Enerplus Corp (ERF) 2015 Q4 法說會逐字稿

At this time I would like to welcome everyone to the Enerplus Corporation 2015 fourth-quarter and year-end results conference call.

(Operator Instructions)

I would now like to turn the call over to Mr. Drew Mair, Manager, Investor Relations. Please go ahead.

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 am here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jensen Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; and Eric Le Dain, Senior Vice President, Corporate Development, Commercial.

Following our discussion we will open up the call for questions. With that, I will turn the call over to Ian.

Good morning, everyone, and thanks for joining us today. We have just announced operating results that continue to demonstrate the quality of our assets and our ongoing cost improvements. Our results reinforce our focus on maintaining our financial strength and flexibility. But as importantly, we have continued to exceed our targets for safety, regulatory, and environmental performance. I will talk about some of our key achievements in 2015 and how these have better positioned Enerplus as we move forward.

Under a significantly reduced capital budget, we exceeded our targets and grew annual production by 3%, despite a significant number of non-core divestments during the year. Our production growth in 2015 was primarily a story of strong well performance and excellent capital efficiencies in North Dakota, where we directed 60% of our capital. We have worked hard to reduce our cost structures, and we continue to do so across all areas of our operations. In North Dakota specifically, we saw meaningful improvement in our all-in well costs, which are down almost 30% from 2014 levels.

We also made the difficult but necessary decisions to reduce our staff count by 20% during the year, as we continued to focus our portfolio and rightsize our organization for the environment we find ourselves in.

Our operating performance also translated into another strong reserves story this year. We replaced 108% of our production through the drill bit. But more importantly, this occurred at highly competitive finding and development costs of CAD8.44 per BOE. We believe this is particularly significant given that reserve additions and revisions over 65% weighted to crude oil and natural gas liquids.

We continue to improve the focus of our portfolio and sold non-core properties with production of over 6,000 BOE per day during the year. Including the Deep Basin divestment announced early 2016, we have sold over 11,000 BOE a day since the start of 2015. This has concentrated our activities on fewer, larger positions while also strengthening our balance sheet.

Included in this divestment total is 2,700 BOE per day low margin, dry, shallow gas assets that we sold in the fourth quarter. Divesting these assets is expected to improve our netback, given the higher relative operating costs of the assets, but it also significantly reduces our abandonment obligations.

Looking forward. Today we announced further reductions in our 2016 spend. Our capital program for 2016 is now forecast at CAD200 million, down 40% from our current 2016 guidance and 60% lower than our 2015 spend. In addition, we are reducing our monthly dividend to CAD0.01 per share per month, representing a savings of approximately CAD37 million for the rest of 2016. These measures are aimed at maintaining our financial flexibility and preserving the value of our high-quality inventory during these low commodity prices.

We have been consistent in our messaging around the dividend. It remains an important part of our shareholder value proposition. However it needs to be an appropriate level in the context of our cash flows.

Taking into account our recent asset sales and reduced capital program, our revised 2016 production guidance range is 90,000 to 94,000 BOE per day, with 43,000 to 45,000 barrels per day of liquids. With these steps, we believe we are well positioned to continue to manage through this downturn without compromising our balance sheet.

And with that I will now ask Jodi to comment on our financial highlights.

Sure, thanks, Ian. Our continued focus on costs resulted of full-year operating expenses of CAD8.76 per BOE, which was below our guidance of CAD9.00 per BOE and 10% below our original 2015 guidance. In 2016 we intend to continue to drive costs down. However, with production levels lower and a production mix more heavily weighted to oil, our operating costs are expected to be CAD9.50 per BOE.

G&A was another area where we realized significant cost savings during 2015. Annual G&A expenses were CAD2.09 per BOE, coming in below our revised guidance of CAD2.20 per BOE and 13% below our original 2015 guidance, despite CAD11.5 million in one-time severance costs.

However, 2016 is when we really start to see the benefits of our cost savings initiatives. We expect, on an absolute basis, cash G&A to be down approximately 15% year over year. But on a BOE basis, it is essentially flat at CAD2.10 per BOE, again due to lower production levels in 2016.

Funds flow for the fourth quarter was CAD103 million, or CAD0.50 per share. And for the full year, funds flow was CAD493 million, or CAD2.39 per share. This was supported by our commodity risk management program, where we realized cash gains of CAD288 million during 2015.

We incurred an asset impairment charge during the fourth quarter of CAD266 million and for the full year CAD1.4 billion, both before tax. Unlike IFRS accounting, US GAAP stipulates that we use historical trailing-12 month commodity prices when calculating impairments, and consequently the impairments reflect the low commodity prices during 2015.

Furthermore, we expect the 12-month trailing price to decline further during the first quarter of 2016, which may lead to additional impairments. It is important to note that this impairment reduces our earnings, but it does not impact fund flow. In addition, because we report these in US GAAP, these impairments are not reversed in future periods when commodity prices recover.

We ended the year with total debt net of cash of CAD1.2 billion, which was an increase of CAD80 million over 2014. This increase was entirely due to the effect of the weakening Canadian dollar on our US senior notes. We repaid approximately CAD103 million of our senior notes during the year and increased the amount drawn on our bank credit facility by a modest CAD6.6 million.

As we look forward into 2016, our top priority is keeping the balance sheet strong. At current commodity prices, our capital program and dividends are more than fully funded by funds flow and our Deep Basin divestment proceeds of CAD193 million. Furthermore, we expect to repay between CAD100 million and CAD150 million in debt throughout the year.

Although we have no scheduled debt repayments on our US senior notes until June 2017, in January we made an offer to purchase a portion of our senior notes and were able to retire approximately CAD80 million, or $57 million, at a discount to par, which further improves our leverage ratios.

Finally, a few words on our debt covenant. At year end, we were in compliance with all of our covenants. Our most restrictive covenant, which is debt to EBITDA, was at 2.2 times. The maximum ratio under this covenant is 3.5 times for a period of six months, after which it drops to 3 times. Based on our forecast prices for 2016 of approximately $39 per barrel WTI and $2.40 for Mcf NYMEX, we expect to continue to be compliant with all of our covenants throughout 2016, as a result of recording a gain on the sale of our Deep Basin assets.

Typically, under full-cost accounting, we would not recognize gains and losses. However, in the event that a disposition significantly alters the relationship between the book value on the financial statements and proved reserves, US GAAP requires that a gain or loss be recorded in income. As a result of the significant impairments recorded to our book value throughout 2015, the sale of our Deep Basin properties in 2016 meets the criteria. Therefore, we expect to record a gain of approximately CAD145 million in the first quarter, which will be included in our EBITDA.

However, a word of caution. If the current commodity price environment persists, we would expect to start taking steps to renegotiate our covenants with our lenders towards the end of 2016. Overall though, we have been able to maintain our financial flexibility and continue to remain in a relatively strong financial position.

I will now turn the call over to Ray to speak about operations.

Thanks, Jodi. I will be brief.

The key message I would like to get across is that our assets continue to perform very well. I am extremely proud of what we have accomplished operationally in 2015. We were able to deliver production growth under a significantly reduced budget and despite non-core divestments. Our 2015 capital program was largely focused in North Dakota, and this asset will continue to see the bulk of our 2016 spending.

Activity levels in North Dakota were lower in the fourth quarter. We drilled 1.6 net wells and brought approximately 4 net wells on stream. Our well deliverability in North Dakota remains top decile, and our costs are continuing to come down. Current all-in drill complete and tie-in costs, including facilities, are approaching $9 million.

One of the drivers for reducing our 2016 capital budget is to preserve the value our inventory. Our North Dakota wells are prolific. Our average well in 2015 delivered in excess of 100,000 barrels of oil in under four months. We believe it is prudent to defer more of these wells until commodity prices have improved.

It is with this in mind that we have reduced the number of completions in 2016 by around 40% relative to 2015. That ends up being around 14 completions in 2016 in North Dakota. We will still have approximately 12 drilled uncompleted wells in North Dakota at the end of 2016.

Turning to the Marcellus. We spent CAD4.5 million in the fourth quarter and less than CAD8 million in the second half of 2015. We expect modest levels of spending to continue in the Marcellus in 2016, pending further improvement in regional pricing. Well performance remains strong, allowing us to maintain fairly steady production with low levels of activity.

In Canada the spending will be directed toward water flood development and optimization activities.

And with that I will pass the call to Eric to speak about our hedging activities and pricing outlook.

Thanks, Ray. Our commodity hedges will continue to protect funds flow in 2016, although not to the same extent as they did in 2015. On average in 2016, we have 11,000 barrels per day of oil hedged and 62,500 Mcf per day of natural gas hedged, through a combination of swaps and three-way collars. Please refer to our news release or MD&A for details on our hedge portfolio.

Our US Bakken realized differential, at the aggregate of the field sales points, average just below $7 a barrel during the fourth quarter, before trucking and gathering. We are forecasting a similar $7 a barrel differential to WTI for 2016.

Our realized Marcellus gas pricing in the fourth quarter averaged $1.13 per Mcf below NYMEX. This was an improvement of over 30% from the third quarter. We expect our realized Marcellus differentials to improve in 2016 for two reasons. First we have secured 30,000 Mcf per day of Tennessee Gas Pipeline capacity effective August 1 from our producing region that delivers to a market of prices closer to NYMEX for our $0.63 per Mcf of firm demand tolls.

And secondly, industry spending in the region, as you know, has fallen significantly over the last 12 months, which will at least slow production growth to levels better balanced with the regional takeaway capacity being added in 2016 and 2017. As a result, we are guiding to a basis differential of $1 per Mcf below NYMEX for our 2016 Marcellus production.

Despite the improving basis differential, Enerplus is still forecasting some production curtailment in the event of low NYMEX prices, particularly in the first half of the year.

Now back to Ian for some closing remarks.

Thanks, Eric. As you know Enerplus has been focused on preserving our financial flexibility, and we continue to take steps to ensure we come out of this downturn as a strong company on all fronts. Continued discipline on capital spending, further reductions to our cost structures, operational excellence, and an unwavering focus on safe and sustainable operations, remain our priorities for 2016.

And with that I will turn the call over to the operator, and we will open it up for any questions you may have.

(Operator Instructions)

Nima Billou, Veritas Investment Research.

Good morning.

I appreciate you getting ahead of the covenants. But with the natural gas sale looking where you ended in 2015, I just want to confirm that it is only if the currently depressed commodity environment persists for the full year that you would potentially, or you would have to enter into negotiations late in the year. Because post that sale of those gas assets, which were at a good price, the adjustments in the dividends, it would seem that if commodity prices rebound even modestly that you would be onside the debt to EBITDA covenants.

Yes, it's Jodi. Based on our price view that we based our guidance on of the CAD39 WTI, we would be okay for the whole year. However, as you know, as that drops off in Q1 of 2017, and we add 2017, we would be looking at our March 31 deadline thing.

Oh, so it's only because it extends into 2017 and it goes lower to the 3.0 level where you wouldn't have to enter into this then?

Well it's a 12-month trailing calculation.

Okay. Okay.

And as you highlight, we obviously have a lot of torque to commodity prices, and very changes move these numbers around the forecast prices that we used effectively tied to the strip. So small changes can really move it.

I appreciate that. And then next, just a quick question on the capital. You haven't given the sale of those assets. You're really not suffering much of a production decline. But just wanted to get a sense where would the rational areas be to retrench? Would it just be conventional natural gas? And Canadian heavy oil? Can you just run through where the areas you target for pullback. Obviously wouldn't be your productive US assets, but run through the logic of where that spending was cut back first, that would be helpful.

You're talking about reconciling from our CAD350 million guidance to our current CAD200 million guidance?

That's right, and just generally saying, maybe you can't get down to 50 million, but really you cut back first in Canadian heavy oil, like just trying to get a sense of where you cut back first. What regions were targeted first? Or is it just broad based and evenly cut across the board this year in terms of your product mix?

So let's remember where we were at the 350 level. The 350 level, it was 90% focused on oil. And the lion's share of that was in North Dakota.

Thanks.

And so as we roll forward, a couple of things have happened. One is the Wilrich sale. We didn't have a dramatic amount of spend there, but there would've been some in the Wilrich. So that's come off out of the mix.

We also are now, maybe somewhat surprisingly to us, seeing a little more cost improvement than we would've anticipated in November. As Ray talked about, we are now flirting with a CAD9 million well cost in North Dakota, and that's not where we would have been a year ago. So there's a little bit of improvement that has come from that.

And then on the activity side, it is largely out of North Dakota. There is a little bit in Canada, some of the water-flood activity, but largely it has been out of North Dakota. A little bit of nonproductive activity, but we had talked about on streams in North Dakota of about 20, and now were talking about 14. So that's where things have -- that takes you through it.

And my final question on North Dakota, can you get a sense, because we don't always have that sense, is there still a heavy discount on North Dakota oil? Are you still suffering from discounts in that region? Your price discount to WTI, like where do those stand today, and do you see any evidence in terms of declining North Dakota production of those discount bearing WTI?

Well, let me turn that over to Eric to give you a little more color on that.

Sure, the current differentials we see are in the $7 a barrel range against WTI. And in fact, yes, there's still a decent level for sweet light crude. They have improved quite significantly over the last year, and we see them remaining at about that level for the coming year.

And are you constructed? Do you see, because you're on the ground and you're seeing the activity directly, is production starting to come off dramatically with producers like yourself pulling back activity and larger producers in the region? Are you constructive on that supply and demand balance, at least with respect to North Dakota improving, in the sense that producers are investing less, and that production is dropping off, are you seeing any signs?

The published data on North Dakota production is showing a decline in production for the industry as a whole. We have seen part of the background on the differential improvement is we've got more than ample takeaway in terms of rail and pipeline for the industry, and it is actually some of the rail totals that are being discounted to realize that tighter differential.

Thank you very much.

Greg Pardy, RBC Capital Markets.

Thanks, good morning.

Just a couple questions for me. Wondering, Ian, could you just give us a sense as to how the capital is going to be weighted over the quarters? And then secondly, maybe outside of your non-core Bakken position, are there any other assets you'll be looking to sell this year?

Thanks.

Hi, Greg. Sure.

As we continue to cut, it increasingly becomes front end loaded since you're now past January and February. So what I think about that capital spend, we're talking about, call it, close to half in the first four months. That is the way that lines up.

And then starting to follow the back of the year with not a lot in Q4. And we will be nimble in connection with that as we have last year. If we see $20 oil in Q2, there'll be a few less completions than we're thinking about right now. So we do have an ability to move relatively quickly on that. But it is for sure pretty heavily front loaded.

And then other assets to sell; I think we've been really clear about that. We continue to have small things that don't have large strategic value that we're not putting a lot of money into, and the teams are focused on optimizing those assets and driving costs to those, but when opportunities present themselves for those little things, we take advantage of that.

We have been very careful in not counting on it, because it is such a difficulty in D market with such a dramatic bid-ask spread. But that's been one of the reasons that I think we've been so successful in unlocking arguably are above-market metrics on some of our more recent trades.

Okay, that's great. Maybe just a follow-up for Ray. What was the DUC count at the end of 2015, just in North Dakota?

Did you say DUC there?

Yes, just your, wells you've drilled, but not either completed or tied in.

Yes, we had nine drilled uncompleted wells at the end of 2015.

Okay. Perfect. Okay, thanks very much.

Kyle Preston, National Bank.

Yes, thanks. Ian, I know it's probably a little bit too early to talk about 2017, but just wondering if you can give us some context around where you expect production to exit the year. What happens to your decline profile with this capital program executed this year, and also if you would anticipate more Marcellus drilling in 2017 as some of those bottlenecks get relieved there?

Well you answered your own question a little bit. 2017 is a long ways away. That said, a couple of themes here: softening decline is an outcome of this. And for us it gets impacted a little bit also by the curtailment of the Marcellus. No one has asked us about this; we haven't talked about it too much. But we are forecasting a little more curtailment that we had before. It is relatively modest, but another 1,000 to 2,000 BOE a day of additional curtailment, that actually has an effect of depressing decline more. So we can think about 20% decline is not a bad way to think about it as about us corporately.

When I think about what 2017 looks like, you think about our oil. We were 46,000 BOE a day of oil production last year, and we are talking 43,000 to 45,000. So at the midpoint that's down 4%. We haven't specifically guided to an exit number. But we have talked about the capital profile earlier in Greg's question, and so you can think about a little bit of a steeper decline as you think on exit to exit basis.

But that said, we're going have a dozen highly prolific wells sitting in inventory where you can almost turn those on. So you blow on that capital a tiny bit then you can alleviate that. As you think to 2017, I am somewhat hesitant because if you think about the conversations we all were having a year and a half ago and about what sustaining capital was, we're dealing with completely different productivity and capital efficiencies that we ever imagined were possible.

A year ago we were thinking we had to spend CAD550 million to keep production flat -- sorry, CAD650 million to keep production flat. You know last year we spent CAD490 million, now we're talking about CAD200 million, with when you adjust for divestments, is pretty modest decline. So I don't know was it's going to look like in 2017, but I will say that the only reason it looks as good as it does for us is because we have got this incredible capital efficiency engine in North Dakota, and this incredible asset in the Marcellus, and in the absence of those it would look a lot worse for us. So we are relatively constructive on decline showing up in North America this year.

On the Marcellus specifically, there's no question we will start to spend some money as this pricing dynamic improves. We think we're going to start to see it this year. You can convince yourself it a might be a little bit longer than that, and I think you will start to see the spend increase a little bit. But we have been keeping production flat, spending CAD20 million to CAD30 million. It has been really really modest.

Sorry, what did you say about the corporate decline, was it 20%, or low 20s?

20 is a good number to think about.

Okay, thanks, Ian.

(Operator Instructions)

Patrick O'Rourke, AltaCorp Capital.

Hello. Can you hear me? Okay, perfect. In terms of a few quick questions here, but in terms of the hedging, obviously the hedges on the oil side drop off here in Q3 and Q4. You spoke, you are thinking about declines in terms of production in North America here. How are you thinking about hedging, then? Are you looking at setting higher upper bands on your callers? How are you going to go forward here?

Maybe Eric and I will Mutt and Jeff this. I would say it is a bit complicated. We have consistently hedged, and that has been based on the strategy of cash flow protection and managing risk. So, we've been quite consistent in that.

We have layered on a price view, and so when we look at our hedging this year, it is okay. It's a lot better than some, and it's got three-way collar structures on the oil is what we've used the most. That, tied to a price view that it was going to be hard for oil to average under 50 for the whole year. We didn't bet the farm on that call, but we gave up a little bit of protection with that call. To date, that isn't true. We will see what happens, but it gave us an ability to participate up to $80 and we haven't capped ourselves. So that was the structure that's underpinned it.

We're now living in this lower for longer world, and thinking about when do you start to layer on hedges, and price view will be part of that. Balance sheet is part of that. Asset sales have been part of that, as well. So I think we have certainly more flexibility than many people.

Our view is, as you start to see $40, that is going to be sold hard. If you see $50, that is going to be sold really, really hard. And I would say we haven't quite finalized our view as to when and how we're going to be layering that in. Eric, do you want to add some more to that?

Maybe on gas a little, perhaps?

Our view on gas is not dissimilar to oil. We do see a supply demand imbalance coming towards the latter part of this year. And so we're not going to rush to hedge gas at the current price levels. But exactly as Ian said, we will consider funds flow protection for the 2017 period in context, within the context of our price view. And we will be considering incremental hedges as prices move further this year.

Okay. Great.

In terms of the DUCs there in North Dakota, just something we've been watching very closely. We saw North Dakota in the director's cut production actually decline last month, while the DUCs North Dakota-wide went down by a wide margin too, the viewpoint being that the quality of the DUCs is starting to degrade.

Do you share this viewpoint, and then can you comment in terms of where you are drilling and your DUCs will be set up post, at exit of 2016 will they be more levered to the Nesson anticline-Antelope area, or will you have more of those wells more down in the southeastern part of the acreage?

We do share that view that not all DUCs will get completed. They're not all equal. Over the last year though you've seen an incredible high grading in the quality of the activity, so most of the drilling in the last year has been focused on core areas, and you're clearly seeing that come to a screeching halt.

Relative to exactly where those DUCs are, we went to quite a spartan program over a year ago, running one rig. So only one rig over the entire acreage position for about a year; and that rig moves around a little more than you'd think you'd like. As you think about drivers relative to lease retention, even drainage issues in a few little areas. So I would say of those 12 DUCs at year end, they are evenly spread over the acreage block.

Okay. And then final question here, you have about CAD50 million in capital in Canada; it looks like it's, the bulk of it is going to be directed to the water flood. Recent royalty review, they did, they haven't added specificity or any granularity. But they did mention that they are going to be looking to put water-flood incentives in place. Have you run scenario analysis on this, or had conversations? And would you delay some of this capital until you have a little bit more clarity on that?

So it is not CAD50 million of [D&C] in Canada and water flood. You've got to capitalize G&A, you've got some maintenance, you've got a whole bunch of stuff that comes into that, and some of that is already spent. So there is not a significant program. And some of that was, we've got a polymer project that started last year that was carrying over year end. So some of that is well in hand without a practical ability to slow it down.

Maybe just as a general, as a general comment on the royalty structures specific to EOR, I think most people understand there is still a lot of uncertainty with respect to Alberta royalties and where the final details will come out. There is a calibration process going on right now and our understanding is that will end by about the end of March. And that will give us more information relative to royalty structures and what capital is going to, you can get credit for what amount and type of capital.

Our expectation though is some of the more complicated areas like EOR, and some exploratory drilling, some recompletions, things that are a little more complicated, won't be dealt with by that deadline, and will be dealt with by the end of this year. So, for Enerplus, who's thinking about maybe spending more money in EOR, in a price recovery scenario, we're going to need to see those details. So we'll see where it gets to this year. But there's still a lot of uncertainty there.

Okay. Thanks.

Brian Howe, Credit Suisse.

Hi, it's actually Jason Frew here.

But either Ian or Eric, I would like to get your view, like a multi-year view, on Marcellus takeaway capacity. And where you see differentials over time. And can you envision a scenario where your Marcellus asset contributes meaningfully, or more meaningfully, to cash flow in the future?

Thanks.

The fast answer to that last part of the question is, yes we do see a world where this asset contributes significantly to cash flow. There's a few fundamental changes occurring in the region, the Northeast Pennsylvania region where we produce from.

For 2016, the industry is probably adding about a Bcf a day, a little under, and we've added some of it already of takeaway capacity. But more significantly in 2017, the number is between three and four Bcf a day of incremental takeaway. And we've tried to adjust and set those numbers according to how we see the regulatory arena playing out for some of the projects.

In terms of the differential, as we've said in our press release, we are forecasting a dollar under NYMEX for this current year. And the current forward market is right around that level, for the rest of this year and next year. We do see real potential for that differential to narrow in the actual market in 2017, as more capacity comes on stream.

Okay, thanks.

And there are no further questions in queue at this time. I now turn the call back over to Mr. Ian Dundas, President and CEO, for any closing comments.

Once again I would like to thank you for your time today and participation in the call, and I hope everyone has a nice day. Thank you. Cheers.

Ladies and gentlemen, this concludes today's conference call. You may now disconnect.