Enerplus Corp (ERF) 2009 Q3 法說會逐字稿

Good morning, ladies and gentlemen. Thank you for standing by. Welcome to the Enerplus Resources Fund third quarter results conference call. At this time, all participants are in the listen-only mode. Following the presentation we will conduct a question-and-answer session. (Operator Instructions).

I would like to remind everyone that this conference call is being recorded today, Friday, November 13, 2009 at 11 AM Eastern time. I will now turn the conference over to Jo-Anne Caza, Vice President - Corporate and Investor Relations. Please go ahead.

Thank you, Operator, and good morning, everyone. I would like to welcome you to Enerplus's 2009 third quarter conference call. Gord Kerr, our President and CEO, will be relaying the results of our third 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 Rob Waters, our Senior Vice President and Chief Financial Officer and Ian Dundas, our Senior Vice President of Business Development.

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 third quarter news release issued this morning and included with our MD&A and financial statements filed on Edgar and SEDAR 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. You may also 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 barrels to barrels of oil are -- sorry, 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. So I will now turn it over to Gord.

Thank you, Jo-Anne, and good morning everyone.

First of all, I am pleased to report that our operating and financial results for the third quarter of 2009 continue to be on track with the expectations we set out at the start of this year. We also continue to make progress on a number of strategic initiatives we set to improve our performance and transition our business to a more focused early-stage resource play company.

We believe these changes will position us to provide both growth and income to our investors in the future.

One of the most significant accomplishments this quarter was the acquisition of an average 21.5% working interest in over 540,000 gross acres in the Marcellus shale gas play located primarily in Pennsylvania. Now this play is considered one of the best developing shale gas plays in North America. Its location to the largest natural gas market provides superior economics to other shale gas plays and, given the current stage of development, we believe this asset will provide tremendous growth potential for Enerplus.

I'll get into further details regarding this acquisition later in the call.

Now we have continued to maintain our financial strength throughout the quarter as well, balancing our capital spending and distributions to unit holders and preserving our balance sheet strength for growth opportunities. We continue to have one of the lowest debt-to-cash flow ratios in the energy sector at 0.7 times.

Our production averaged approximately 90,111 BOE per day during the quarter and 93,184 BOE per day for the first nine months of 2009, putting us on track to meet our full-year guidance of 91,000 BOE per day.

Given the level of capital spending we set for 2009, we continue to expect our exit rate will average approximately 88,000 BOE per day. Our cash flow for the third quarter was approximately CAD207 million, comparable to that of the second quarter. Approximately 45% of our cash flow was distributed to unit holders during the quarter through our monthly distributions, which were maintained at CAD0.18 per unit. And when we combined distributions to unit holders and our development capital spending, our adjusted payout ratio was roughly 68% of our cash flow for the quarter.

During the first nine months of the year, our distributions in CapEx totaled approximately 78% of our cash flow. However given the higher level of capital spending planned for the fourth quarter of 2009, we continue to expect our adjusted payout ratio for the year to approach 100%.

We also invested approximately CAD45 million in development capital during the quarter, drilling 48 gross wells with about 28 wells net to Enerplus. Our year-to-date capital spending has totaled approximately CAD180 million to drill 229 gross wells, 157 net to Enerplus with a success ratio of 99%.

We have been actively working to reduce our costs throughout 2009 and our efforts have resulted in operating costs of CAD10.07 per BOE for the third quarter and an average of CAD9.94 per BOE for the full year. Based on these results we are lowering our full-year guidance from CAD10.65 per BOE to CAD10.20 per BOE, an improvement of over 4% from our original target.

Our general and administration costs were CAD2.41 per BOE for the quarter, on track to meet our full-year guidance of CAD2.45 per BOE.

Continued weakening in natural gas prices resulted in an average selling price of CAD2.95 per MCF, down 64% from the same period last year. Crude oil prices rebounded slightly during the quarter; however, they still remain significantly lower than the third quarter of 2008. We realized an average selling price of CAD64.95 per barrel during the third quarter, a 41% decrease from the same period in 2008.

Our risk management program helped offset some of the continued weakness in commodity prices we experienced during the quarter. We realized cash gains of approximately CAD24.5 million on our natural gas hedges and approximately CAD16.1 million on our crude oil hedges during the quarter.

For 2010, we have downside protection, price protection in place for approximately 17% of our natural gas production at an effective price of CAD6.80 per Mcf and for approximately 31% of our oil production at an effective price of approximately CAD75.87 per barrel based on current forward market prices.

As I mentioned previously, an important component of our corporate strategy has been to acquire early-stage resource play assets in North America, with a focus on tight gas and tight oil projects offering superior economics and significant growth potential.

As announced in September, we have purchased a 21.5% working interest in over 540,000 gross acres of land in the Marcellus Shale gas play, primarily in Pennsylvania from Chief Oil & Gas and certain affiliated entities. Total consideration was $411 million, consisting of an upfront payment of $164 million that was paid upon closing and another $247 million that is to be paid as a carry of 50% of Chief's future drilling and completion costs, which we expect will be invested over the next four years, if not sooner.

Our internal assessment has identified over 1.4 trillion cubic feet of best estimate contingent resources on these lands net to Enerplus. This would almost double our 2P natural gas reserves currently booked. And there are over 2,400 drilling locations currently identified based on a 55% land utilization.

Our current development plans will see over CAD800 million invested over the next five years with expected production growth of approximately 100 million cubic feet of natural gas per day, net to Enerplus, by 2014.

In conjunction with the Marcellus acquisition, we completed an equity financing, issuing approximately 10 million units for gross proceeds of CAD225 million. The proceeds were used to fund the upfront cost of the acquisition and the remainder reduced our outstanding bank debt to zero.

We currently have our full CAD1.4 billion bank credit facility available to us. Subsequent to the quarter end, we completed another acquisition adding to our portfolio of Bakken assets. We purchased a 50% non operated working interest in over 22,000 gross acres of prospective Bakken land in North Dakota for $27 million. We have assessed a best estimate of contingent resources of approximately 7.4 million barrels, net to Enerplus, on these lands based upon a 13% recovery factor.

We've stated throughout 2009 that part of our transition would include the divestment of assets that do not fit with our strategy. Subsequent to the quarter, we also sold approximately 4.5 net sections of low working interest, non-core property interest in southeast Saskatchewan for approximately CAD100 million. These lands were producing about 200 BOE a day of oil with 1.5 million BOE of booked crude plus probable reserves.

Our development capital spending continues to reflect the prudent approach we undertook at the start of 2009 in light of commodity price uncertainty and a focus on achieving compelling returns on our investment. Our activities in the first half of 2009 were focused on natural gas drilling on our shallow gas and tight gas resource plays. And as the price of natural gas continued to deteriorate throughout the year and oil prices strengthened, we began shifting our development program. This shift resulted in a low level of spending in the third quarter and set up for a high activity level in the fourth quarter.

For the balance of the year, we expect to focus on oil projects on our Bakken lands and waterflood assets and are limiting our natural gas activities primarily to the Marcellus, and in Alberta, utilizing the Alberta Drilling Royalty Credit incentive. During the quarter, we drilled 12 wells at Shackleton in Saskatchewan, completing our activities there for the year.

Due to the weak natural gas prices we have elected not to tie these wells in until gas prices recover. However, we also started drilling the first nine of approximately 250 shallow gas wells in Alberta to take advantage of the DRC incentive.

This program offers a credit of CAD200 for every meter drilled, allowing us to substantially recover the cost of drilling a shallow gas well. We plan to utilize the benefits of this program, primarily at Verger, Bantry, Hanna Garden and Princess. Most of this drilling activity is expected to occur in the fourth quarter of 2009 and we expect to complete and tie in wells as economic conditions warrant. So new production associated with this drilling is not expected until 2010.

We also plan on drilling approximately 15 oil wells under the DRC program at various locations throughout Alberta later this year or early next year.

Based on drilling plans for the fourth quarter, we are estimating recovery of approximately CAD22 million from the DRC program in the current year. Capital spending in our Marcellus shale gas play is expected to be approximately CAD40 million in 2009, up from our original estimate of CAD30 million. We expect this spending to consist of CAD20 million in drilling capital, CAD5 million in land and seismic, and CAD15 million of carry obligations mentioned previously.

To date, a total of 39 wells have now been drilled on our Marcellus lands, 28 horizontal wells and 11 vertical wells. Eight of these wells have been drilled since we acquired our interest in September.

Currently, 20 horizontal wells are waiting on completion and seven horizontal wells are either being drilled or remain to be drilled in 2009. Given encouraging results to date, we are adding a fourth rig and expect 2010 capital expenditures to exceed our initial estimates. Activities have been focused on testing new areas and drilling and completion methods to identify the optimal approach.

We expect to move to pad drilling this winter in several areas which have been derisked by offset wells.

Chief Gathering LLC, the midstream subsidiary of Chief Oil & Gas, continues to progress with the construction of its pipeline infrastructure. Chief Gathering has secured seven interstate pipeline interconnects, two each in Lycoming and Fayette counties and one in each of Bradford, Susquehanna and Clearfield counties. We expect to provide a more detailed update on drilling results and capital plans as part of our 2010 guidance, which we plan to announce mid-December.

Current production is approximately 10 million cubic feet per day gross, with 2.1 MCF -- MMcfe per day net to Enerplus from 11 producing wells, of which six are horizontal and five are vertical.

The improvement in crude oil prices has also resulted in us increasing our activity in our Bakken/Tight Oil assets. At Sleeping Giant, we are resuming our drilling activity and have increased our refrac program to 18 refracs for the year, with plans to use tri-fracs, where we frac three wells simultaneously, to complete the program.

12 refracs have been completed at the end of the third quarter. This activity continues to yield positive results with production gains of approximately 50 BOE per day gross or 35 net to Enerplus for refrac and expected reserve additions of 50 MBOE gross or 35 net to Enerplus.

We have contracted two rigs and plan to drill four wells at Sleeping Giant by year end. We estimate at year end we will have eight third well and 40 lease line drilling locations remaining on our lands, as well as approximately 100 refracs in our inventory. We also plan to continue drilling at Taylorton in southern Saskatchewan, where we participated in the drilling of five gross wells, of which we have a 25% working interest, in the third quarter, and have another three gross wells planned with our partner for the fourth quarter.

On our newly acquired North Dakota acreage, initial plans include four gross wells to be drilled in late 2009 or early 2010. Although this is a 50% working interest non operated position for Enerplus, due to our considerable drilling expertise in the Bakken, we will operate the drilling activities. Additionally, we have plans to drill on our operated Bakken lands in other areas as part of our overall Bakken portfolio.

Drilling activity is also expected to increase in our crude oil waterflood properties in the fourth quarter. We currently have development plans at Virden in Manitoba, a Glauconitic "C" unit at Medicine Hat in Alberta and our Freda waterfloods in Saskatchewan. A total of 11 gross wells are planned in these areas, all of which will be horizontal wells.

The current moratorium on licensing any wells with H2S content in Alberta may slow our plans at Medicine Hat. We are also increasing our conventional oil activities on select fields, primarily in southeast Saskatchewan, and plan to drill approximately three wells in the fourth quarter.

We continue to maintain our capital guidance of CAD330 million for 2009 including our carry obligations associated with the Marcellus shale gas play and which is net of the credits associated with the DRC incentive, with fourth quarter spending up significantly over the previous quarters of 2009.

So to conclude, let me reiterate the key points of our business strategy going forward. We believe a balance of growth and income will provide a compelling investment opportunity. The addition of more early-stage resource play assets to our portfolio of core cash flow generating assets will help us achieve this. We expect these early-stage assets to be focused on tight gas and tight oil that we believe will deliver top quartile economics. We plan to utilize our balance sheet strength prudently to acquire additional assets and also help fund the capital needs of these growth plays. We also remain focused on the successful execution of our operational plans, maintaining the discipline we apply to our spending and improving the efficiencies of our day-to-day business.

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

(Operator Instructions). Gordon Tait. BMO Capital Markets. Please go ahead.

Good morning. I had a question on -- just a little bit more information on some of your new acreage, your newly acquired acreage in North Dakota. Do you have a sense of how many wells you might ultimately drill? Like how many drilling locations you have on that acreage?

First of all, Gord, I didn't know you had changed your last name to Tight. But it kind of makes some sense. Sorry about that.

It's to confuse you.

Garry, do you want to maybe comment on that?

We are early-stage into this play, so we are obviously sensitive to what we talk about at this particular point. We do have, as I said, a couple of wells planned in the area here this year, but in terms of full scope --.

Yes, it's early days, but you can see that going to multiple wells per section, we've got 25,000 acres. So it could be a fairly significant play. And it is early days, but we have -- we are just drilling, we'll drill four wells into that the rest of this year. But when we look around there are a number of wells offset our acreage which gives us confidence it is oil-charged. And we think it will be a good development, but it is early days.

The other thing about that area is typically these tend to be very long laterals and a high number of stages of fracs. So I think we got to be careful, too, in terms of it's not the traditional single section wells. What they are starting to do down there is actually drill across two sections and put as many as 20 stage fracs into those wells.

And what kind of recoveries might you expect in a well?

Yes, I think what we had planned, we were down in the 15% recovery expectations.

And what sort of barrels does that translate to?

Yes, we are looking -- it's still early days, but you would expect something in the order of what you see in some other Bakken properties, where Sleeping Giant, we talk about 4 million barrels per section. So it's early days here, but you might see something along those lines.

But these are pretty expensive wells to drill?

They are.

What are you spending per well?

Yes, if you do the long horizontal, you could spend as much as CAD5 million.

Okay. And then just on the refrac program at Sleeping Giant, what does it cost per refrac roughly?

Yes, those have dropped quite a bit. We were spending -- I'll say pre meltdown as much as CAD700,000 and now we are down to about CAD450,000.

All right, thanks very much.

Jim Mahoney with the Daily Oil Bulletin.

Good morning. I'm wondering in terms of natural gas spending, you mentioned Shackleton. I understand in the third quarter you basically either deferred or delayed some spending there. I'm wondering at what kind of gas price would you sort of resume your program there or ramp up your drilling program at Shackleton?

You know, we've got, I would say, various areas within Shackleton that we could drill, even with where prices are moving to right now in the CAD4.00 to CAD5.00 range. I would say that overall, a CAD6.00 price would support basically all the area drilling in Shackleton.

So we will probably look at whether we not -- we, in 2010, reinvigorate some of our spending into Saskatchewan at Shackleton. I mean I expect we will do some drilling in Shackleton based on those areas that can be supported at the low gas price levels that we see in the CAD4.00 to CAD5.00 range.

And in terms of the Marcellus in 2010, would you have any idea -- just sort of a rough ballpark estimate -- for what you might be spending in the Marcellus in 2010?

I think at this point what we have indicated is that versus our original announcement and guidance that suggests that we would be spending somewhere around $100 million, directionally we see that increasing. But it is still early and we are not going to really get into that until we release our guidance in mid-December.

Okay. I think that's about it for my questions. Thanks.

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

Thanks. I just wanted to ask you about any other asset sales. Are you planning -- do you have a disposition program in place? Or do you have a target by terms of production or dollars you would like to raise in asset sales for 2010?

First of all, we don't have a disposition program in place, to pick on your words. We definitely have a view towards disposing of some of our assets that don't fit within our long-term strategic plan.

And so, we will be looking at moving into disposition in -- I'll call it mode in the first quarter of 2010. Recognizing that there is a lot of activity out there on that front, as you well know, we are in -- I think -- a very enviable financial position. We've got a lot of balance sheet capacity.

So we are not in a rush to dispose of assets. But we have identified a chunk of, if you will, of our portfolio that is not going to fit within our long-term strategic plans. And those are the assets that we will look to exit out of, and that could be anywhere from 10,000 to 15,000 barrels a day equivalent production out of our existing portfolio. So that hopefully gives you some sense for where we're moving.

Thanks.

We have no further questions at this time. Please continue.

Operator, if we don't have any further questions, I think we can conclude the call.

Ladies and gentlemen, this concludes the conference call for today. Thank you for your participation. You may now disconnect your lines.