Enerplus Corp (ERF) 2011 Q3 法說會逐字稿

Good morning. My name its Sarah and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation Third 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).

I would now like to turn the call over to Ms. Jo-Anne Caza, Vice President of Corporate and Investor Relations. Ms. Caza, you may begin.

Thank you, Operator, and good morning everyone. I would like to welcome you to Enerplus' 2011 third quarter conference call. Gordon Kerr, our President and CEO, will be summarizing the results of the third quarter. And Ian Dundas, Executive Vice President and Chief Operating Officer, will provide a more detailed update on our operations and our plans as we head into the back end the year.

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, our President of US operations; Eric Le Dain, 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 our news release issued this morning, and included within our MD&A and financial statements, filed on SEDAR and EDGAR, and available on our website at enterplus.com.

Our financial statements were also prepared in accordance with International Financial Reporting Standards, including comparative figures pertaining to our 2010 results. All financial figures referenced during this 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. And we'll also have a replay of this call available later today on our website. Over to you, Gord.

Well, thanks, Jo-Anne. And good morning, everyone, and thanks for joining us. Let me start by saying that despite things being slightly behind schedule in our operations, we are seeing some very good well results in anumber of areas in our portfolio and our base production is performing well. Ian will share some more details on that in a moment.

Most of our spending during the quarter was in our Bakken, Oil Waterfloods and Marcellus [Satsus]. And in total, we spent just over CAD200 million, which included the drilling of 35 net wells during the quarter. In total, we brought 12 net wells on-stream throughout the quarter. And year-to-date, we've brought 48 net wells on-stream.

Also during the quarter, we continued to be impacted by the weather-related delays that we experienced in the first half of this year. Production build from our drilling, completion and on-stream plants has been at a slower pace than we anticipated, particularly in North Dakota. Access to our sites at Fort Berthold were affected by longer repair times for a state highway,the back up in scheduling of frac services for our operations and a slower pace for the construction on the first phase of gathering system in the project area.

Our production averaged 73,245 BOE per day during the quarter,just 3% lower than anticipated, because of delays in our operations execution, and also reflecting the sale of a portion of our Marcellus interest at the end of June, which included about 1,100 BOE per day of production. With the slower than expected build-in production throughout the first nine months of the year, we expect our full year production will average closer to 76,000 BOE per day in 2011.

Now our operating costs have also been impacted by the wet weather, both in Canada and the US. Our Op costs on a per BOE basis increased by more than 10% over the second quarter to CAD10.92/BOE. As the first phase of our gathering system in Fort Berthold as been built out, the wet weather issues are behind us. And as we build production, we expect our costs will moderate in the balance the year. We have adjusted our full year operating guidance to CAD9.60/BOE, which is up from our original guidance of CAD9.20/BOE.

Our funds flow was CAD123 million for the quarter or CAD0.68 per share. Lower than expected, primarily due to a tax expense of CAD32 million related to our Marcellus sale and an adjustment to prior year tax recovery estimates in the US. If we excluded the tax impact, our funds flow would have been CAD0.86 per share. And I think it's also important to remind everyone that while the tax impact associated with the Marcellus sale affect our reported funds flow, the CAD272 million reported gain on the sale is not included in funds flow.

We are using our balance sheet to support our capital spending, as we said we would. We have maintained our financial strength as we've transitioned our portfolio over the past few years. And now we're using it to support our growth plans. Our payout ratio, based on a reported funds flow for the quarter, was 79%. And when we include our capital spending, our adjusted payout ratio for the quarter was 245%.

We do continue to be in a strong financial position, with a debt to funds flow ratio of 1.3 times at the end of the third quarter.

We also continue to add to our new growth prospects. We've added another 38,000 net acres of land in the Duvernay play in the Willesden Green area of Alberta. And now hold approximately one hundred sections of under developed land in the play. We plan to drill our first test well in 2012, targeting liquids-rich natural gas, and will be closely watching results from others in the area.

We've also added to our merging oil play portfolio and are now holding approximately 25,000 net acres in two key prospects, again in Alberta. Year-to-date, we spent approximately CAD100 million adding over 110,000 net acres to our strategic land inventory.

We're in the midst of a very busy fourth quarter. We plan to drill over 40 net wells across our portfolio and bring approximately 41 net wells on-stream. We believe this activity will keep us on track to meet our exit production guidance of the range of 81,000 to 84,000 BOEs per day.

So with that, let me turn it over to Ian to get into more detail on our operations and capital spending activities.

Thanks, Gord. Morning, everyone. As Gord mentioned, we had a slower start to the quarter, in terms of our production build, than we had anticipated. It really stemmed from weather issues in the first half of the year that impacted timing of some activity in Q3, as well as our Q3 results. As Gord indicated, the key issues largely related to the pace of completion and tie-in activity, as well as the completion of third-party infrastructure at Fort Berthold.

Despite the timing issues, we have been quite pleased with well results in some key areas. I will give you a few highlights. In the Bakken, our first successful Three Forks completion has had a 30 day [AP] of over 800 barrels a day. It's now produced about 40,000 barrels of oil in just under two months.

In the Marcellus, we have just completed a production test on our first operated well in Clinton County, Pennsylvania, which tested at just over eight million a day.

In the Deep Basin, we are now drilling in the Ansell Minehead area and have just brought on our first well from this program to Bluesky producer -- producing at 4.2 million a day of gas, with an expected liquids yield about 125 barrels a day at current rates.

Finally, we are also seeing some early success in our Canadian oil portfolio. Our EOR project at Giltedge its showing production response. And we have had encouraging drilling results in the Viking at Gleneath.

And now I will take you into a little more detail in the plays. So starting with the Bakken. Production from our Bakken portfolio was up about 900 barrels a day during the third quarter. Clearly, this was the project that was most impacted by weather,as major highway repair work and delays in construction of the gathering system at Fort Berthold continued into the quarter. The impact was not only the timing of well completions but also increased operating costs, as a result of increased trucking and foot handling charges. Notwithstanding that, we did drill ten wells at Fort Berthold during the quarter, seven Bakken wells and three Three Forks wells. We also brought on six wells throughout the quarter in Montana and North Dakota.

As I indicated, we're particularly pleased with our initial Three Forks test. As you may recall, we believe the Three Forks is relatively uniform over our entire leasehold. And this early time data is quite encouraging, in terms of establishing well productivity. For the purposes of our economics, we are currently modeling EORs for our Three Forks well at approximately 70% of a Bakken producer in our development area. And thus far, performance is on track with those expectations.

We have a number of additional Three Forks wells that we expect to complete in the fourth quarter, and anticipate providing more information at year end. Although we haven't specifically quantified the upside potential to our resource estimates associated with the Three Forks, it's fair to say that this initial well result is directionally positive.

Since quarter end, the first phase of our third party oil and gas gathering system has also been completed and we have commenced gas sales from 14 of our producing wells. We expect margin pickup from gas and NGL sales, as well as a reduction in trucking costs. We also believe the completion of the pipeline and gathering system will improve production reliability, particularly as we move into the winter season.

Although we are seeing some cost pressure within the Basin, we feel that the reduced drilling times due to the use of walking rigs and multi-well pads provides us with greater confidence in achieving our expected well results, which remain consistent with previous disclosure. To refresh your memory, we expect our long horizontal wells should average about 8.7 million a day and short horizontal wells around 6.7 million a day, which would include tie-in costs.

A little more on the cost of mitigation side. We're also successful in drilling our first saltwater disposal well late in the third quarter. To give you a since of the economics here -- we're estimating our ongoing water disposal costs to be in the range of CAD3 to CAD5 a barrel, although they were much higher than that during the past winter, averaging two to three times higher, which was one of key drivers behind some of the weather-related cost escalation we experienced. This well is currently taking about 4,000 barrels of water a day, which obviously is a meaningful cash item for us. We have plans to drill a second saltwater disposal well. And these two wells should be able to handle all of our disposal needs, as well as providing a third-party revenue stream. We have been running with four rigs in the play for about the past four months, which has set us up to bring on 13 wells in the fourth quarter;nine Bakken shorts and four Three Forks shorts. We expect six of these wells to be tied into the gathering system that was completed in October.

A final comment on Fort Berthold; we are seeing some production optimization opportunities, which we expect will improve up time reliability. As you may know, we are dealing with a highly over-pressured area here, which is one of the factors that is contributing to the superior well performance we are seeing. To frame this for you, we are seeing some wells flow without any lift system for over a year. That's well beyond our initial expectations and is quite supportive of long-term well performance. That said, it has created some start-up challenges as we work through the appropriate lift system to use. Currently, we're in the process of testing some electric submersible pumps, which have worked quite well for us in other applications.

Overall, this optimization and tie-in activity is expected to add between 5,000 and 8,000 barrels of oil equivalent of production in our western operations by the end of December.

Turning to Waterfloods. Our Oil Waterflood properties have been performing well throughout the year and production is up slightly from the second quarter. The majority of the work in the third quarter was in Saskatchewan, targeting the Ratcliffe and Viking formations. The at Freda Lake, we drilled four net Ratcliffe wells and are seeing production results consistent with our initial expectations, averaging approximately 140 barrels of oil equivalent per day per well over the first 30 days. We have upgraded our facilities and batteries in this area throughout the past year to accommodate future growth potential. And we would anticipate drilling another four wells into the Ratcliffe before the end the year, continuing with a program into 2012.

We also drilled five wells targeting the Viking at Gleneath during the quarter. It's early time data, but well results are positive, with initial flow rates ranging between 180 and 470 barrels a day on four of the first five wells. Our 30 day -- our expectations for 30 day rates from these wells are 40 barrels a day. At this point, we would suggest we expect to exceed these levels. These wells are currently being tied in and with continued performance, we'll setup more drilling opportunities next year.

As we mentioned earlier this year, we started our first polymer flood project on a portion of our Giltedge property near Wainwright, Alberta. We started injecting polymer in late April and are now seeing production response, which is earlier than we had initially expected. Overall, field production is up around 15% and water cuts have improved from both the polymer injection, as well as other optimization work that's been done on the field. We continue to monitor production and water cuts throughout the next few months, and then we will be making a determination as to what expansion of the program could look like.

We're also getting ready to start a second polymer project at Medicine Hat. This is another mature field with over 300 million barrels of original oil in place, with less than 10% of oil recovered to date. Estimated incremental recovery from a polymer project is in the range of 5% to 10%. So the success of these programs could increase production in reserves quite meaningfully in these areas.

Let's turn to natural gas. On the natural gas front, we continue to see a decline in our Canadian conventional gas production, particularly the Shallow Gas, as we have shifted capital from this region to Canadian projects where we expect liquids contribution. And we have continued to develop our Marcellus projects.

Production from Marcellus increased from 12 million a day after the sale of a portion of our interests at the end of the second quarter, to 15 million cubic feet a day of gas during the quarter. Our partners continue to be active in the northeastern region of Pennsylvania, drilling 36 gross wells, 4.5 net to us. Only 1.2 net wells that were brought on-stream during the quarter and the inventory of wells waiting on please and/or tie-in is growing -- now it's at about 15.5 net wells. We expect to tie-in another 24 gross or 2.5 net wells by year end, taking production from 19 million a day currently to between 25 million and 33 million a day by the end of the year.

EXCO continues to run a three rig development program focused on multi-well pad drilling, exclusively in Lycoming County. Both Chief and Chesapeake are also active, with three and six rigs running, respectively, in northeast PA. Partner wells are averaging 4,000 to 5,000 [sea] lengths with up to 15 frac stages and are trending longer where acreage configuration allows.

Our partners are also adding an extra casing stream for added water protection. This has resulted in costs from our non development wells of about CAD6.5 million toto CAD8 million, which is higher than we were seeing earlier in the year. With more frac leads coming into the basin, there could be some reduction of frac costs. But overall, it continues to be very busy region, with over 165 horizontal rigs working in the basin.

We continued with our delineation activity on our operated leases and drilled our first of two wells in West Virginia during the quarter. Drilling on our second well in West Virginia has just wrapped up. And we will work to complete both these wells over the coming weeks, with tie-in to occur in 2012.

As I indicated with my opening comments, our first operated well in Clinton County, Pennsylvania has shown very positive test data, with 24 hour peak rate of just over eight million a day. This is well above our initial expectations. We also have seen some encouraging results recently from competitor activity adjacent to our land in Pennsylvania. We will be monitoring these results closely in order to help assess the potential we have on our operating position in Clinton County.

Turning to the Deep Basin in Canada. Canadian natural gas spending has been focused almost exclusively on plays with associated liquids, as I said earlier. We spent roughly CAD20 million in our deep tight gas portfolio during the third quarter, on both operated and non-operated activities.

On the operated side, we are running a one rig program, and as I indicated, have just brought on a Bluesky producer -- just over four million a day with a decent liquids cut. We also just finished drilling a Wilrich horizontal, which we will complete this month and expect to tie-in this year. And finally, we are currently testing a vertical stack Mannville well where we see Gething and Wilrich potential. Overall, I would say we are quite encouraged by our progress in the Deep Basin, and see significant opportunity in front of us.

So wrapping up with a summary of the fourth quarter and how we see the outlook. During the fourth quarter, we expect to see a significant increase in production as a result of completion and tie-in activities,with the majority of the production build coming from the US, specifically Fort Berthold, and to a lesser extent, the Marcellus. To frame this for you; we plan to bring on an additional 41 net wells during the quarter, adding 9,000 to 12,000 BOE day of new production. Approximately 85% of that would be oil weighted. And this puts us in a strong position to achieve our exit guidance range of between 81,000 and 84,000 BOE a day.

So with that, I will turn it back to Gord.

Thank you, Ian. For those that have followed Enerplus over the years, I think you have seen a significant transformation in our asset base. Over the past few years, we've sold somewhere in the order of about CAD2 billion worth of assets, and we have exited the oil sands and select other non-core assets. At the same time, we have added over CAD1.5 billion of new assets into the portfolio. Assets that we believe have solid future growth prospects to have production reserves and cash flow, organically.

In total now, we hold over 380,000 net acres of strategic land, in both Canada and the US,the majority of which is focused on oil and liquids-rich natural gas. This land position will support our future growth plans and provide incremental reserves production and cash flow growth in the coming years.

We have preserved our balance sheet. And as I said earlier, we're using it to achieve our growth plans in the near term. We also have a great team of people that are working hard to execute on our plans and to grow our Business. And we believe we're on the right track to deliver on our strategy.

So with that, I will just turn the call back over to the Operator for questions from the audience.

(Operator Instructions). Our first question comes from the line of Gordon Tait from BMO Capital Markets. Your line is open.

Morning. Just a question on your operating costs. As you noted, they come in higher than expected. I presume some of that was because of the floods and some of the production interruptions. But is there also an underlying trend? Are you expecting that to go forward -- that kind of a pressure on Op costs?

Well, Gordon, some areas in particular, we mentioned Fort Berthold, we've undertaken tie-ins that we believe will reduce our costs in those areas. Overall in our industry, and I don't think we're any different than others, we're seeing increased pressure on cost. So there is an element of cost inflation there. I think what will be key as we expand our operations in key project areas like Fort Berthold, we would expect to see greater economies of scale there. But the reality is there is inflation that is happening industry-wide. So we're working to mitigate those cost pressures through how we handle our operations in these key areas and look for those reductions that will come through things like tying-in to a main gathering system.

We should maybe think of them as being a little higher than what it being this year, I suppose, for next year?

Well, we'll be coming out with our guidance later this year. But I think, generally, as I said, the industry has seen those cost pressure increases there. And we certainly upped our guidance here for the latter part of the year. So I don't really have anything further. Ian, you want to make any further comment?

No. The only other thing to add to Gord, is as we work through guidance and cap allocation, there are areas that are not getting capital. Gas price being what they are, dry gas projects are getting effectively no capital in our world. And that has pressure on LOE in some areas where we're just not reinvesting. But overall, I think Gord hit it pretty well.

Okay. And then in the Deep Basin, you've got a pretty good footprint from. Are you planning to delineate the Duvernay process yourself? Are you partnering with others -- are you going to let others do it? What's your plan for that element?

Well, currently, as we said, we are planning a delineation well in the first quarter. And then we're certainly in a position to watch what other players in the area are doing. And I think there's some wells that are being drilled currently and they will come off, call it confidential status, here over the course of the next year. So we'll be doing some of it our self. We have no -- in the lines that we have currently, we don't have a partner involved with us at this particular point in time. So like I say, we built a position there that points to somewhere in the order of about 65,000 acres of land that we think is great position to have right now.

Okay. And then just lastly, if you like what you see with these polymer floods, with these pilots -- obviously, those can be pretty big budgets; would that be something that you would decide on in the budget prior to the year end? Or is it something you would move forward with next year? Do you still need to see more data?

Well, we have two areas that we're currently working on. We mentioned the polymer project that's under way currently at Giltedge. And then in the Medicine Hat Glauc C area, we're also positioning to advance in a polymer project there already. We've already ordered some of the lead equipment and will be scheduling it in here over the course -- the balance of this year and into 2012.

So we should see something in there -- in the budget at the end of this year for your polymer floods?

That's a safe assumption.

Okay. Thanks.

Gordon, I just had one more thing on the partner question, relative to delineation. We've got the Duvernay we're planning on testing, the Montney, there's some delineation going on in the operated Marcellus, a few other things we're looking at as well in the oil side. When you look at all those projects, we've got a pretty high working interest in all of them. I would say there's possibilities we could bring partner in to help mitigate risk and advance our plans. I would say we don't have any at this red hot minute. The Duvernay is a really good example, where we're 100% interest and it's a very large contiguous land position. I would say we're preparing to do it ourselves. But it's not only just offset activity. There's a possibility we could bring someone in at the right time for that. So I would say, at this moment, we have some choices in front of us.

Okay. Thanks.

Next question comes from the line of Roger Serin from TD Securities. Your line is open.

Thanks. Good morning, everybody.

Morning, Roger.

Just a couple of questions. So on the Bakken growth, net 5,000 to 8,000 barrels a day, is that a net number? So is that incremental from Q3 levels?

Yes.

Okay. And on the Marcellus, am I reading this correct? If you go from Q3 average of 15 million a day, current 19 million, to the low end, which is 25 million a day, that's 10 million a day, and you're adding 2.3 net well tie-ins for the quarter?

Correct.

And you're adding on the Bakken -- I think saw it's 13 net wells in the quarter?

That's correct, as well.

Yes.

Look at that. I got through the whole press release and read it all. Thanks very much.

You get a gold star, Roger.

You started out doing [a less] test, but you passed it.

I'm good. That's it. Thanks.

Okay.

Oh, actually one last question. Duvernay, is that going to be a vertical test or a horizontal test?

Haven't decided yet.

Okay.

If you look at what's happened out there, there are a series of guys who have -- well you have seen both approaches. And you have seen interesting consequences from those approaches. I think we're the beneficiary -- we'll be the beneficiary of seeing some drilling success and drilling learnings that we can take from others. And I think that's going to give us more choices . But yes, it's a real-time question we're working through.

Okay. Great. Thanks very much.

(Operator Instructions). And your next question comes from the line of Kevin Lo from FirstEnergy. Your line is open.

Hey, guys. Just a quick housekeeping question. In your MD&A, you were saying you added 38,000 acres of land targeting Duvernay and in the Willesden Green area. And in the CapEx section, it says 13,000 acres. I'm just trying to reconcile that and how that works, in the interest of math. Or am I just not reading it correctly?

I don't remember exactly what was in there, Kevin. But I think the -- in aggregate -- I think the real key here is that, in aggregate, we've got 65,000 acres targeted for the Duvernay.

We would have added a little bit of extra acreage after the quarter end. So the MD&A will deal specifically until September 30th. In the front end of our President's message and in the news release, we'll be talking about our acreage position to date.

Okay. So if I was to do simple math, 38,000 is what you have added since second quarter, 13,000 is what you had in Q2, so you added 20,000 subsequent to Q3, then? Would that be correct?

That sounds about right.

Yes.

Great. And would the purchase metrics be similar, in terms of dollars [per ha], be similar in latter acreage than you would have paid in Q2? Or Q3, sorry.

Are you trying to get to our competitive pricing on that question, Kevin? I don't think that's --

We'll take that one offline then.

Well, sure.

All right. Thanks. That's all for me.

And there are no further questions in queue.

Well, Operator, on that note, then, I will just thank everybody again for joining us on the call this morning and we'll conclude. Thank you.

And this concludes today's conference call. You may now disconnect.