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Edited Transcript of ERF.TO earnings conference call or presentation 24-Feb-17 4:00pm GMT

Thomson Reuters StreetEvents

Q4 2016 Enerplus Corp Earnings Call

CALGARY Feb 24, 2017 (Thomson StreetEvents) -- Edited Transcript of Enerplus Corp earnings conference call or presentation Friday, February 24, 2017 at 4:00:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Drew Mair

Enerplus Corporation - Manager of IR

* Ian Dundas

Enerplus Corporation - President & CEO

* Ray Daniels

Enerplus Corporation - SVP of Operations

* Eric Le Dain

Enerplus Corporation - SVP of Corporate Development, Commercial

* Jodine Jenson Labrie

Enerplus Corporation - SVP & CFO

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Conference Call Participants

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* Patrick O'Rourke

AltaCorp Capital Inc. - Analyst

* Adam Gill

CIBC World Markets - Analyst

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Presentation

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Operator [1]

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Good morning, my name is Sharon, and I'll be your conference operator today. At this time would like to welcome everyone to the Enerplus Corporation 2016 year-end results conference call.

(Operator Instructions)

Thank you. Drew Mair, Manager of Investor Relations, you may begin your conference.

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Drew Mair, Enerplus Corporation - Manager of IR [2]

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Thank you, Operator, and good morning, everyone. Thank you for joining the call. Before we get started, please take note of the advisories located at the end of today's news release. These advisories describe the forward-looking information, non-GAAP information, and oil and gas terms referenced today, as well as the risk factors and assumptions relevant to this discussion. Our financials have been prepared in accordance with US GAAP. All discussion of production volumes today are on a gross Company working interest basis, and all financial figures are in Canadian dollars unless otherwise specified.

I'm here this morning with Ian Dundas, our President and Chief Executive Officer; Ray Daniels, Senior Vice President, Operations; Eric Le Dain, Senior Vice President, Corporate Development, Commercial, and Jodine Jenson Labrie, Senior Vice President and Chief Financial Officer. Following our discussion, we will open it up for questions. With that, I'll now turn the call over to Ian.

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Ian Dundas, Enerplus Corporation - President & CEO [3]

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Thanks, Drew. Good morning, everyone. Thanks for joining us today. 2016 was a pivotal year for Enerplus. In addition to continued strong operational performance, we had considerable success strengthening our balance sheet, as we remained committed to our plan of focusing and high-grading our portfolio.

Our non-core asset investment program generated aggregate proceeds of CAD670 million, which, combined with a modest equity raise, allowed us to reduce net debt by CAD840 million, or a almost 70% reduction from the beginning of the year. Our focus on managing and reducing our costs yielded a reduction of over the CAD100 million of cash costs relative to our initial 2016 budget. When you with this number in context of the CAD306 million in funds flow in 2016, you see how impactful this cost reduction is to our margins.

We saw important structural improvements to our realized pricing, particularly in North Dakota, where differentials have significantly tighten definitely there is room for further improvement, with additional pipeline capacity expected in service this year. We continue to deliver competitive F&D costs at CAD4.82 per BOE on a 2P basis, including future department capital, and CAD4.77 per BOE on a PDP basis. And despite an exceptionally limited capital budget, reserve replacement in our core growth areas was strong. We replaced 207% of operated North Dakota production and 175% of Marcellus production via the drill bit, through 2P reserve additions and revisions in the year.

The success we had in 2016 has laid the foundation for Enerplus to deliver what we think will be differentiated growth over the coming years. We see an ability to deliver 20% compound annual liquids production growth through 2019, funded through cash flow at [$]55 TI and [$]3 NYMEX. The key driver of this organic growth is our core position in North Dakota, where we are increasing activity levels this year, and expect to continue to accelerate activity into 2018. We will, however, always remain disciplined in our capital plans. We will not chase unfettered, unprofitable growth. Our capital allocation remains firmly grounded on the principles of value and full cycle returns.

Lastly, before I turn the call to Ray to discuss operational highlights, I would add that Enerplus is focused on environmentally responsible and safe operations. It has been, and will remain, a cornerstone of the Company's consistent and high-performing operational execution. Ray, over to you.

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Ray Daniels, Enerplus Corporation - SVP of Operations [4]

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Thanks, Ian. We met or exceeded all of our operational targets in 2016. These included delivering strong production in line with our forecast, reducing operating cost per BOE by 17% year-over-year; delivering exceptional capital efficiencies, demonstrated by our top quartile, possibly top decile F&D costs; reducing our North Dakota drill complete and tie-in costs by over 20% year-over-year, and increasing our high-quality drilling inventory in North Dakota by nearly 40% with our move to higher density drilling; and we had the safest year in our history. In addition, through proactive contracting in 2016, we our secured and protected about 75% of our North Dakota capital program from escalation in 2017.

I'm very pleased with our performance and excited about the year ahead, as we ramp up operations. In fact, this year in North Dakota, we will complete and bring on-stream more wells than in any previous year. Although we experienced extreme weather conditions in North Dakota at the tail end of last year and the start of this year, our program is on track for 2017.

Staying in North Dakota, we had a relatively limited capital program in the fourth quarter. Capital activity was centered on a three-well density test, that is what we call a fishing pad. As a refresher, this was two middle Bakken wells spaced 500 feet apart, offset by a first [bench default] well at 700 feet. Production performance from these wells has been very strong, with all three tracking the high-end of type curve expectations. Each well has produced over 100,000 BOE during the initial 90 days of production, and the wells are currently producing approximately 850 BOE per day on average, and are their fifth month of production.

One of the goals for this test was to better understand the impact of higher density drilling wells on longer-term production performance and ultimate recovery. We are encouraged with these results, and will continue to monitor the wells' performance. In addition to further drilling density testing this year, we will test various completion designs to try and further improve our capital efficiency.

Turning to the Marcellus, we saw a modest increase in activity levels in the fourth quarter in response to improved regional pricing. Prior to fourth-quarter, drilling activity in the Marcellus and eventually stopped. Our 2017 capital budget in the Marcellus is approximately $60 million, which is more than double what we spent last year, but still reflects relatively modest drilling and completions activity. We do expect some increase in activity in 2018, in advance of new pipeline projects coming into service in the region.

In our Canadian waterflood portfolio, we have been continuing to focus on expanding and optimizing secondary and tertiary recovery, while also enhancing profitability through cost efficiencies. We've been able to bring operating costs in the waterflood down by over 30% over the last two years. In part, this has been due to divesting higher-cost properties, but also through driving efficiency improvements. In our new Ante Creek asset, we consolidated plant and equipment, resulting in significant operating cost savings; and after successfully stimulating a source water well, we have started ramping up water injection volumes in accordance with our development plan. Once again, our waterflood assets will generate meaningful cash flow, free cash flow, in 2017, and then continue to help moderate our overall decline. I'll now turn the call over to Eric.

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Eric Le Dain, Enerplus Corporation - SVP of Corporate Development, Commercial [5]

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Thanks, Ray. I wanted to touch briefly on our Bakken and Marcellus differentials, before providing an update on our crude oil hedge position. The decline in basin production in the Balkan in 2016 has meant that less rail is required to clear the basin. This dynamic, combined with strong local refining demand, helped narrow Enerplus's Bakken differential to WTI in 2016 by approximately $2 per barrel compared to 2015. We've seen a meaningful improvement in our Bakken differential over the last couple of years, and we think that we will see another step change with the completion of the Dakota Access Pipeline around mid-2017.

Bakken differentials for March are trading tighter than $5 per barrel below WTI today. The Balkan portfolio is well-positioned to take advantage of these narrowing differentials. We have approximately 50% of our expected production in 2017 contracted under firm sales agreements. However, the majority of these sales are at floating market differential prices. We will add to our term sales portfolio and lock in these tighter differentials as opportunities arise throughout the year.

Accordingly, we're updating our forecasted 2017 Bakken differential to $4.50 per barrel below WTI, a 40% improvement from 2016. This improvement in our realized pricing is another area that is helping to drive our margin expansion. In the Marcellus, we also saw differentials improve through the fourth quarter and into the new year. With the lack of drilling activity in the last couple of years, the industry in Northeast Pennsylvania has worked through a good part of its inventory of curtailed production and DUCs, while regional demand and takeaway capacity have steadily grown.

The daily correlation between the in-basin spot pricing and the NYMEX so far this winter has reverted to levels we last saw in the winter of 2013/2014. In-basin, forward prices today are pointing to a tighter basis in 2017 and beyond. We're forecasting a $0.90 per Mcf realized differential below NYMEX in 2017 for the Enerplus sales portfolio, and think it will tighten further in 2018.

Turning to quantity risk management, price risk management, our financial hedges are designed for us to both protect our 2017 capital plan economics and our 2017 funds flow. We have on average 18,000 barrels per day, or 63% of forecast crude oil production net of royalties, hedged for 2017 at price levels that support our economic returns. We also have 12,500 barrels per day of crude oil protected in 2018, with 4,000 barrels per day protected for 2019. With that, I'll turn the call over to Jodi.

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Jodine Jenson Labrie, Enerplus Corporation - SVP & CFO [6]

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Thanks, Eric. As Ian mentioned earlier, we significantly strengthened our financial position in 2016, during an extremely challenging market environment. We reduced our total debt net of cash and restricted cash by over $840 million, or approximately 70%, ending the year with a net debt to trailing adjusted fund flow ratio of 1.2 times. On a forward-looking fund flow basis, this ratio is expected to be below 1 times at the end of 2017.

Importantly, the bulk of our debt reduction did not come at the expense of significant dilution, but instead it was a result of our divestment program, which is continuing to drive efficiencies across the business. Restricted cash balance at year-end reflects the proceeds from the sale of our non-operative North Dakota asset, which we chose to place in an escrow with a qualified intermediary. These funds may be held in escrow for a period of up to 180 days from the date of closing, in order to facilitate a possible like kind exchange in accordance with US federal tax regulations. Essentially, this is a tax efficient option for us, if we were to pursue certain US-based acquisition opportunities. To be clear, this does not mean a transaction will happen, but this option comes at virtually no cost to us, and could help with future tax planning.

In the fourth quarter, we completed a one-year extension of our CAD800 million bank credit facility, which now matures October 31, 2019, with no changes to our terms or covenants, and at year-end we were only 3% drawn. We have made significant progress continuing to reduce costs across the business, which has been key to ensuring we can execute on our profitable growth strategy in a lower commodity price environment in 2016 we met our beat all of our guidance targets and realized over $100 million in annual cost savings. These include interest savings from lower debt levels, as well as savings on operating costs, transportation expenses, and G&A, compared to our original 2016 guidance. Our net income was CAD840 million during the fourth quarter. This was the result of CAD339 million gain on the sale on our non-operated North Dakota property, as well as the reversal of a portion of the valuation allowance on a deferred tax asset at year-end.

Adjusted fund flow for the quarter was CAD108 million, or 34% higher than the third quarter, as commodity prices continue to improve. As I reflect on 2016 and the challenges we faced at the beginning of the year, it was very clear in our minds what steps we needed to take. We moved quickly and aggressively to reduce capital on our dividend, as well as sell non-core assets, with the final step being a modest equity raise in May. Now in 2017, we can use our financial strength and improved margins to reestablish long-term profitable growth, and create additional value for our shareholders. I'll now pass the call back to Ian for some closing comments.

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Ian Dundas, Enerplus Corporation - President & CEO [7]

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Thank you, Jodi. In summary, we are well on track to deliver substantial production and cash flow growth in a potentially [ring-bound], but certainly volatile commodity price environment. Our balance sheet is strong, the capital efficiencies are among the best in the industry, and we have a deep and high rate of return inventory. With that, we will turn the call over to the Operator and are available for any questions.

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Questions and Answers

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Operator [1]

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(Operator Instructions)

Patrick O'Rourke, AltaCorp.

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Patrick O'Rourke, AltaCorp Capital Inc. - Analyst [2]

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Great year. Looks like you have done some really good things. I have a couple of reserve base questions here. First question, south of the border, in terms of the Bakken asset, looks like you guys have reduced FDC at least at 2P level, and actually at the 1P level year-over-year. You've done some dispositions, costs are coming in lower, but there's also the interplay of higher-density drilling. Can you give some color in terms of how your booked right now in the Bakken, especially in terms of that higher-density drilling, please?

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Eric Le Dain, Enerplus Corporation - SVP of Corporate Development, Commercial [3]

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This is Eric, I can talk to that. Looking at how we are booked today, probably our average EUR for [P] plus PDP in North Dakota is about 726,000 BOE, that is just over 600,000 oil. We are looking for our UDs at roughly a similar level, about 720,000 barrels oil equivalent.

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Patrick O'Rourke, AltaCorp Capital Inc. - Analyst [4]

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But I guess more what I'm looking to understand is, you have had the success with the higher-density drilling, have you booked more locations? Because the FDC number did come down year-over-year, and I know some of that will be with the dispositions that you have done, and like we mentioned cost savings are the cost curve coming down. I'm trying to understand how tightly the engineers would be booking you there now?

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Eric Le Dain, Enerplus Corporation - SVP of Corporate Development, Commercial [5]

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Yes, we added roughly 17 locations for UDs at year-end. I need to correct something I said, the 720,000 is an oil booking level for the UDs. So about 17 incremental locations with associated FDC, and there was some cost reduction [out deferred] of FDC, and they actually netted out -- the overall pluses and minuses ended up to about minus CAD4 million in the end on a change in FDC.

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Patrick O'Rourke, AltaCorp Capital Inc. - Analyst [6]

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Okay. So are those 17 while still booked on the old spacing assumptions or have they gone to the new piloting assumptions? Everything is put in context of that 10 wells per DSU spacing. Okay. And then one quick question on north of the border. In terms of the Ante Creek asset that you've acquired, I know that you see quite a lot of upside there from potential water flooding. Is it safe to assume that is not booked in the PDP of that asset as of right now, and that could be something that is a bit of a tailwind as we move in and start thinking about the 2017 reserve report?

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Eric Le Dain, Enerplus Corporation - SVP of Corporate Development, Commercial [7]

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That is correct. We have not booked reserves for that waterflood potential beyond existing PDP.

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Ian Dundas, Enerplus Corporation - President & CEO [8]

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Patrick, on that, I think you said 2017, I think it is 2017, maybe 2018. As Ray said in the notes, we're positioning to start significant water injection, and so, as you may recall, when we were -- we talked about this build coming, the production build over the next two, two-ish years, and so you are right around that timetable. So we will see how it goes.

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Operator [9]

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(Operator Instructions)

Adam Gill, CIBC.

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Adam Gill, CIBC World Markets - Analyst [10]

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Two questions, one, in the Marcellus, is there anything that you are doing to actively protect the stronger differentials that we're seeing in 2017 and 2018? My second question, this one is pretty high level, but in terms of the 2017 plan, where you see the biggest risk in your planning, and where do you think the area is where you are most likely to outperform your plan?

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Ian Dundas, Enerplus Corporation - President & CEO [11]

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Maybe I will hit those both quickly. We have got quite a bit of detail in our investor presentation that has talked about our marketing portfolio, transport portfolio, in the Marcellus, and were quite proactive on that in anticipation of tightening up. So I think we're really well-positioned to be dealing with that. There's some short-term stuff that we're looking at right now, because we manage the near-term. The risk in the portfolio -- or in the program, the capital program, on one hand it is a significant increasing capital from where we were, and Ray talked about the most completions we've had in our history.

But it is a pretty discrete program. We're going from one rig to two rigs, and the system's pretty well dialed up. One of the things that we were particularly concerned about nine months ago was cost inflation, so (inaudible) and so we got out in front of it, and we were able to secure the lion's share of the program. So as these things go, I think it is pretty well understood machine that we're just ramping up a bit.

So I would say there is no dramatic risks associated with how we see this next program. The guys on the ground are going what are you talking about, we're about to go -- spend a lot of money and go a lot faster. But I think it's really well understood, and we're really well-positioned to be able to manage those risks. Ray, do want to add color?

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Ray Daniels, Enerplus Corporation - SVP of Operations [12]

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No, I think you've covered it well, there, Ian. We've got a great team down in the US. They're set up and ready to go, and so far we are on track, and it looks like we will continue that way.

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Ian Dundas, Enerplus Corporation - President & CEO [13]

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We're now getting granular, right, so this weather event, it's got a fair amount of play in other Bakken companies calls. It was dramatic. It was dramatic. We anticipated winter, and so have built-in cushions for those kinds of things, but it is significant. It takes a lot of work, and if that stuff continues to play out, it continues to play out in a higher spend environment, it creates issues. But I think we are well-positioned for it.

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Adam Gill, CIBC World Markets - Analyst [14]

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Where do you think you could maybe outperform on your plan?

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Ian Dundas, Enerplus Corporation - President & CEO [15]

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Well, you have 30 wells coming on, little improvements here and there can really add up, right? I think it would be hard to go much faster. We're not dealing with things that are -- we've got a pretty good cycle time right now. If you think about these 30 wells, the most in our history, but we are only using two rigs. We have run five rigs before. But back then we had cycle times -- it took you 40 days to drill a well and three months to bring it on, so our cycle times are pretty fast right now.

So I would think the bigger upsides are going to be as we continue to optimize this completion design, and it could be quite impactful. We're still budgeting for an CAD8 million well, which means 1,000 pounds of proppant, and then we use a bit of a higher cost proppant. If we can make that happen for less, you multiply that by the number of wells, you could see significant improvements in capital efficiency, but we're continuing to test lots of different things along that line.

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Operator [16]

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(Operator Instructions)

We do not have any questions on the phone at this time. I will turn the call over to the presenters.

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Ian Dundas, Enerplus Corporation - President & CEO [17]

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Thank you very much. Appreciate your time, and hope everyone enjoys the rest of their day, cheers.

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Operator [18]

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