Enerplus Corp (ERF) 2012 Q3 法說會逐字稿

Good morning. My name is LaRone and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2012 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)

Ms. 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 our third quarter conference call. Gord Kerr, our President and CEO, will be summarizing the results of the quarter, and Ian Dundas, Executive Vice President and Chief Operating Officer will be providing an update on our operations. To help answer some of your questions at the end of the call, we also have with us Rob Waters, Senior Vice President and Chief Financial Officer; Ray Daniels, our Senior Vice President of Operations; Eric Le Dain, Senior Vice President of 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 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 also available on our website at Enerplus.com. Our financial statements were also prepared in accordance with International Financial Reporting Standards. 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 6 to 1 energy equivalent conversion ratio which does not represent the current value equivalent. Following our review, we will open up the phone lines and answer any questions you may have, and we will have a replay of this call available later today on our website. With that, I'll turn the call over to Gord.

Thanks for joining us this morning. I'll be reviewing our results for the third quarter that we released this morning. Then I'll turn the call over to Ian to provide you with more detail on our operations and the progress we are making in our key plays.

During the third quarter, we continued to focus the majority of our spending on our oil plays. We also executed on our plans to strengthen our financial position through the sale of some of our non-core assets. Our production averaged 81,573 BOE per day, up approximately 11% from the same quarter last year, and down marginally from the second quarter. Our crude oil volumes continued to increase through the quarter. However, our natural gas volumes were lower than we expected due to delays in our non-operated Marcellus production coming on-stream. Our oil production from Fort Berthold grew by 10% from last quarter to average 12,800 BOE per day, and our oil and liquids now account for almost half of our daily production volumes, consistent with our expectations of increasing our oil and liquids to approximately 50% this year. We've continued to invest in our non-operated natural gas assets in the Marcellus throughout the year in order to retain leases. However, activity levels with our partners have slowed versus what we expected. We have seen fewer wells being tied in this year, and Ian will provide color on this point. As a result, we are reducing our production guidance, and I'll walk you through the impact of this on our guidance in a moment.

We generated funds flow of CAD135 million or CAD0.68 per share during the quarter, down approximately 8% from the second quarter. Our realized pricing improved along with commodity prices during the quarter, but we had a couple of one time items that impacted us. Our operating costs were higher than expected by approximately CAD11 million related to charges that were either seasonal or non-routine. These costs included the newly enacted state impact fee in Pennsylvania that has application to newly drilled wells back to 2011. Charges for upgrading our US Bakken facilities for emissions controls and costs for a pipeline -- and cost for a pipeline repair at our Giltedge property. We expect operating costs in the fourth quarter will be lower. Fluctuations in the foreign exchange rate relating to our US operations also impacted funds flow by about CAD10 million compared to the second quarter.

During the quarter, a portion of our expiration and evaluation assets were written off, which impacted our net income. We recorded impairments of approximately CAD114 million, CAD66 million of which relates to Marcellus operated leases in West Virginia and Maryland that are expected to expire over the next 12 months as we don't anticipate renewing them given our spending plans next year and the current outlook for natural gas prices. Now, certainly these impairments have negatively affected our net income and reflect decisions we made to invest in certain plays, even though they had no impact on our reported fund flow.

Capital spending was down quarter-over-quarter as planned. We spent CAD167 million or 20% less than in the second quarter. The majority of our activity was focused on our oil assets at Fort Berthold and on our Canadian water flood properties. Ian will provide more color on this as well. We continue to expect capital spending of CAD850 million in 2012. With a lower capital spending and dividend, our adjusted payout ratio this quarter dropped to 159%.

As I referenced at start, we also successfully executed on the monetization of non-core assets. In August, we sold our shares in Laricina Energy, capturing proceeds of CAD141 million, and last week, we announced we had entered into an agreement to sell all of our working interests in Manitoba for approximately CAD220 million. Now, the Manitoba assets are currently producing 1,600 barrels per day of crude oil and have 8.4 million barrels of 2P reserves. The metrics on this transaction are quite favorable at 7 times cash flow, 138,000 per flowing barrel of production and nearly CAD29 per barrel of 2P reserves. We expect to close this transaction in the back half of December. Our September 30 debt to trailing 12 month fund flow pro forma of the Manitoba sale proceeds is 1.5 times.

Now, the volatility of crude oil and natural gas prices has been a major theme throughout 2012. Reducing this volatility and helping protect our revenue from risks of sharp declines is one of the key objectives of our risk management program. Given recent movements in oil prices due to uncertain global economics, our hedging program is expected to provide some certainty and protection to our fund flow. We have approximately 63% of our crude oil production net of royalties hedged for the remainder of 2012 at CAD96.22 per barrel WTI and approximately 58% of our 2013 net crude oil volumes hedged at $100 per barrel. We have also hedged a portion of our natural gas volumes for 2013 and have 17% of our net gas production hedged through a combination of puts and swaps at an average floor price CAD3.31 per MCF. We continue to watch for opportunities to hedge natural gas as we move into the winter season. I will turn the call over to Ian to give a more in depth review of our operations.

Thanks, Gord. We continue to have an active capital program during the quarter, albeit at a significantly slower pace than what we saw during the first half of the year. We invested CAD167 million during the quarter with a majority of the spend focused on our oil assets. Our tight oil project at Fort Berthold, North Dakota continued to track the lion's share of our capital with CAD80 million invested there during the quarter. Year-to-date, we've spent approximately CAD370 million in North Dakota. Our efforts this year in North Dakota are focused on growing production, improving our cost structures, managing lease expiries and advancing our understanding of the Three Forks.

So let's start with production. We produced 12,800 barrels of equivalent per day during the third quarter, up 40% year-to-date and 10% over the second quarter. We've drilled a total of 24 wells year-to-date, 80 of which are long horizontals with 24 net wells brought on stream. Cost structure has been a significant challenge over the last 12 months and have obviously been a key focus area. We indicated earlier in the year we were focused on improving profitability with a strong focus on cost control. We have tested a number of different completion designs this year to understand if we can enhance well economics with smaller fracs. While we've seen cost reductions, these wells have not met our performance expectations and we believe we are sacrificing return. As a result, we have been backed closer to our original design.

Our recent completions for a 9,800-foot lateral would have 28 to 29 stages with approximately 90,000 pounds of ceramic proppant per stage and higher [gel weighting]. Although the increased stages obviously puts cost pressure on our frac jobs, we are starting to see cost relief in other line items on our completion AFEs such as the cost of proppant. To give you a sense of it, proppant is down over 20% per pound from the start of the year, and we expect that's going to continue to fall. When you add it all up, we estimate that the cost of our current completion would still be in the CAD6.5 million range before facilities and tie in costs, which is similar to where we were last quarter even though we are now pumping bigger fracs and are seeing better performance than we saw with the smaller fracs.

Drilling performance has also improved significantly since the start of the year, in part related to eliminating our two least efficient rigs. Drilling days from rig up to TD are averaging about 30 days for a single well drilled on a pad. This would give us drilling costs of approximately CAD5 million and a total D&C cost before facilities and tie in of under CAD12 million, which is consistent with where we were last quarter and generally consistent with what we are seeing for wells drilled on our non-operated lands in this area. As I mentioned earlier, our program this year was highly influenced by land expiries. This has meant we have drilled more single wells than multiple wells on pads. We have one four well pad we drilled earlier this year, and we saw the average drilling days drop to under 25 days on these wells. Once we're able to move to more high density pads, we should see a further reduction in costs. At this point, we would expect a move to pad drilling could save more than CAD0.5 million a well. Our current plans involve a partial move to more pad drilling next year.

We've tested seven Three Forks wells this year. Although we have seen some variability, we have been quite encouraged by the results. For reference, we are currently modeling a Three Forks well to be approximately 70% as productive as a Bakken well. We have six Three Forks wells that have more than six months production history, four of which are tracking at or above our current Three Forks type curve. Several wells tracking what looks like to be a Bakken curve. Our best Three Forks well with any significant run time is a 4,500-foot short lateral with about ten months of production history. This well will produce more than 100,000 barrels in its first year. We have also recently tested a 9,800 fool lateral long Three Forks well which has produced just over 30,000 barrels of oil in its first month. Both of these wells appear to be performing like strong Bakken wells at this point. Based on our results this year, we have growing confidence in the prospectivity of the Three Forks throughout our acreage, although to date, our most prolific Three Forks wells have tended to be in the northern portion of our acreage block. Our plans next year include continuing to advance our understanding of the Three Forks, and at this point, we would expect to drill approximately another half dozen wells in the Three Forks next year.

We have been talking a lot about the impact that our non-operating leasehold has had on our overall capital invested in Fort Berthold. Out of CAD370 million in capital, we have spent here year to date, over CAD50 million is on non-operated acreage versus only CAD10 million that we expected in our original plans. When we established our 2012 plans, we had expected to drill approximately one net operated well. Through the end of Q3, we have participated in about four net non-operated wells with 2.5 net wells brought on stream.

A few comments on our marketing efforts. We currently ship 70% of our Bakken crude pipeline on the Enbridge and [Deep] systems, with the remaining 30% being shipped by rail to the Gulf Coast. The differentials continue to be very volatile. We have seen Fort Berthold field differentials tighten from a CAD15 barrel discount to WTI in the first half of the year to less than CAD10 in September, and in October, we saw differentials in the CAD2 per barrel range. While differentials remain tight in November, we continue to expect volatility in the region and are continuing to forecast wider differentials in 2013. Our rail capacity has been providing some pricing production with approximately 15% of our total Bakken production being priced off of Gulf Coast markets, which have been more closely linked to Brent pricing.

In late October, we estimate field production in Fort Berthold surpassed our exit target of just over 15,000 barrels of equivalent a day. We expect to remain at approximately this level over the balance of the year, with declines being offset by two additional completions and some production optimization work. Although we haven't finalized our 2013 plans, we would expect our capital spending to be lower in Fort Berthold next year. Economics in Fort Berthold are still attractive. However, the combination of lower oil prices and sticky costs has eroded significant margin with rate of returns under strip pricing for our Bakken wells in the 30% to 40% range. Although we are expecting to see cost reduction next year, we are not prepared to adjust our spending plans beyond our current two rig program until we see sustained improvements in cost performance.

We can move to Canada and talk about our crude oil water flood assets. We continue to advance our water flood programs throughout the quarter, spending approximately CAD25 million and focusing the majority of our efforts on our Medicine Hat Block C project in Alberta and our Freda Lake Ratcliffe project in Saskatchewan. We continued with our capital program in the Block C in the third quarter. We drilled three net wells and continued with battery enhancements and injector conversions. During the summer, we started to inject polymer into the formation. While it's too early for definitive results, early indications are quite promising. As a result of our drilling and enhanced oil recovery activities, we expect production will grow this year in this asset by almost 50% from 3,800 barrels of equivalent a day start of the year to an expected exit of 5,600 barrels a day.

We also continued to develop our assets in the Ratcliffe formation at Freda Lake to involve this play to a full fledged water flood scheme along the entire trend. We drilled a total of nine net wells with another expected to be rig released in November. We also converted ten vertical injector wells into producers with another two conversions remaining this year. The economics of this program are strong. We expect to see full program returns over 65% with a CAD60 break-even supply cost and capital efficiencies in the low CAD30,000 per barrel range. New wells drilled in this area have a type curve IP of 120 barrels a day for the first 30 days with expected recoveries of 140,000 barrels. Our results to date have exceeded these expectations. Seven of the nine new wells we have drilled in 2012 have IPed over 200 barrels a day during the first month, and six of them produced an average of 170 barrels a day over the first two months. Our water flood production has grown to almost 16,800 barrels of equivalent a day this year, which is up about 12% from this time a year ago.

Now moving to the Marcellus. Non-operated activity has slowed throughout the year in response to lower gas prices. Our program this year was designed primarily to retain leases with our nonoperated partners in northeast Pennsylvania, which is clearly one of the most prolific parts of the play. I'm pleased to say we have achieved good success in this regard. We have now satisfied the remaining portion of the carry amounts associated with our original purchase in the Marcellus. At this time, we expect by year end, we will have over two-thirds of the core acreage in our non-operated project held by production. Year-to-date we've spent about CAD90 million with our non-operated partners and expect full year spending will be approximately CAD120 million, somewhat lower than we had initially anticipated.

Despite strong well performance, we have done a poor job of forecasting the timing of the production build. Delays in the pace of production are related to several factors, including changes in timing of on-streams due to changes in partner plans as well as infrastructure delays. In addition to delayed timing of on-streams this year, we now expect approximately three net wells that were expected be brought on in 2012 will slip to 2013. We had originally expected that our production would grow from 25 million a day to 70 million a day throughout 2012. Given the slower pace of activity I indicated, we now expect our production will exit between 50 million and 60 million a day. During the third quarter, production averaged around 40 million cubic feet of gas a day. At this point, we estimate we are producing just under 50 million cubic feet a day.

With the focus on lease retention, we have not seen any significant reductions in drilling costs. While results continue to be positive, particularly in Susquehanna and Bradford counties, drill complete and tie in costs have been averaging over CAD8 million. Based on an expected EOR of between 8 BCF and 10 BCF, we expect to achieve rates of return between 15% and 25% using current strip price. Given our outlook for natural gas prices, we plan to judiciously allocate capital in this region in 2013 and would expect a lower level of spending than we have experienced in 2012. Based on our price outlook for gas, we do not expect to allocate any capital next year to our leases in West Virginia or Maryland, and as a result, you will see we took a financial write down in the amount of CAD66 million related to approximately 40,000 acres that are expected to expire over the next 12 months.

And finally, a comment on the Duvernay. We drilled our first vertical well in Duvernay in September, which we've now recently cored and logged. We're in the process of analyzing that core. One of the key data points we're looking for is to confirm maturity in order to support our view that our lands are in the liquids rich fairway. In the meantime, our process regarding a potential joint venture or sale of our Duvernay and Montney lands continues. With that, I will turn the call back to Gord to talk about our guidance.

So in terms of guidance for the remainder of 2012, we are revising our production outlook based upon our results to date. We indicated in the second quarter that there was uncertainty in our exit production from the Marcellus, and the delay in this production in the third quarter will impact not only our exit, but our annual average for 2012 as well. We now expect our daily production volumes will average 82,000 BOE a day down from our expectation of 83,500 BOE per day. Exit production volumes will now have more variability than we originally thought, and we are guiding to a range of 85,000 BOE per day to 88,000 BOE per day. As I said, these changes are directly attributable to the delays in the Marcellus. Production in October was running at a approximately 84,000 BOE per day. The sale of our Manitoba assets is not expected to have a material impact on our exit production forecast as we are assuming this deal closes at the end of December. Our forecast for operating costs is now CAD10.70 per BOE versus our original guidance of CAD10.40 per BOE due to the revised production outlook. General and administration costs are not expected to change and remain at CAD3.30 per BOE.

We continue to expect capital spending of CAD850 million, again with the majority of this spending focused on our crude oil assets. We also expect to release our 2013 guidance early in December, and based upon our activities to date and current outlook for commodity prices, we expect our capital spending will be approximately 20% lower in 2013 than this year. We've made significant improvements to our financial strength this year, and we're looking to preserve that strength. Our focus will be on improving the profitability of our business with lower capital spending next year and with the sale of our Manitoba assets, which was 1,600 barrels a day of our production, our production growth expectations will be reduced. Should we see improved commodity prices or improved operating efficiencies, we have the ability to increase our capital program and production to capture additional value for our shareholders. So with that I'll now turn the call back to the operator for questions.

(Operator Instructions)

Robert Bellinski, Morningstar.

I was wondering if you could give an update on permitting in Fort Berthold and what you see in terms of utilization for your rigs coming next year?

If you go back a year ago, permitting was a big challenge for us. When we look at where we are right now, we're -- we have permits well in hand. It's not an issue at all next year. So rig utilization for our two rigs, it's effectively 100%. These rigs have been in the fold for a couple of years now and they will be kept busy throughout next year with our current plans.

Okay. Great. And then my second question is do you guys have an estimate as far as total cost for those Duvernay models or something you are targeting at this point?

Yes. We haven't drilled one. And just to be clear, I assume you're talking about the horizontals? We have drilled a vertical strat test. The development out here will be a horizontal development and we're going to kick off our first horizontal next year.

Our expectation for that first well will be CAD15 million. If you look forward, guys are talking about lower numbers as you move towards pad drilling and such. But I think CAD15 million is a good number to think about for horizontal. That strat test would be, call it one-third of that level.

Okay. Great. Thank you.

(Operator Instructions)

Roger Serin, TD Securities.

I need a little clarification on a couple of things. On the Canadian gas realized price, you generally have been more or less in line with what I'll call [acoal] base pricing. This quarter it looked like you were a bit below that. So for modeling purposes, did something change or was it just a mix of spot versus monthly contracts?

I would say the latter is appropriate, mix of spot. We had a decent amount fixed through the summer period that we put in place early in the spring with the risk of that storage overhang, and that had an influence in the quarter.

Okay. So going forward, go back to more or less the historical trends, which was pretty close to acoal pricing?

Yes, I think so.

Okay. Operating costs. Gord, I was writing almost as quickly as I could. It sounded like CAD11 million op costs. Some of them are more one-time. Is the CAD11 million the aggregate of what you would think would be more one-time on both Pennsylvania, the US Bakken and Giltedge?

To be clear, the Pennsylvania is a catch up thing, Roger, going back to 2011. So there is an ongoing fee associated with the state of Pennsylvania for wells. And it's got some price sensitivity. It's I think graduated or reduced for wells over time. I think it starts at about [$50,000] a well.

And then also, we had some pipeline repair work that I mentioned we had to do. We had a spill on one our properties to clean up. We also had an equalization come at us. It was about three years of equalization cost. Equalizations are a normal part of the business but not necessarily in the time frame of three. So that was somewhat unusual.

Also the timing on some of our lease costs. We book them when they show up. So we'll see that drop off in the fourth quarter. And so I would expect that from Q3 to Q4, we're going to see reduction in our op costs in the order of about CAD10 million to CAD15 million.

Okay. Which is about the bump that they moved up quarter over quarter. So okay. In terms of your rail, you've got about 30% of your Bakken volumes on rail. You obviously are getting some benefit there. Can you give me a rule of thumb as to, first of all, whether it's firm or whether it's bought? And secondly what sort of dish you need for that to be profitable?

So the commitment to the rail capacity and with our buyer is a firm commitment, and that 30% receives Louisiana light suite equivalent. Rail costs from loading through transport to unloading can be in the CAD15 to CAD20 range and, therefore, you need that kind of differential versus WTI to offset.

Okay. Maybe I'm not sure whether it's Ian or Gord. So, Gord, I think you said that next year you'd probably spend less and orders of magnitude was approximately 20% less. So does that get me to CAD675 million to CAD700 million for a capital program for '13?

Your math there, Roger, that's pretty darn close.

That's what we're suggesting. Along with our guidance at the back end of the year, just to give you a sense for where we're thinking in terms of capital allocation.

Okay. To be clear, I used a calculator. So when I look at that, I think you talked about spending a little bit less in Fort Berthold. Are there areas -- and you're obviously spending a little bit less in the Marcellus. Are there areas that are actually going to see an increase in CapEx?

I think we'll moderate our plans in a number of areas there. So there might be a few smaller property areas that will receive less allocation of capital. Part of our strategy has been to get more focused in our property portfolio here overall. We don't talk about the fact that we have sold off smaller property interests here because the aggregation of the proceeds isn't that great in terms of improving our focus. There will be properties that I'd say smallish in nature that won't get capital allocated that they might have had this year.

Yes. Roger, the only thing I'd add to that, and it's not going to move the numbers in a big way. Obviously, Duvernay is one that has some contingencies associated with it based on success and based upon how JV unfolds. At this point, I wouldn't say we're planning for a JV. We're working on it and we'll see what comes out of that process. And so if we actually get something there, that could move the numbers around. That will come with some liquidity as well.

So if I looked at the Duvernay and some of your plans, it seems to me on a net basis you might be as much as two to three verticals and one horizontal. Are those numbers before JV considered plausible?

I'm not sure you would be up to -- if you didn't have a JV, I'm not sure you would be up to four verticals. One or two horizontals, a vertical. Somewhere this there.

Now I am not using a calculator, but you have to be getting upward of CAD40 million to CAD50 million.

If you went to those levels?

Yes.

Yes, you would. Recognizing we're not in the 2013 guidance conversation yet.

I understand.

We're working through those plans. And this core is going to be important for us, too, right? We're analyzing that right now. This core is designed to give us confidence in liquids content and help us drill the horizontal and optimize it. That's equivocal. That could influence our plans.

I'm guessing you think that the well you drilled was in the gas liquids window and you can say yes. And then with that in mind, what information did you have to come to that conclusion prior to getting the core information?

So, this is acreage that we -- an acreage position we purchased built up over the last year and a half. It's not legacy. We went there by design. And, like industry, you're looking for a series of things. But thermal maturation is a key driver as to where you want to set up to find your way between dry gas and oil.

And so we built our position and if you actually look at our website, you can see we have got a cartoon where we indicate where we think that fairway is. And so we chose this first location to be in an area that we thought was more prospective. But the reality is the whole position we think could be in the liquids-rich fairway. We will find out as new information comes at us. You have faulting out here as well. That could influence it. It's a work in progress, obviously.

And we'll see more results coming out here as we go as well as come off confidential status here towards the back end of the year.

Do you plan to release the thermal maturity information on your Duvernay vertical test more or less when it becomes available or will it be in due course with the quarterly? How do you think we'll hear about that?

We haven't made a decision on that, Roger.

Okay. And last question. So at a very high level you've dropped your CapEx for next year. We've seen a little bit of an improvement on commodity prices. You've hedged more. Back of the envelope again without a calculator, it looks to me, if you keep the current dividend payment on a net basis, you would be spending maybe 15% to 20% more than cash flow, but you've also got, given your asset sales, a fairly strong credit capacity. Is that a kind of over-spending that is consistent with the business model you guys have in mind?

Well, I think as Ian said earlier, hold that until we come out with our guidance at the back end of December. But I think what we're trying to indicate is that we don't expect to go into 2013 at the same spend level despite the fact that we've monetized some of our non-core assets, including the Laricina.

Can't blame me for asking.

I would be disappointed if you didn't.

Thanks. That's all I got.

There are no further questions. I will turn the call back over to Mr. Kerr.

I want to thank everybody again for joining us here today. We know that the market is the market and while we have reactions to different points in time, we're pretty confident about the direction that we're going with our asset base and the things we are doing for our shareholders. Hopefully that will get reflected as we believe it should in the market. So thank you again for joining us and everybody have a great weekend.

That concludes this conference call. You may now disconnect.