could potentially see step up in capital. So that points to additional IBC type costs and depletable property costs in the US.

So moving on to the US then, and the Marcellus, you gave information on average rates of about 4.5 million a day. In your March 2010 IR presentation, you got some tight oils in there and you look at sort of industry high, low and mid-cases and on the mid to case, the IP rates are at least in your presentation, 5.3 million a day. You are talking about rates. And those are 30-day rates and you are talking about 24-hour rates at less than that.

Should I read into that that there are either some testing issues, pipeline pressure issues? Or should I read into this that these wells are coming in at the lower end of what you showed in your IR presentation?

Well, I think if I remember the presentation - I don't have it right in front of me - we were pointing to some of the data that's out there from people like Ross Smith Energy and Tudor, Pickering, Holt. And our type curve that we based our economics on was looking more towards the 3.2 to 3.4 type of IP rates in the fullness of time.

So I think our point is that these results are positive, relative to how we have assessed economics relative to the play. You know, I think you really have to give it some time to work its way outward. Again, pretty early stage in this. Albeit, we've got 58 wells in various stages in the play right now, it is still early.

You're right. You do talk about 3.2 million to 3.4 million a day equivalent, but the third party was higher. Okay.

Just a couple other questions. You talk about 30% of your gas is tight gas in Canada. Could you give me a sense of broadly what play types you are sort of lumping into tight gas?

Well, first of all, we certainly have our play at Tommy Lakes and we are not putting a lot of capital into the Tommy Lakes right now. So continue to produce that and then as I said, in the Deep Basin area, we are looking at, can we spend our position on the Montney? And -- but more importantly, the stacked Mannville play as far as a tight gas play is concerned.

So basically Deep Basin plus your Tommy Lakes stuff?

Right.

Two last questions. Kirby - can you give me any update on your steps that you are taking to either advance the project or crystallize value?

Well, I think at this point all we are advising is that we are considering options for Kirby. This is, I think as you heard us say a number of times, it is very attractive in our mind anyway and in the mind of a lot of, I'd say our staff still, asset. And so we are just evaluating the options. And certainly you've seen an increased interest again, if you will in the oil sands, and coming from different directions. And by that I mean in terms of the parties that are interested in acquiring these type of assets.

So we would consider a various variety of options and we are just in that process right now. But it is an asset that I think in the context of our valuation hasn't been given a lot of recognition in the market.

Have you engaged anybody to help you in that process?

Yes.

I think the last question coming up here. So you spent over CAD100 million in the Bakken and Saskatchewan land sales. From what I can tell there is limited data. We don't have any production data, obviously. There is one well that was completed in November so do you have production data or you are basically doing this on land sales on petro-physical and analogous type work?

Well, I think I answered the question earlier with regard to the status of the wells that we have drilled there. Certainly we would have data, relative to what we drilled into so far. And certainly we've looked at petro-physical data, we've looked at what activity happened in and around the play area and other information that we were gathering through this whole period. So I think I'll just leave it at that point for now.

You know, the other thing to think about is last year we sold about 4.5 sections of land for CAD100 million. So we look at this as redeploying that capital with potential significant opportunity to us.

That sounds like a good trade. Okay. Thanks.

(Operator Instructions). There are no further questions at this time.

I think that concludes the call, Operator.

As she said, this concludes today's conference call. You may now disconnect.

Thanks for joining us.