Enerplus Corp (ERF) 2011 Q1 法說會逐字稿

Good morning. My name is Jessica and I'll be your conference operator today. At this time, I'd like to welcome everyone to the Enerplus Corporation first-quarter results conference call. (Operator Instructions). Thank you. 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 Enerplus's 2011 first-quarter conference call.

Gord Kerr, our President and CEO, will be summarizing the results of the first quarter and providing some additional information on our strategy going forward. And Ian Dundas, our Executive Vice President and Chief Operating Officer, will provide more details on the operational results of the first quarter as we go.

To help answer some of your questions at the end of the call, we also have with us Rob Waters, our Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Canadian Operations; Dana Johnson, President of U.S. Operations; Eric Le Dain, vice president, strategic planning -- sorry, Senior Vice President, Strategic Planning, Reserves, and Marketing; and Rod Gray, our Vice President of Finance.

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

Our financial statements were also prepared in accordance with International Financial Reporting Standards, including comparative figures pertaining to Enerplus's 2010 results. Participants are also directed to our website for a replay of this call, as well as other information on Enerplus, and investors may call our toll-free 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 six-to-one conversion ratio. Following our review, we will open the phone lines and answer any questions you may have.

So I will now turn it over to Gord.

Thanks, Jo-Anne. Good morning, everyone, and thanks for joining us.

I just want to create some context as we move to talk about our first-quarter results. Over the last two years, we've significantly repositioned the portfolio of Enerplus, adding over 500,000 net acres of prospective land to our portfolio in areas such as the Bakken, Three Forks, and Ratcliffe late-oil plays in North Dakota and Saskatchewan, the Marcellus shale gas play in northeastern U.S., and then liquids-rich natural gas plays in the Deep Basin area of western Canada.

In addition to the significant resources associated with these new growth assets, we've also identified significant upside potential on a number of properties within our waterflood portfolio. Subsequent to year-end, we advised that we had assessed an additional 60 million barrels of contingent resource under enhanced and incremental oil recovery methods on these properties. This potential upside equates to 70% of our booked waterflood reserves.

Based upon the plans we've laid out for 2011 and 2012, we expect to spend in the order of CAD650 million in each of the next two years and to grow our production volumes by 10% to 15% and our cash flow by 15%.

In the first quarter of 2011, our activities were focused on both our new assets in the Bakken and the Marcellus in the U.S., as well as targeting the Cardium and the Ratcliffe on our foundation assets in Canada. Our results are on track with expectations; however, like many other oil and gas producers have advised, winter weather did create challenges throughout our operating areas during the quarter.

Our production volumes came in within our guidance range for the quarter at 75,483 BOE per day, and about 44% of our total volumes were attributed to crude oil and natural gas liquids, which we continue to expect to see grow to 50% as we execute our 2011 and 2012 development programs.

We spent just over CAD174 million on our assets, with over half of our spending on oil projects. We expect to continue spending a greater percentage of our capital budget on oil projects this year, given the strength of crude oil prices.

With weak natural gas prices, we continue to proceed cautiously with investment in natural gas, and will focus on plays with the best economics and those where we believe there is opportunity for future value creation.

80% of our CapEx was invested in three key plays -- the Bakken, Marcellus, and waterfloods. And I'm pleased to say that the drilling results in all areas are positive. We drilled 26 net wells with five wells brought onstream.

I'm also pleased to say that our drilling results continue to exceed our expectations in North Dakota. Since acquiring our interest in Fort Berthold and becoming an operator a year ago, production has grown from approximately 1,100 barrels per day to over 4,500 barrels per day, primarily as the result of our successful drilling activities. This asset will be a key driver for our growth over the next few years, as we expect to grow production to over 20,000 barrel equivalents per day.

We continue to be active in the Marcellus, primarily on our joint-venture lands where drilling was focused on development and lease retention. We currently have nine rigs operating in the play with our partners, plus one Enerplus-operated rig. Drilling results continued to be positive with production rates exceeding expectations, and production volumes for the first quarter were slightly ahead of expectations despite fewer well completions and tie-ins. The Marcellus will provide significant growth potential for us over the next four years in the order of 150 million cubic feet per day.

We continue to advance our work on our IOR and EUR projects at our Giltedge and Medicine Hat waterflood properties during the quarter. It's still very early in the process. But with the significant amount of unrecovered oil at these properties, we believe there is meaningful opportunity to grow production and reserves. We've also had good success at our waterflood properties where we've been drilling wells into the Cardium and Ratcliffe, and Ian will speak more to this in a moment.

Our operating costs were better than expected for the quarter at CAD8.40 per BOE compared to our guidance of CAD.920 per BOE, likely due to the sale of higher-cost properties in the latter part of 2010 and a mark-to-market gain on electricity hedges in the quarter.

We generated funds flow of CAD161 million during the quarter, and approximately 60% was paid out to shareholders through our monthly dividend of CAD0.18 per share.

When we add our capital spending to the dividends paid in the quarter, our adjusted payout ratio was 169%. Again, this was in line with our expectations. We had previously advised that our adjusted payout ratio would be increasing in 2011 as we invest in earlier-stage assets where there is a longer lead time to production and free cash flow.

And we've also said that as our growth plays deliver results, we expect our payout ratio with decline in 2012 and beyond. In the interim, we plan to use our balance sheet to support our capital investment plan.

Also, we said we'd look to monetize minor non-cash generating assets, and in the quarter we sold approximately CAD60 million of such assets, which also helped to fund our investment activities.

At the end of the quarter, our balance sheet continued to be strong with a debt to trailing funds flow ratio of 1.2 times.

Now our operating guidance for 2011 remains fundamentally unchanged, although we did bump our general administration expense marginally in association with reporting requirements under our adoption of International Financial Reporting Standards. And if you're up to it, there is a healthy note 15 to our financials that you can read that speaks to the transition to IFRS reporting.

We continue to expect annual average production will range between 78,000 BOE to 80,000 BOE per day, on average, and will grow throughout the year to exit in the range of 80,000 BOE to 84,000 BOE per day. Our forecast for capital spending is also unchanged at CAD650 million.

Wet weather has impacted our ability to move rigs and tie-in wells early in the second quarter. However, we expect to ramp up activity in the second half of the year.

In April, we announced a number of executive changes at Enerplus which I believe will help enhance the execution of our business strategies. Ian Dundas, our Executive Vice President, has taken on the added responsibilities of Chief Operating Officer. So I'll now turn the call over to Ian to provide further details on our operations during the quarter.

Thanks, Gord. Good morning.

I'll start with our Bakken operations in our western U.S. business unit. We got off to a slightly slower start in the quarter due to severe winter weather and high industry activity. This resulted in modestly lower capital spending than we had planned and production volumes remaining relatively flat from year-end, averaging approximately 13,600 barrels of equivalent over the quarter.

And although we're still dealing with the weather issues, we've made meaningful progress over the quarter securing arrangements for additional rigs, frack spreads, and trucking services, as well as building an inventory of drilling permits, all of which will be critical as we execute a large capital program in a very heated basin.

To put this in context for you, in Fort Berthold in the first quarter, we ran two rigs, drilling four wells and completing two. Now once things dry out, we believe we will be in a position to drill and complete up to four wells per month, which is effectively our target level of activity for the remainder of the year.

Notwithstanding the slower pace of activity in the first quarter, we continued to be pleased with well performance. Our two completions in the quarter, one long Bakken and one short Bakken well, had initial 30-day production rates of over 1,100 barrels a day and just under 900 barrels a day, respectively. This most recent short well is our best early-time performance to date for a short lateral.

Since building this position last year, our long wells have outperformed our initial estimates by over 30% and our short laterals, more than 45%. With these strong volumes and current oil prices, we expect long lateral wells to achieve payout in under a year and shorts in about 1.5 years.

Subsequent to the quarter, we also completed our first Three Forks test with first-week average production of around 600 barrels a day. Although we are dealing with very early time data here, this is consistent with our expectations.

Looking forward, we plan to move to two more rigs in Fort Berthold this quarter and expect to run with a minimum of four rigs for the remainder of the year. Infrastructure and gathering system buildout continues to proceed, and by mid-summer we expect to have a majority of our wells tied in to a central gathering facility, which will reduce our reliance on trucking in the region and enhance margins through gas and NGL sales.

With our expanded capacity, we expect to drill and complete approximately 28 horizontal wells at Fort Berthold during the remainder of the year. Combined with the seven-well program in Montana, we are on track to spend approximately CAD250 million on oil properties in North Dakota and Montana this year. The Fort Berthold program is strategically designed around maximizing 1,280-acre spacing, testing both Bakken and Three Forks.

And finally, and perhaps most critically, understanding the optimal well spacing.

Briefly, on the cost side, although there are clearly cost pressures in the region, at this point we still expect our long laterals to come in at about CAD8.5 million and shorts at CAD6 million.

Turning to our Canadian waterflood projects, production in our waterflood project portfolio was on track with our expectations for the first quarter, averaging just over 13,000 barrels of equivalent a day. We continued with our development program, spending approximately CAD28 million on drilling, completions, and facilities. We drilled 8.5 net wells, primarily targeting light oil in the Cardium and the Ratcliffe.

Turning to some specific project details, we kicked off a six-well program targeting the Cardium in Pembina and completed three of the wells during the quarter. Again, although we're dealing with some very early-time data here, early indications are quite positive.

In Saskatchewan, we drilled and completed three horizontal wells into the Ratcliffe trend at our Freda Lake project. Initial 30-day production rates are exceeding expectations -- I'll actually give you some real numbers here, ranging from about 200 barrels to 300 barrels a day. In our current plans, we're looking to drill an additional 11 Ratcliffe wells this year. In total, we're planning for a few dozen more wells throughout these fields this year, although given some of our success to date, we are evaluating allocating additional capital to these projects.

Briefly, on our EOR project at Giltedge, we began injecting polymer on schedule in April, and the plan calls for us to see a production response sometime in the fourth quarter.

Work is also underway at our second polymer project at Medicine Hat with a planned start-up for early next year.

Turning to gas, I'll start in the Marcellus. The story for the Marcellus continues to be improving well performance, but the pace of completions and well hookups slightly behind expectations. Production in the Marcellus averaged over 21 million cubic feet a day, up from 2010 exit volumes of just over 17 million a day.

We participated in drilling 21 gross wells, with five net to our interest. Most of this activity occurred in northeast Pennsylvania, where our performance continues to exceed our initial expectations. Well performance has been particularly good in Lycoming and Susquehanna counties.

As I indicated earlier, completion and tie-in activities were slower than we anticipated, with only one net well -- net nonoperated well completed due to winter conditions and continued delays primarily on the pipeline side. We currently have 54 gross wells on production; 57 gross wells that are either partially drilled, waiting on completion, or in the process of completion; and a further 22 gross wells waiting to be tied-in.

On the operated side, we're planning a modest delineation program in 2011 that will focus on our acreage in central PA and Preston County, West Virginia. We successfully completed our first operated well in Clinton County. It's a 5,300-foot lateral. It was an eight-stage completion. Had a peak test rate of just under 4 million a day. With the lack of pipeline infrastructure in this area, we do not expect to tie in this well until early next year.

We also began drilling the first of two wells in Centre County in Pennsylvania and will follow these wells with a three-well program in the southern part of Preston County in West Virginia in the latter part of the year.

Just briefly on our other natural gas projects, activities on our Canadian natural gas portfolio were mainly associated with nonoperated drilling in the liquids-rich Deep Basin area, where we hold over 80,000 net acres of operated land, prospective for either the Montney or the Stacked Mannville.

We participated in a total of eight gross nonoperated wells, 2.4 net, and also finished our operated two-well program at Tommy Lakes. While results from our nonoperated partners have been quite positive, and given the positive drilling results to date, we expect further drilling activity by our partners in this region.

I'll now turn it back to Gord for his closing thoughts.

Thanks, Ian.

So ladies and gentlemen, the work we've done to transition our portfolio has, we believe, positioned Enerplus for success. We built a resource base that provides our investors with a multiyear development inventory of light oil and low-cost gas opportunities. We've kept our balance sheet strong, insuring that we can support our spending plans going forward. Our leadership team, together with the technical and commercial expertise of our staff, are focused on delivering our targets.

So with that, I'll turn the call back over to the operator and take any questions that the audience may have.

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

Just a question on your Fort Berthold drilling program. It sounds like you're getting better economics on your long laterals, just in terms of your payouts. So does that change the way -- is that going to affect the way you might develop that play?

You know, Gord, I think in our previous disclosures and discussions, we've indicated that our preference is to drill the long laterals, and in fact, I think we indicated about 75% that's expected to be drilled on a long lateral basis. And that will be, obviously, contingent on contiguous landholdings, as well as the rock properties and the geology of the play.

But that's really the direction that we're taking, for those reasons. The economics are better on the longs.

Okay, and then, in terms of CapEx and overall spending, where do you target your debt to capital ratio? Where would you sort of maybe -- what sort of maximum rate would you like to see that go to?

I think what we've said is that we see our debt to cash flow ratio rising towards the two times into the 2011-2012 timeframe, and then easing off after that.

So when we look at it two times, that's probably about as far as we want to go. Now we've also indicated that we're looking, and as I mentioned, we sold CAD60 million worth of non-core noncash-flowing properties here in the first quarter this year. We have some assets in our portfolio that we would also look to monetize.

And the other thing is that we've indicated that we would not be averse to looking -- to selling down a portion of our principally nonoperated interests in the Marcellus because there is no question that we have a significant inventory of gas potential within our Marcellus holdings.

(Operator Instructions). Roger Serin, TD Securities.

I've got a couple of questions. And I got on late on the call, so I apologize if you've answered them. What did you expect in terms of polymer flood response? It looks like a two- to three-quarter lag from injection, but what sort of scale in terms of production rates are you thinking of?

We've got Ray Daniels in the room, who was recently promoted to Senior Vice President of Canadian operations. So, Ray, why don't you take a shot at the question? Did you catch it?

Yes. At this time, it's not clear what kind of incremental response we're going to get from the EUR from this initial pilot project that we're working on just now. We have modeled it. I don't know what the numbers are off the top of my head. But we expect to see some response late October into November, sometime then.

Your second question, Roger?

Yes, Sleeping Giant. A while ago, you had done some drilling and then backed off, and now I see you're drilling some more wells. Are you changing the approach? Is this given some of the completion techniques you're seeing on some of your Fort Berthold? I'm just wondering what has triggered that. I know you were doing a lot of refracking and now you're drilling some wells.

Go ahead, Ian.

Roger, it's Ian. No, I don't think we've backed off. That field is at a relatively mature stage of development. And the guys have been doing a lot of work looking for opportunities where, maybe on an individual section basis, we saw some lower recovery factors and have sort of attacked it on that basis.

We actually brought a couple of rigs in there early part of the year. We've got a seven-well program targeted for this year, effectively going through certainly on a section-by-section basis, looking for these opportunities. That's really going to be the game plan here for the next year or two, looking for, I'll say, almost optimization opportunities.

And then, the open question is going to be EUR and whether there is -- or sorry, some form of secondary opportunity that sits there, and we're working through plans to see if we can understand that a little more this year.

(Operator Instructions). Cristina Lopez, Macquarie Securities.

Just a quick question on the CapEx program. You made mention that there are cost pressures in North Dakota, and we're seeing that in western Canada as well. Do you expect to see a lot more of that cost pressure going into 2012? And do you still expect that you can stay kind of within a CapEx budget near CAD650 million this year and then something similar for a CapEx spend for 2012?

You know, I think certainly we acknowledge that this is a high-activity basin, and we all recognize that the access to services is challenged. Right now, we feel that we're comfortable with the CAD650 million spend going into 2012 as well. We'll have to evaluate.

What we're really encouraged about, obviously, is the results coming out of these wells in support of the economics, even if there is some increased cost pressures there.

And given the recent -- sorry, this -- just had another question. Given the recent sale of Chief's assets in the Marcellus, are you expecting the new partner to actually ramp up the activity levels there or expect to keep it relatively the same as had been anticipated?

You know, this is obviously just a recent announcement, and so we have not had any discussions, if you will, with Chevron relative to what their plans would be. We have some, I'll say, protection on levels of activity under our existing agreement, so we'll just have to wait and see what Chevron's thinking are as they work to complete the transaction with Chief and Tug Hill.

Perfect. Thanks, guys.

There are no further questions at this time. I'll turn the call back over to the presenters.

Thanks, everyone, for joining us this morning. We appreciate you taking the time out of your day, and with that, we'll conclude.

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