Enerplus Corp (ERF) 2014 Q3 法說會逐字稿

Good morning. My name is Mike and I will be your conference operator today. At this time I would like to welcome everyone to the Enerplus Corporation 2014 third-quarter results conference call.

(Operator Instructions)

I will now turn the call over to Jo-Anne Caza, Vice President, Corporate and Investor Relations. You may begin your conference.

Thank you, Operator, and good morning, everyone. Thanks for calling in.

Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our third-quarter results, which we released this morning. In addition, Ray Daniels, Senior Vice President of Operations, will also give some additional detail on our capital spending and operational performance in the quarter. Eric Le Dain, Senior Vice President of Corporate Development, Commercial, will be giving some color on our marketing and hedging activity and we also have Rob Waters, Senior Vice President and Chief Financial Officer, on the call with us today.

Our financials have been prepared in accordance with United States Generally Accepted Accounting Principles. All discussions of production volumes are on an gross Company working interest basis and all financial figures are in Canadian dollars, unless otherwise specified. Conversions of natural gas to barrels of oil equivalent are done on a six-to-one energy equivalent conversion ratio, which does not represent the current value equivalent.

The information we're discussing today contains forward-looking information. Listeners are asked to review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be found at the end of our news release issued this morning, and included within our MD&A financial statements filed on SEDAR and EDGAR, and available on our website at www.enerplus.com.

Following our discussion, we'll open up the phone lines and answer questions you may have and we'll also have a replay of this call available later today on our website. With that, I'll turn the call over to Ian.

Good morning, everyone. Thanks for joining us today.

Our results release this morning demonstrate another quarter of consistent operational performance, execution of our non-core divestment strategy and it highlights our strong financial position. Daily production averaged 104,000 BOE a day, essentially unchanged from the second quarter, but nearly a 20% increase from the same period in 2013. This is despite the curtailment of 3,000 to 4,000 BOE a day of natural gas from the Marcellus, caused by low natural gas prices and pipeline maintenance in the third quarter.

Crude oil and natural gas liquids volumes were up again this quarter, averaging 44,200 barrels per day. We continue to see strong performance from our Bakken/Three Forks activity in North Dakota. Natural gas volumes were flat quarter over quarter, at approximately 360 million a day despite the curtailments. Although commodity prices weakened in the third quarter, funds flow from operations was maintained quarter over quarter at CAD213 million, or CAD1.04 per share. A drop in our cash share-based compensation expense, along with our hedging program, helps to keep funds flow flat quarter over quarter.

We continue to advance on our non-core divestment program through two transactions, one that closed September 30 and the other which closed in early November. We've sold approximately 3,100 BOE per day of non-operated, primarily natural gas production. In total, we generated about CAD91 million in proceeds. As we mentioned last quarter, we are redeploying a portion of these proceeds. As a result, we're increasing our capital spending for 2013 modestly, by CAD30 million, to CAD830 million. We plan to accelerate some of our 2015 capital program into the fourth quarter of 2014 to advance activity in both the Wilrich and North Dakota.

Our investment activities have also served to improve the focus within our portfolio and further strengthened our balance sheet. We ended the quarter with debt to trailing 12-month funds flow ratio of 1.3 times. Operating costs increased in the quarter to CAD10.67 per BOE due to production curtailments on our lower operating cost Marcellus properties, along with seasonal well servicing repairs and maintenance. Curtailments will also have a modest impact on our annual operating cost guidance, which we are adjusting back to original estimate for 2014 of CAD10.25 per BOE.

Cash G&A costs were flat quarter over quarter and continued to be in line with our expectations. Cash equity-based compensation costs are expected to decrease from CAD0.60 per BOE to CAD0.45 per BOE due to the drop in our share price.

I'll now past the call over to Ray and Eric to provide some details on our operating activities and marketing. Ray?

Thanks, Ian.

As Ian mentioned, we delivered another solid quarter operationally, with continued growth in liquids production. We invested a total of CAD208 million in development capital in the third quarter, drilling just over 19.3 net wells and bringing 17.3 net wells on stream. The majority of our activity continued to be focused on oil projects, particularly in North Dakota, where we invested CAD96 million targeting both the Bakken and the Three Forks wells. We drilled 6.6 net wells with 5.6 net wells brought on stream. We achieved another quarter of record production at Fort Berthold at about 22,400 barrels of oil equivalent per day, up almost 1,600 barrels of oil equivalent per day from our high in the second quarter.

Taking a look at our activity year-to-date, we continue to see very strong well performance. We've drilled a total of 19 wells, with 13 wells brought on stream. Our operated drilling activity has been focused in the central and northern half of our acreage. Overall, we're seeing higher initial production rates and shallower declines. The 30-day initial production rates on our two-mile horizontal wells drilled in both the Bakken and Three Forks have averaged 1,725 barrels per day. This is about 20% above our highest type well.

We're also seeing shallower declines as our 90-day initial production rates have averaged over 1,300 barrels a day, which is also about 20% higher than our high-end type well. These wells have been completed using about 1,000 pounds per foot of white sand with about 40 frac stages. Well costs year to date have a trended about 5% higher than our budgets due to the larger fracs, but the production increase of 20% more than offset the additional cost and has driven further improvement in our capital efficiencies.

We have just fracked our largest pad to date and commenced the flow-back process of the five wells. This pad includes two Bakken wells, two Three Forks first bench wells and a second Three Forks second bench well. This will drive continued growth in the fourth-quarter. We currently have approximately eight operated wells awaiting completion.

While we are focused our drilling operations in the central and northern half of our acreage in 2014, we have participated in non-operated wells in the Southwest part of our lands. This includes a well offset in our operated lands that averaged over 1,800 barrels in the second month of its production. Very encouraging results given the acreage position we have in that area. In total, our US oil assets in North Dakota and Montana produced nearly 28,000 barrels of oil equivalent per day during the quarter.

In Canada, we're currently running two rigs in the Brooks area of Alberta, targeting the Lower Manville, another light crude oil play. We've drilled six wells to date and expect to have an additional eight to ten locations drilled by year-end. We have four wells currently on stream and early production performance has been positive. Based upon the results of our 2014 activity, we can see an additional 20-plus locations drilled in 2015.

Turning to the Marcellus, we continued with our drilling program in the quarter with 7.2 net wells drilled and 5.4 net wells brought on stream. We continue to see an improvement in capital efficiencies as a result of cost improvements and increased well productivity. The continued evolution of well completions has been a principal driver behind these improvements. Over the past few years, we have seen horizontal well lands increase from an average 4,500 feet to roughly 5,500 feet as the planned length.

Frac spacing, has also evolved starting at 400-feet spacing originally with testing down to 153-foot spacing. We've also been testing amount of sand with our fracs, going from 1,000 pounds per foot up to 4,000 pounds per foot. The net result of this has been a 30% increase in our IP 30 rates and a 30% increase in our IP 90 rates over the last two years. Using IP 90, capital efficiencies have improved by 45% through the same period.

Lower realized prices, along with some pipeline maintenance activity, resulted in 3,000 to 4,000 barrels of oil equivalent per day of production, on average, being curtailed in the quarter. Despite this, production from the Marcellus was essentially unchanged from the second quarter, averaging 187 million cubic feet a day.

As a result of the lower regional natural gas prices, the pace of activity is slowing down, with our primary partner moving from a four-rig program to a two-rig program by early in the new year. We expect capital spending in the fourth quarter to go lower than Q3 based on cost reductions, and this trend will continue more significantly in 2015 with the cost reduction and the slowing in activity.

Moving to the Duvernay, we drilled and completed two horizontal wells in the Willesden Green area this year. Our first horizontal well was completed in the first quarter, and brought on stream in late June, achieving a 30-day initial production rate of 535 barrels of oil equivalent per day of sales volumes. This included 2.24 million cubic feet of sales gas and 162 barrels of liquids, with over half of the liquids being condensate or C5-plus.

A second horizontal well was completed in the second quarter and was brought on stream in early October. We have now seen 30 days of continuous production, during which this will had an estimated 700 barrels of oil equivalent per day of sales volumes, made up of 1.75 million cubic feet per day of sales gas and 410 barrels per day of liquids, approximately 85% of which was condensate. Both wells have met our expectations on liquids content based upon our geotechnical analysis, with both in liquids rich areas.

Keeping in mind that these were very much exploratory wells, we are encouraged by the positive results we have achieved. The costs of these wells were higher than we expected particularly, on the completions, not unlike what others we've experienced in the steep overpressure play.

We see a number of opportunities to increase drilling and completion efficiencies going forward, particularly with multi-well pads. With our drilling to date, we will hold the core lands that we view as being most perspective for liquids rich natural gas in the Duvernay and we plan to continue to evaluate the performance of these two wells before determining our next steps.

Overall, we are very pleased with the results of our capital program to date in 2014. Based upon our revised guidance, we're poised to deliver above average per share production growth of 13% year over year.

I will now turn the call to Eric, who will give us an update on business differentials, our price outlook, and our hedging program.

Thank you, Ray.

The natural gas supply and demand imbalance in the Marcellus region, of course, continued in Q3. The growth in supply from the Marcellus and the Utica continues to overwhelm takeaway capacity. Scheduled pipeline maintenance during the quarter also added volatility to spot prices in the region, causing wide differentials to persist through the quarter. From September through December 2014, over 1.5 BCF a day of transport capacity is being added to the Marcellus region. While maybe only 350 million of it directly ties to Northeast Pennsylvania production, the remainder will help to relieve pressure on key marketing points, such as Dominion South.

Our realized price differential to NYMEX for our Marcellus production was minus $1.72 per MCF in the quarter. Year to date we are at minus $1.38 per MCF compared to NYMEX. During and subsequent to the quarter, we executed sales and precedent transport agreements for up to 80 million cubic feet a day, priced at Transco non-New York, that will fill in behind our existing sales agreement in the 2016 to 2018 timeframe as those agreements roll off. On the crude oil side, both the WTI and Brent oil prices dropped sharply in the third quarter and Canadian crude differentials weakened.

The net backs from rail to the East and Gulf Coast continue to define field prices in the Bakken. Unfortunately, the start up of the Pony Express pipeline to Cushing was delayed. However, it is currently in service and we expect it to help narrow differentials somewhat for the balance of the year. Our realized Bakken differentials in the field saw little change over the second quarter, averaging $14.72 per barrel below WTI. As you may recall, we had forecast a realized fuel differential for the year at $13 per barrel below WTI. Year to date, we are at $13.78 per barrel.

Despite the recent drop in crude oil prices, we continue to generate the majority of our funds flow from crude oil sales. For the remainder of 2014 we have approximately 64% of our forecasted net of royalties crude oil production swapped at prices just above $95. In the first half of 2015, we have swapped about 50% of our crude oil production net of royalties at an average price of $93.58 a barrel, and for the second half of 2015, we have swapped about 25% at $93.68 per barrel. We've also have added costless consumer color financial contracts for 2015 that will enable us to participate in the upside on a portion of these volumes, should prices rise above $94 per barrel.

On the natural gas side, we added to our hedge booked in the third quarter. Now have downside protection against NYMEX at around $4.18 per MCF on approximately 39% of our expected remaining 2014 net production after royalties, with an additional 10% hedged against ACCO at CAD4.25 per MCF. So in aggregate, that's 49% hedged to the end of 2014. In 2015, we have approximately 28% of our natural gas volume hedged net of royalties at $4.24 per MCF.

Now I'll turn the call to Ian.

Thanks, Eric.

Based upon our production results to date, we are increasing the low end of our production guidance. We now expect production to average between 102,000 and 104,000 BOE per day. We would expect to produce at the higher end of the range but we are maintaining a relatively wide range to account for the potential for more curtailment in the Marcellus then we currently anticipate. This also includes the sale of approximately 3,500 BOE a day of non-core production that we've discussed that has been completed to date in 2014.

In total, we raised over CAD200 million in proceeds from the sale of non-core assets this year. We also closed on our previously announced $200 million senior unsecured notes offering and used the proceeds to pay down our credit facility. We now have almost our entire CAD1 billion credit facility available to us.

As Eric mentioned, we are also very well hedged, not only for the fourth quarter 2014 but also going into 2015. With current volatility in the marketplace, we are assessing our plans for 2015. Directionally, we would expect modestly lower capital spending in 2015, with targeted production growth of 5% to 10% per share. However, we are still watching the market closely and expect to release our 2015 guidance later this year.

Our financial position is very strong and we have a conservative dividend policy. We will continue to invest with discipline in order to deliver affordable growth and a sustainable dividend going forward.

With that, I will turn the call over to the operator and we'll open it up your questions.

(Operator Instructions)

Greg Pardy, RBC Capital Markets.

Yes, thanks, good morning. Just three questions for you.

Maybe just to start, Ray, I've asked you this before. Is just in the Marcellus. Trying to get a feel for, without short-circuiting your 2015 guidance release, but moving down to a couple of rigs, how many wells right now would you have completed but not connected?

16, Greg.

16, okay.

16, 1-6.

1-6. Got it. Secondly, with respect to Fort Berthold, could you lay out just generally what your fourth quarter and first quarter programs are going to look like? Is the plan now in place to move another rig into the Bakken early next year?

Greg, maybe I'll just take it at a high level for a moment and go back to Ray relative to maybe some operational details there. At the highest level, when we think about 2015 versus 2014, because your getting close to a guidance conversation here, we've said we expect modestly lower spend there. So what are the things that are moving?

We are going from four rigs to two in the Marcellus, so that frees up additional capital for sure. Strategically, over the last several months we would have been talking about everything lining up to add a third rig in North Dakota, with the caveat being what's going to happen the price of oil? Well, the price of oil moved to the downside.

And so, directionally, I don't know that we are going to add a third rig anytime soon in North Dakota. We have some oil projects in Canada that we're looking at in Brooks that seem to be lining up pretty well. I guess that's a bit of an open question for us.

The non-operated activity in North Dakota is also continuing, as Ray talked about. That's actually accounted for a little bit of the additional spend in the back half of the year.

So when we look at all of that, I'd say it's less likely that there's a third rig coming anytime soon down there, with sort of a continued two rig program and maybe a little bit non-op that we were initially anticipating. Still going to drive good growth down there and when you look at some of these well results to-date, it's pretty encouraging in some of the productivity gains we're seeing. Ray, is there anything else you'd add there?

Not really. I mean, things, Greg, we'll know with the side wells it was just completed on the totals butterflies pad. We have no more completions this year to do. I mentioned that we'll get eight wells still to be completed, so we've got plenty of work going into Q1 next year to get production off early.

No, that's very helpful. Last question is just on current taxes.

There was a cash tax recovery in 3Q. Is the expectation that you'll have another cash -- directionally have another cash tax recovery in 4Q? I know it's a modeling question but it just seems to be standing out.

It's Rob Waters here, Greg. The way we account for taxes is that every quarter we forecast what that year looks like in terms of the income tax. As you can appreciate, in the first two quarters, when commodity prices were high, we're anticipating more taxable income and more tax and book that accordingly on a prorated basis.

When we hit Q3, all of a sudden, with the declining oil prices, that estimate of the full year of taxation has dropped and that's where the recovery comes from. In the way that we're recording income taxes, we'd actually over-accrued, as it were, in the first two quarters, just given where the year is now trailing out to be.

So if these current oil prices persist, chances are we could get another recovery, too. But it's not -- we don't have a lot of income taxes and play, as you know, in our Company. We're not really cash taxable in Canada and in the US we've actually dropped our guidance in terms of income tax slightly to reflect the lower oil prices and lower taxable income that we're now expecting.

Okay, that's great. Thanks, all.

Patrick Bryden, Scotia Bank.

Hey, Patrick.

Patrick Bryden, your line is open.

Good morning, can you hear me?

Yes, we can.

Sorry about that. Thank you.

When you think about the dynamics at play in the Marcellus here, and some of the shut-ins that may be happening with operators in industry as well as yourself, can you give us a sense for how that decision process is being made?

I guess I'll speak to our situation, because people manage these things independently. In our situation, we have a few different operators. The single largest operator there is Chief. We have a good dialogue there and we're very strategically aligned.

We anticipated the possibility of curtailment several months back, several quarters ago, and that was based on a view that when you look at the build, the supply build and then he looked at the transport build-out and that timetable and then you thought about summer pricing dynamics, you could see potential for low prices in the summer.

Chief would have told us that in that dynamic, depending where those prices went, they might curtail production. We tried to account for all of that and I think we did a very good job doing it. I made a mistake, I think, by not maybe quite accounting for how much it could affect our operating costs and so we had to move our operating costs down a tiny -- we moved them down a tiny bit and up a tiny bit. But on the production side, I think we captured really quite well. It's their decision and we are very strategically aligned with how they been going about doing it.

Okay. I know it's maybe hard to peg what the visibility is on that, but you're suggesting that might persist into Q4? Or would you think that kind of alleviates as we look ahead into the new year?

Yes, lots of moving pieces, right? We have a pretty wide Q4 implied production level, when you look at our 102,000 BOE to 104,000 BOE a day. We think probably we're towards the high end of that and so that implies some of curtailment, but not as much as we might have seen in the third quarter. But it implies some curtailment that sits there.

We could be wrong on that and therefore we think we need to keep that wide end of the range. Of late, those pipe expansions have occurred as we anticipated and volumes -- prices are responding. You can see that in the spot market, so we're comfortable with our guidance but it does move around a little bit, for sure. I mean, there's volatility that sits there.

I think it is what we've been saying for the last couple of years. Lots of gaps in the area, pipes building out, weather is going to play a role. We will probably have this conversation every quarter for a while and we're managing that, we're managing our guidance.

The big, big things that are at play here, that are supportive, capital is slowing. You are seeing that slow. You're seeing it with our operator, you are seeing it with other operators, and the pipes are being built out. I think it's all moving in the right direction and we're managing it, I think, quite well.

Okay. I'm wondering if, is it possible to get a bit more elaboration on the sales and transportation agreements as you look out in time? I think, Eric, you had touched on that in the 2016 to 2018 timeframe. Can we get a little more specifics on that?

We can't in terms of the commercial sales agreement. We have signed precedent agreement with the Pen East Project and the sales agreements link to pipelines that are in service in advance of that in the 2015 to 2016, 2017 timeframe.

Okay. Did I hear you correctly, did you say 80 million cubic feet a day that is related to Transco New York?

That's correct.

And that would be a number that is net?

Pardon me, Transco non-New York.

Okay. And that is a net or gross number?

That's our sales.

It's net to enterprise.

Okay. And then on the Duvernay, can you give a sense for -- you've mentioned you want to evaluate performance and that you are pleased. But what would you be looking for as you evaluate well performance here? What specifically would push you one way or the other?

I think there's a couple things, Pat. You look at that 15 of 8 well, which is the one that has the higher liquids content and it has the higher production. We're at day 31, so it still early, of course. Time is going to be important to see how things stabilize and how they line up and give us more comfort on the reserve profile we're dealing with.

You've also got industry data coming that's important. We have a fairly large land position. In some areas we've got good control, in some areas we don't have a lot. If you actually look the Willesden Green generally, there some areas we have one well per township. Just more data is going to be helpful to that.

I think the other piece, though, is really understanding what's happening to costs in the area. Different producers are trying different completion approaches and they have different cost profiles and so really understanding how all of that lines up is going to be important for us.

And on that cost side, I can appreciate you want to beg of this question, but can you give us a sense for what that cost grove look like as you start out and if you were to progress?

You know, you'd have almost as much information as me on this. We have our own experiences, but we're levering as much a thing on what other producers are doing who are running bigger programs and starting to think of pad drilling and those sorts of things. The companies were spending more money. They are talking about the possibility of CAD10 million to CAD13 million.

Some of that's -- a lot of that is going to tied to the completion design that they actually have and we have quite figured all that out at this red-hot minute. I think CAD10 million to CAD15 million is a good number to think about, but we don't have a lot of data on this point and that's really what we're working on right now to understand that.

If you look at these will results, particularly that 15 of 8, and you think you're talking about well costs, I don't know, under CAD15 million, you can start to make it go around. If you think you get them down to CAD10 million, it actually looks pretty interesting. Our type curve, for what it's worth right now, is still based on that 750,000 BOE of reserves and in that Northwest area, that's got a shot at being half condensate or something along those lines. So that can line up pretty well in this pricing environment.

Okay. Last thing and then I'll get out of the way. Can we just maybe have a little bit more color on Brooks in terms of running room in the Manville, the rates and that cost, that kind of thing would be much appreciated?

The cost, Pat, they were just under CAD1.8 million to drill and complete. IP 30 just above 90 barrels a day, 94 barrels a day.

It does have running room. We're looking at probably drilling somewhere between 50 and 70 in the full program. We've got another 8 to 10 this year and as I said next year, 20 plus. Really, depending on the results will depend what we end up drilling.

Okay. Any comments on thickness, or channels that might be more perspective and the upside of what's rates could do?

The [globe] channel running there as well. One of the wells that we brought on, we hit virgin pressure so we're looking at all of this stuff and some of it feels as if it could be quite exciting, but we're still early in with the first six wells. We still have some learning to do. Certainly early indications are looking pretty good with, as I say, that virgin pressure well, we're seeing summer between 50% and 80% oil cut, which is what you would expect to see first well in there, so that's good news.

Okay. Appreciate that. Thank you.

(Operator Instructions)

Kyle Preston, National Bank.

Thank you and good morning, guys. I think Patrick covered most of my questions on the Duvernay, but just one other question I had, regarding your production mix in 2015. Realize your guidance isn't out yet, but obviously you had a lot of new gas brought on in 2014, but now the fact that you're laying down the rigs in the Marcellus.

Should we expect to see a material change in your gas/oil mix there? Will you just be sort of back filling the Marcellus gas with behind pipe gas you have there?

So, we're talking a 5% to 10% growth. Oil will grow at the same kind of levels we have this year. The Marcellus would still probably expect decent growth when you look at the completion backlog, that Ray talked about, you look at the profile.

I think as a round number to think about is similar kind of growth on the gas and oil side. One of the things that we are actually kicking off a Wilrich program. It's not dramatically large, but it is an area that we're pretty encouraged by and so that could give a decent contribution on the gas side as well. Short answer, both gas and oil with, call it, three-quarters of the spend on oil side.

Okay, thanks. As far as the basis difs on Marcellus gas and these similar levels in 2015, I know Eric so there was some new capacity coming but don't imagine that will have a big impact?

In Q3, we talked about CAD1.50 dif for the rest of this year and continuing into next year. That would've been the context of CAD4 NYMEX. It was wider in the quarter, it is tighter at the second, I think it's a good number to think about and I can't say it enough, weather will influence it.

I think as we see CAD4.50 NYMEX, if that were to happen, the differentials probably a bit wider, actually. Because there's a fair amount of gas here that's really by, for all intents and purposes, disconnected from NYMEX right now.

Okay, great. That's it for me, thanks.

Thanks, Kyle.

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

Well, thank you everyone for dialing in today. Nice to see a little bit of green in the markets after the last summer. Appreciate everyone's time and hope everyone has a great rest of your day. Thank you, bye.

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