Enerplus Corporation
Q1 2013 Earnings Call Transcript

Published: 18 Sep 2013

[Robert Waters:]

Good morning everyone and thanks to FirstEnergy and Societe Generale for hosting us. I’m not going to spend much time with the advisory but you should be aware of the risk to the forward-looking information we are talking about. Enerplus began its life, just a quick overview of Enerplus; we began our life 27 years ago. So we’ve been around for 27 years. We began as a Canadian royalty trust. But those days of being a Canadian company are kind of over for us. Although, I am a proud Canadian, we are very much a cross-border company now between U.S. and Canada. For example, 40% of our production is coming out of the U.S., 60% of our shareholders are from the U.S. We are listed on New York as well as the TSX. We are in two of the best plays in the U.S. if not in North America in terms of North Dakota, Bakken oil and Marcellus gas. 65% of our CapEx is being spent in the U.S. We currently expect to produce 85,000 BOEs a day, just under 50% crude oil and liquids on that so sort of a 50-50 mix between gas and oil. What makes us different is we are also a higher yielding company like Crescent Point, we have a 6% dividend yield. And that draws back to our legacy as a Canadian energy trust. It also is part of our strategy as a management team because we do believe that it adds more disciplined management to return some of the returns back to shareholders and it reduces the risk to investors in investing in oil and gas. Now our corporate strategy is to deliver sustainable and profitable growth and income to investors. So you take that combination of your annual cash flow growth with competitive yields and that provides you an attractive total return. So currently we have a very focused asset base with positions in North America’s top tier resource properties. We complement that with the mature low decline assets but that has not always been the case. As mentioned, we spent the last four years repositioning our portfolio. We [spent][ph] billions of dollars of non-core assets that didn’t have the economic scope and scale to be top quartile and we reinvested those proceeds into early stage assets that we believe had the potential to deliver top quartile return and scope and scale for Enerplus. So this turnaround story as they call it has been challenging at times than if you watch our share price that had suffered previously because people would worry that we would blow off our balance sheet are be unable to do this and we’ve proven now that we are coming at the tail end of turnaround and the share price is starting to respond. I think we still have a gap between the multiples we are trading at in some of our peers. But our job is to continue to deliver the results that we see in the first three quarters. We’ve accomplished the turnaround without stretching our balance sheet; in fact which is interesting because we are still 50% natural gas player in the North American market where gas prices are depressed. We are emerging as a much more focused company, a profitable company and one with a very discipline capital allocation strategy. In terms of the four core area, we are focused on Williston Basin in the U.S., light oil. We have a large working interest and we operate a position in the Sleeping Giant which is the Elm Coulee Bakken field in Montana. We are also in Fort Berthold which is North Dakota Bakken and Three Forks, and we are spending about 50% of our capital there. We are in the Marcellus. We have about 90,000 net acres, 40,000 of those net acres are non-operated, so we don’t operate it but they are in the sweet spot of the dry and Marcellus play and I’ll talk more about that later. In Canada, we have interest in nine Waterfloods and these are low decline assets. They have been in existence for decades. They have a lot of original oil in place and we are using new technology and reservoir engineering to extract more of that oil. And finally, in the Canadian Deep Basin, we have some very interesting positions in some of the emerging plays there being Montney, Duvernay and the Wilrich that we will talk about. In order to give you some impression of how much focus and transition has gone on, in 2008, if you were to take our top 10 assets, they would represent 53% of our net present value. At the end of last year the top 10 assets represented 81% of our net present value. In fact the Four Core areas that I just talked about they represent 86% of our net present value and about 73% to 75% of our production in reserve. So there has been a tremendous amount of change in terms of our portfolio in a very short period of time and this is what is delivering right now. So 19% production growth over the last 10 quarters and as you know, it’s not all about production growth, it’s not all BOEs are created equal. So let’s talk cash flow growth, or funds flow growth and over the last three years in terms of funds flow growth, we are seeing a 33% increase. Now for 2013 in the first half we had funds flow growth of $377 million. We are using the analyst consensus for the full year of $764 million. And so not only is that funds flow growth driven by increasing production, notably increasing oil production, it’s also driven by improving capital efficiency, we are getting more bang for our capital buck and improving cost structures, and we’ll talk about how we have been able to reduce their drilling and completion cost over time and that’s very important to us. So it’s not all about production growth. It’s also about having discipline around how you are spending your money whether that’s capital or operating costs or G&A costs. Sustainability was a big issue for us because we do have a high dividend yield and we do have 50% natural gas weighting and that was a concern in prior years because people would worry about our dividend and our exposure to natural gas and our balance sheet. Well in 2013 we’re already fully funded, the cash inflow is expected to exceed the cash outflow. We have CapEx of $685 million and our dividends are $215 million and we can cover that $900 million with the combination of funds flow, the net disposition of non-core assets and SDP is really our form of DRIP program, stock dividend plan, it’s the tax -- tax advantage DRIP so to speak. And we expect this sustainability to continue in our model as we model going forward. And this is important in terms of our business and the sustainability of the current dividend. In terms of performance year-to-date I would say it’s been ahead of expectation. Our production guidance has been confirmed at the higher end of our original range, despite having still 1,300 barrels a day of non-core production that we haven’t adjusted it for. In fact, we have plans to divest more non-core assets between now and year end, but to the extent that those sales don’t materialize, there is a probability that will exceed both annual average and exist and in Q -- in the second quarter our production was 90,000 BOEs a day. Again not all about productions, in terms of our costs, our capital spending, our operating costs, our G&A costs, they are all tracking original guidance. We’ll talk a little bit about the asset so I have moved into North Dakota and this is where we are drilling for Bakken and Three Forks, spending about 50% of our capital base here -- of our capital spending here. This is very light oil, 42 degree API oil. We have 70,000 high working interest acreage, we are the operator, we have been in this place for three and half years, drilled 92 wells now, 92 net locations, so we are getting a good feel of the play. Its beyond early stage now. It’s into full development mode. We’ve got two rig running and we like what we see. We’ve taken production in Fort Berthold from essentially zero we expect to exit this year at 18,000 barrels a day -- BOEs a day. When you look at the economics of the play, the average net back is an access of $50 a barrel. The F&D costs are running between $20 and $25 a barrel. Recycle ratio exceeding two time for the play. We are drilling 20 to 25 net wells a year, two-thirds of those are Bakken and one-third of those Three Forks. We have about 130 drilling location available, if you are seeing four well for safety unit and I’ll talk a little bit about the upside potential of down spacing because there is more toward than that. In fact, I’ll move on to that rite now, when you look at the running room at Fort Berthold, North Dakota. In addition to the 130 net wells that are currently in our inventory, some of our partners in North Dakota have been experimenting with downsizing and over the net two quarters we are going to do our own downsizing pilots and we are going to do at seven well test to see if we can downsize the spacing unit. In addition, some of our partners are drilling into the lower Three Forks expansion and so far we have just been drilling the Bakken and first Three Fork expanse with the lot of success. Right now we are selectively pouring down into the second and third ventures of Three Forks across the land. We are comfortable that we have Bakken across our acreage in this field and we are comfortable that we have the first venture of the Three Forks across at least 90% of our acreage in the field. Time will tell whether we have the second and third ventures and we’ll be testing those depending on the core results. But as you can see just down spacing alone will add another 150 net locations and eight more years of drilling inventory. So its been a great place for us. Things keep getting better, we’ve changed our frac design and we’ve recently updated this slide from other what other people have seen before and that we are watching with some of our competitors we are doing in and historically we do high stream proppant which is quite expensive because we are worry that the reservoir pressure would crush the bend we are using in the fracking. But we’ve noted that some of our peers have been using high strength white sand for sometime which is a lot cheaper than ceramic proppant and increasing the number of stages and do tighter spacing. And so the six wells we have drilled and sort of follow that methodology we are pumping 2.5 to 3 times more proppant albeit using white sand and we are increasing the number of stages and tightening it down and the result although early days have been impressive. So this shows you a 500 or 650 and 800,000 type curve and you can see of the six wells three of them, in fact four of them are either tracking or beating the top end of our previous range being an 800,000 type curve. And in terms of the economics an 800,000 type curve would translate into a rate of return just under 60% and the breakeven price of about $51 a barrel. And we are doing all that and we are maintaining our costs in terms of the costs drill and completed well there. When we started this year we expected to spend just under $13 million, $12.9 million to drill and complete a long Bakken well in this area of the reservoir. We brought those costs down to $11.5 million by dropping some rigs that we are not as efficient as the two rigs we are running now and putting almost all of the services out to tender. So once again not only are we proud of the operating performance that you are seeing as we tweak our completion technology but we are quite proud of our ability to control cost in the area. And so the Williston Basin this combination of the Montana Bakken and the Bakken in Three Forks in North Dakota is actually adding a significant cash flow to our company. North Dakota alone has become cash flow positive and that’s interesting for a developing early asset that were just 3.5 year event. The net operating income is exceeding the capital that we are investing in the play and that’s important it represents 50% of Enerplus’ crude production at this time. Let swing back to Canada and talk a crude oil there and here we have interest in nine Canadian Waterfloods. What we like about this is although they are mature assets, technology is our frontier and with these assets we are using modern reservoir technology and infill drilling and in two cases we are polymer floods to extract more of the original oil and plays. It had very low decline, 12% decline. So if you think of it we are in some of the high growth areas like North Dakota that have initial steep decline, while this 12% help offset that. So as a company our average corporate decline is running about 24% which is quite reasonable. What we also like about this is we can spend between 45% to 60% of the cash flow and maintain or modestly grow production. So the water floods are spinning off free cash that we can redeploy into other assets. Swing into the Marcellus, so in the Marcellus, we have 90,000 net acre, 50,000 of those we operate and our operated acreage ran more Central Pennsylvania and down into West Virginia. We’ve drilled some wells in the operated acreage but I would call it tier 2 acreage relative to the non-opposition that we own in North East Pennsylvania. So in fact, we’re not actually spending money on our operated Marcellus acreage right now given where gas prices are. And so what I’ll talk about is there is non-operated position, 40,000 net acres and that is in the thicker, than the best of the best in terms of dry Marcellus play. And so our operators there are cheap oil and gas which is a private company that was one of the early movers in the Barnett Shale, also Exco and to a lesser extent Chesapeake. And in previous years, we’re getting brief from the market with drilling for dry gas when gas prices were low. And everyone else had shut down their dry gas drilling programs. But we are drilling both productions because in the Marcellus, you have about five years to get your wells drilled in on production. And then you hold it otherwise you could lose your deed. So we’ve been drilling for dry gas through that whole downturn in gas and taking a bit of a beating quite honestly. But now we’re coming of the other side. Currently, we have 60% of what we consider the core of the play held by production. By year end, we’ll be at 75% and given the current pace of play, we’re confident that we can pull what we consider the core other play by production. In terms of Marcellus for an early stage play, it is also turning cash flow positive to us. So this is an early stage play that’s natural gas in North America and next year the net offering income will exceed the capital that we’re spending on it. So that is very impressive. And with the production upside case here is the green, is we’re actually seeing higher production in the Marcellus than we had originally expected in terms of the productivity of the wells that we’re seeing. This slide shows you the four -- we're in the fourth counties in North East Pennsylvania. The top one, the dark one is Susquehanna county well performance. And as you can see, it’s topping a 12 Bcf tight curve. This is actual well performance. The next one in red is Bradford county wells and they are tossing the 10 Bcf well performance. And then you have West and East Lycoming sort of in that range at 8 Bcf. And so it’s not unusual and we have had some wells coming in at over 20 million a day in this part of Marcellus. And they are not declining as fast as people had expected. And so you take a 12 Bcf Marcellus well. And if giving us return just under 50% return. At breakeven, that $2.45 in Mcf. Those kind of returns are comparable to drilling for light crude oil in North Dakota. So very powerful economics. Our netback on our Marcellus production in the second quarter was just under $2.50 an Mcf and not reflected in negative $0.18 differentials in NYMEX. When we first began in the Marcellus, we’d actually get a premium to NYMEX because it’s right up against the North American Bakken market play. But because of the amount of the pie coming on, because of this type of acreage, the supply is over run the transportation capacity there. And we’re seeing a discount to NYMEX now. And quickly a volatile remainder of the year for discounts. We do expect a debottleneck but these are still strong economic. In terms of Canada, we are active in the deep basin but this is more earlier stage growth prospects. Some of the early one that are the Montney. We have 34000 net acres. We own a 100% of it. This is in the Cameron/Julienne Creek area. This would be the area where progress, now Petronas, the Malaysian have 20 rigs running. And 2020 is very active. It is dry gas. We’ve got one vertical test into it. We plan to drill at least another horizontal well to prove up our property there. At $3 AECO, if we give you a 17% return, if you got a 5 Bcf well there, $2.34 per Mcf breakeven. And we did have modest drilling to hold our land. Down in the Duvernay, we are in the Wilesden Green area and we moved into that area after seeing the drilling that’s happening in Kaybob and quite honestly Eagle Ford in the U.S. there’s a good proxy for this area. We believe we’re in a liquid-rich window but we only have two vertical test into it now. And the first test proved that we’re in the liquid-rich window, the second test we just completed. And they are analyzing the results. So we haven’t come out with anything public on that yet. We built the Duvernay position over the last 18 months but we’re in it for about a $1000 per acre. And if this were felt and we really are after condensate here to be clear. We’ve got lots of dry gas in the portfolio. We want to condensate. If this were sold and you can go wells protection, we see lines attached to 400 wells. That’s between $4 million and $5 million. The development is about just one asset. Just to give you some impression of the (inaudible) Duvernay land position we have. And finally, we also have positions in the Stacked Mannville 71,000 net acres. Good example of that we are passing in Wilrich. In Wilrich, we have 54,000 net acres. Again this is 100% well. And in Wilrich, we’ve drilled five wells today. I would say one of them we had a bit of completion challenges with but the other four wells have been doing very well. And in fact two wells, one came in at something like $13 million a day and one came at $13 million a day. And so this Wilrich, we’ve actually got a rig running on it into next year. And we plan to continue to drill more wells into it. We can see over a 100 future horizontal drilling locations. We’re currently producing about $30 million a day out of it. We could take production up to high as $50 million to $80 million a day. And again in terms of economic, this is dry gas but just based on the productivity of the well, if you can get a 7Bcf well in this area, you get 27% rate of return. It pays out in three years and a breakeven price of about $2.21. That 27% rate of return is based on $3 AECO. So again dry gas because of the productivity is still economic. So maybe just to summarize, what makes Enerplus unique is we have been very actively repositioning our company over the last four years. And selling a huge amount of non-core assets that we didn’t believe had the potential to be top quartile or scope and scale and repositioning into some of these early stage assets that I have been talking about. The stock has been under pressure in prior years because we’re worried about what’s going to happen. But now people are seeing that coming together. By coming together, I mean, we have not blown up our balance sheet. We are running at 1.6 debt-to-cash flow at the end of the quarter, at the end of the year consensus would say 1.5 times. We’ve improved our sustainability, our payout ratio is running at 150%. That’s adjusted payout ratio. We’re demonstrating cost control in terms of our capital spending and achieving cost reductions and drilling in completion and disciplined around out cost and G&A and we’re also delivering on cash flow growth. So at some point in time, people have got to look at our multiple relative to our peers in the value there in. And so we would argue that you don’t even need an increase in oil and gas prices. All you need is more management to continue to deliver on the strategy and we should earn back the confidence of the market and move to a multiple that divest the average of the group. We’re currently trading at about 4.6 times cash flow and the group average will be about 6.5. And so we are excited about the future. And we’ve been working hard to do this. And we could see the light at the end of the tunnel here. And so to us, it’s been an exciting time and we’re lining up the company for what we believe is a profitable future. So thank you that too.

[Unidentified Analyst:]

Robert, thanks very much. We’re happy to take one or two questions?

[Robert Waters:]

Yeah.

[Unidentified Analyst:]

[Inaudible]

[Robert Waters:]

Right. So the question would be some operators in the Bakken talk about, is it 8 million, 8.5 million to drill and complete Bakken wells and we’re talking about 10.5. And can we continue to decrease the cost of drilling and completion. The first thing I’d say is not all the Bakken is the same. And so we’re in a relatively deeper Bakken and tighter reservoir. And so in some cases, some of our competitors are drilling cheaper wells because they are not as deep. In other cases, when we talk about the drilling and completion cost, it’s all in to us. So we are including the cost to build the pads, put the roads in and everything. Whereas we are finding because we did AFEs by some of our partner that some partners are pretty specific as to what they include in there. But one thing that is a potential to reduce our cost is we’ve been drilling to hold land and we’ve started to drill pad locations this year but to the extent that you can move into pad locations and have the efficiency of the road and the infrastructure in the pad already there we see line of sight to reducing our drilling and completion costs. I wouldn’t throw out 8.5 as a target yet. We think we can beat the 10.5 that we’re currently doing and so that answers your question. Yeah, go ahead.

[Unidentified Analyst:]

[Inaudible]

[Robert Waters:]

Yeah. And the question is in the Bakken again, can we comment on well spacing and interference? And so we’ve been concentrated on just drilling Bakken wells and the first bench of the Three Forks and the assumption is that you would do two Bakken wells and two Three Forks so there’d be four wells per spacing unit. But certainly our partners have been drilling more densely than [not] [ph]. And they continue to drill more densely than [not] [ph] which tells us that they are starting to see that they are getting incremental reserves and production as a result of that. As I said the first real test, we’ve had a few minor pilots but the first real test of down spacing we’re going to do in the next couple of quarters. So we can’t really comment on whether down spacing is viable on our land yet, so we’re going to drill three wells and then three wells. So it’s actually a seven-well spacing unit, very [frequently] [ph] six so seven-well spacing unit and just test that I’d say in the next six months. In terms of interference, we have seen cases where if we’re in fracking a Three Forks well, we have seen influences on Bakken well. And so the barrier between the Bakken and the lower Three Forks is varied; sometimes it’s thicker and sometimes it’s thinner. And you do get some interference there which tells you that they are in communication in certain areas of the reservoir but our technical people aren’t convinced. At first, we thought can you just drill one well with a great big frac and get into both the Bakken and Three Forks. And they are not convinced that that well will be optimal in terms of the oil recovery. And I think our peers would probably echo that given that they’re sort of drilling into each reservoir. And in the case of the second and third bench of the Three Forks, we haven’t drilled into those yet but we are taking cores. And there’s parts of our position that I would say have better Three Forks than other parts. It’s sort of it get really good. In some cases we’ve seen Three Forks just as good as along Bakken but then in other areas of Three Forks been [inaudible]. Any other question, yeah?

[Unidentified Analyst:]

[Inaudible]

[Robert Waters:]

Okay. So two question, one is do we have a view on U.S. gas prices long-term and the other was just more of an explanation around the view about Marcellus net operating income. And so maybe I’ll deal with the net operating income question first. And let me just see if I can find that slide for you. And so what this slide shows us in blue is the capital spend that’s been happening. This is our portion of the Marcellus. The yellow is the net operating income coming out of the Marcellus and then what we’ve done is also added green as sort of an upside case and that’s really the reflecting the fact that we haven’t changed our type curves yet but evidence would suggest that as we get more production history, our type curves might be conservative. And there is some upside growth potential just -- not because we’re drilling more wells just because the productivity of the wells that we have drilled. And so in 2014, as you can see, the net operating income is exceeding the cash flow so that’s what we mean by cash flow positive. Now this is run with the forward curve at August 27 so it’s with NYMEX $3.71 Mcf kind of pricing and so we’ve just run it with the forward curve.

[Unidentified Analyst:]

[Inaudible]

[Robert Waters:]

Because we have so many drilling locations like we continue to drill it and pad drill it, and there is something like 200 drilling locations still to go in the Marcellus and some of it is the [hold land] [ph] too. And the other question was what’s our view of long-term gas prices? And honestly, although, we can say we’re making money, this is the best of the best of dry gas in North America and so there is a lot of other gas plays that aren’t really returning money certainly not full cycle economics. And as the audience would know for dry gas players there is not a lot of access to capital nor is there excess cash flow. So we actually don’t think that the current pricing environment you’re seeing now is sustainable longer term. But and we would expect it to revert back to sort of a 4.50 NYMEX kind of pricing eventually. But we do see a lot of supply coming on in Northeast Pennsylvania and we do see that that will cause disruption all the way through the gas markets and it could back up, for example, Canadian gas and other [inaudible] gas for a while. And when you look at the supply in North America or the demand of gas in North America is growing but only moderately, like you are seeing steel mills and fertilizer plants coming back to the U.S. but very gradually and we believe that you’re going to need offtake capacity from North America to ultimately help the gas price. So that someone has got to get gas off the continent, get it liquefied and sell it elsewhere and that could take some time. Yeah.

[Unidentified Analyst:]

[Inaudible]

[Robert Waters:]

So, the question is can I comment around gas price differentials with respect to the Marcellus and specifically the fact that there recently been widening and also can I comment about the influence of the Utica? And so I’ll just add don’t know enough about the Utica to comment on that. But on the Marcellus differential when we first got into this play we sell the gas at a premium to NYMEX. And now it was an $0.18 discount to NYMEX in the second quarter. Last I heard and this isn’t really current it was running at a negative $0.80 that we were seeing differential. And in the Marcellus where we’re at there’s really two big pipelines running through our acreage and one is the Tennessee pipeline and the other is Transco which is south of that. A lot of the big wells have been drilled along the Tennessee pipeline. So the Tennessee pipeline is actually add capacity and they’re having trouble getting gas out of there. The Transco still has the capacity. And so what we had been doing and still are trying to do is move some of our production up from the Tennessee areas in northern part down into the southern part of the play. And there are some interconnects that have been built like the Wyoming pipeline that runs between the two. And try to get our Marcellus gas priced with respect to Transco pipeline which is priced up to minion pricing for example. And that will at least give you a basis differential you’ll still suffer a discount. But if you’re stuck up in the northern part and you can’t move your gas you could see a differential of a $1.25, a $1.50 at times because it’s pod gas and you’re price taker. And so what we’ve been trying to do is get take away capacity from the north to the south to Transco and line up fields through Transco to get like pricing like the minion. And we’ve been successful to some extent we still have some gas trading at pod just because of the logistics of the area because everyone is obviously trying to do what we’re trying to do. We see that volatility in northeast Pennsylvania probably continuing for the rest of this year but we do believe that it will be debottlenecked in the oil and gas industry anytime that there is an [arc] [ph] like that, someone take the advantage of it and they put in different gather lines and sidelines. But what that will do is then push that differential further field like up north of Canada and down south and west. And so I think we’re probably expecting a differential volatility as I said between $0.20 for the rest -- $0.20 to $0.80 for the rest of this year but then dropping to more like $0.15, $0.10 in future years.

[Unidentified Analyst:]

Robert, I think we’ll have to wrap it up here at that point.

[Robert Waters:]

Sure.

[Unidentified Analyst:]

Thanks so much.

[Robert Waters:]

Well, thank you very much for your attention. Appreciate it.

[Unidentified Analyst:]

Thank you.