Enerplus Corporation. (ERP) Q4 2015 Earnings Conference Call February 19, 2016 11:00 AM ET
Drew Mair - Investor Relations
Ian C. Dundas - President and Chief Executive Officer
Jodi Jenson Labrie - Senior Vice President and Chief Financial Officer
Ray J. Daniels - Senior Vice President of Operations
Eric Le Dain - Senior Vice President of Corporate Development Commercial
Greg Pardy - RBC Capital Markets, LLC,
Kyle Preston - National Bank Financial
Patrick O'Rourke - AltaCorp Capital
Jason Frew - Credit Suisse
Good morning, my name is Melisa and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus Corporation 2015 Fourth Quarter and Year-end Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers remark, there will be a question-and-answer session. [Operator Instructions] Thank you. I would now like to turn the call over to Mr. Drew Mair, Manager of 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 described 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 the U.S. 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, Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer, Ray Daniels, Senior Vice President of Operations and Eric Le Dain, Senior Vice President of Corporate Development Commercial. Following our discussion we will open up the call for questions
With that, I'll turn the call to Ian.
Ian C. Dundas
Good morning, everyone and thanks for joining us today. We just announced operating results that continue to demonstrate 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 target for safety, regulatory and environmental performance. I'll talk about some of our key achievements in 2015 and how these are better position to Enerplus as we move forward.
Under a significantly reduced capital budgets, 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've worked hard to reduce our cost structures and we continue to do so across all the areas of our operations.
In North Dakota specifically we saw a meaningful improvement in our all-in well cost 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 continue to focus our portfolio and right size our organization for the environment we find ourselves in.
Our operating performance also translation into another strong reserve story this year. We've replaced 108% of production through the drill it, but more important this occurred at highly competitive finding and development costs of $8.44 per BOE. We believe this is particularly significant given that reserve additions and revisions were 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 divestments 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 totaled 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 net back given the higher relative operating cost of the assets, but we also significantly reduces our abandonment obligations.
Looking forward, today we announced further reductions in our 2016 spend. Our capital program for 2016 is now forecasted $200 million down 40% from our current 2016 guidance and 60% lower than our 2015 spend. In addition, we are reducing our monthly dividend to $0.01 per share per month, representing a savings of approximately $37 million to 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 at 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'll now ask Jodi to comment on our financial highlights.
Jodi Jenson Labrie
Sure, thanks Ian. Our continued focus on cost resulted in full-year operating expenses of $8.76 per BOE, which was below our guidance of $9 per BOE and 10% below our original 2015 guidance. In 2016, we intend to continue to drive cost down. However, with production levels are lower and production mix more heavily related to oil our operating costs are expected to $9.50 per BOE.
G&A was another area where realized significant cost savings during 2015. Annual G&A expenses were $2.09 per BOE coming in below our revised guidance of $2.20 per BOE and 13% below our original 2015 guidance despite $11.5 million in one-time severance cost. However, 2016 as when we really start to see the benefits of our cost savings initiative, we expect on an absolute basis cash G&A to be down approximately 15% year-over-year, but on a BOE basis it is eventually flat at $2.10 per BOE again due to lower production levels in 2016.
Fund flow for the fourth quarter was $103 million or $0.50 per share and for the full-year funds flow is $493 million or $2.39 per share. This was supported by our commodity risk management program, where we realized cash gains of $288 million during 2015. We incurred an asset impairment charge during the fourth quarter of $266 million and for the full-year $1.4 billion both before tax.
Unlike IFRS accounting, U.S. 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-months trailing price to decline further during the first quarter of 2016, which may lead to additional impairment. It is important to note that this impairment reduces our earnings, but it does not impact our funds flow. In addition, because we report using U.S. GAAP, these impairments are not reversed in future periods when commodity prices recovered.
We ended the year with total debt net of cash of $1.2 billion, which was an increase of $80 million over 2014. This increase was entirely due to the effect of the weakening Canadian dollar on our U.S. senior notes. We repaid approximately 103 million of our senior notes during the years an increased the amount drawn our bank credit facility by a modest $6.6 million.
As we look forward into 2016, our top priority is keeping the balance sheet strong. At current commodity prices, our capital program s and dividends are more than fully funded by funds flow and our Deep Basin divestment proceeds of $193 million. Furthermore, we expect to repay between $100 and $115 million in debt throughout the year.
Although we have no scheduled debt repayment on our U.S. senior notes until June of 2017. In January, we made an offer to purchase a portion of our senior notes and were able to retire approximately 80 million or 57 million U.S. at a discount par, which further improves our leverage ratios.
Finally, a few words on our debt covenants, at year-end we were in compliance with all of our covenants, our most restricted covenant which was 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 three times. Based on our forecast prices for 2016 of approximately $39 per barrel WTI and $2.40 per 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 asset.
Typically under forecast accounting, you would not recognize gains and losses. However, in the event that a disposition significantly alters the relationship between the book value on financial statement improved reserves U.S. GAAP requires that a gain or loss to be recorded at 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 $145 million in the first quarter, which will be included in earnings EBITD. However, a word of caution, if the current commodity price environment persist, we would expect start taking steps to renegotiate our covenants with our lenders towards the end of 2016. Over all though we have been able to maintain our financial flexibility and continued to remain in a relatively strong financial position.
I'll now turn the call over to Ray to speak about operations.
Ray J. Daniels
Thanks, Jodi. I'll be grief, but the key message I would like to give across is that our asset continues to perform very well. I'm 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 as such 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 four net wells on-stream. Our well deliverability in North Dakota remains top deciles and our costs are continuing to come down.
Current all-in drilled complete and tie-in cost including facilities are approaching $9 million U.S. One of the drivers for reducing of 2016 capital budget to preserve the value of our inventory and North Dakota wells are prolific. Our average well in 2015 delivered in excess above 100,000 barrels of oil in under four months. We believe it is prudent to the defer more of these wells until commodity prices have improved.
It was just in mind that we have reduced the number of completions in 2016 by around 40% relative 2015 that ends up being around 14 provisions 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 $4.5 million in the fourth quarter and less than $8 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 static production with low levels of activity. In Canada, the spending will be directed toward waterflood development and optimization activities.
And with that, I'll past the call to Eric to speak about our hedging activities and pricing outlook.
Eric Le Dain
Thanks, Ray. Our commodity hedges will continue to protect funds flow in 2016 although not to the same extent with they did in 2015. On average in 2016, we have 11,000 barrel per day of oil hedged and 62,500 Mcf per day of our natural gas hedged to a combination of swaps and three-way collars. Please refer to our news release or MD&A for details on our hedge portfolio.
Our U.S. Bakken realized differential at the aggregate of the field sales point averaged just below U.S. $7 of barrel during the fourth quarter before trucking and gathering. We are forecasting a similar U.S. $7 of barrel differential to WTI for 2016. Our realized Marcellus gas pricing in the fourth quarter averaged a $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 at prices closer to NYMEX for U.S. $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 level better balanced with the regional takeaway capacity being added in 2016 and 2017.
As a result, we are guiding to a basis differential of U.S. $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.
Ian C. Dundas
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 or cost structures, operational excellence and an unwavering focus on safe and sustainable operations remain our priorities for 2016.
And with that, I would turn the call over to the operator and we will open it up for any questions you may have.
[Operator Instructions] Our first question comes from [Lima Bulu with Reuters Investment Research] (Ph). Your line is open.
Good morning. I appreciate you guys are getting ahead of the covenants, but with the natural gas sale, looking where you ended in 2015, I just want to confirm that it's only if the currency depressed commodity environment persist for the full-year then you would potentially - or you would have to entrance negotiations late in the year, because post that sales of those gas assets which were at a good price, the adjustments in the dividend would seem that if commodity prices rebound even modestly than you would be on size to the debt to EBITDA covenants
Jodi Jenson Labrie
Yes, base on our price view that we based our guidance on is a $39 WTI, we would be okay for the whole year. However, I just feel as that drops off in Q1 of 2017 and we add with 2017, we would be looking at our March 31, deadline sort of things.
So, it's only because it extend into 2017 and it goes lower to the 3.0 level where you wouldn’t have to enter into this then.
Jodi Jenson Labrie
Well, it's a 12-month trailing calculation.
Ian C. Dundas
And as you highlight, we obviously have a lot of talk to commodity prices and very small changes move these number around the forecast prices that we use 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 sales of those assets, you are really not suffering much of a production decline, but just wanted to get a sense where would the rationale 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 it wouldn't be your production U.S. assets, but just sort of run through the logic of where that spending was cut back first that would be helpful?
Ian C. Dundas
You're talking about reconciling from our 350 million guidance, to our current 200.
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 for - what regions were targeted first or is it just broad-based and evenly cut across the Board in terms of your product mix?
Ian C. Dundas
So I guess let’s remember where we were at the 350 level, the 350 level is 90% focused and lion share of that was in North Dakota. And so as we roll forward a couple of things that happened, one is the [Wilworth] (Ph) sale. So we didn't have a dramatic on the spend there, but there would have been some in the Wilworth, so that's sort of come up out of the mix.
We also are now maybe somewhat surprisingly to us seeing a little more cost improvement than we would have anticipated in November. As Ray talked we're now floating with a $9 million well cost in North Dakota and that's not where we would have been a year ago, so there is a little bit of improvement that has come from that.
And then on the activity side, it's largely out of North Dakota, there is a little bit in Canada, some of the waterflood activity, but largely it's 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 we're talking about 14. So that’s sort of where things that sort of takes you through to.
And my final question on North Dakota. Can you give a sense because we don't always have the best sense. Is there still a heavy discount on North Dakota oil, are you still suffering from discounts in that region, like 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 discounts narrowing to WTI?
Ian C. Dundas
Let me turn that over to Eric to give you a little more color on that.
Eric Le Dain
Sure, the current differentials we see are in the U.S. $7 a barrel range against WTI. Yes, there is still descent level of 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 now you constructed, do you see because you are on the ground and you're seeing the activities 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 sign?
Eric Le Dain
The published on North Dakota production is showing a decline in production for the industry as a whole. We've seen - part of the background on the differential improvement is we thought more than ample take away in terms of rail and pipeline from the industry and that is actually some of rail tolls that are being discounted to realize that tighter differential.
Thank you very much.
Your next question comes from the line Greg Pardy with RBC Capital Markets. Your line is open.
Just a couple of questions for me, wondering Ian could you just give us a sense as to how the capitals are going to weighted over the quarters and then secondly maybe outside of your non-core Bakken position, are there any other assets you would be looking to sell this year? Thanks.
Ian C. Dundas
Sure, as we continue to cut, it increasingly becomes frontend loaded since your now past January and February. So when I think about that capital spend, we're talking about call it close to half in the first four months, I mean that’s sort of the way that lines up and then starting fall over back of the year with not a lot in Q4. And we'll be nimble in connection with that as we have last year. If we see $20 oil in Q2 be a few less completions then we're thinking about right now, so we do have an ability to move relatively quickly on that. But it's for sure pretty heavily frontend 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 then teams are focused on optimizing those assets and driving costs of those, but when opportunities present themselves through the little things, we take advantage of that. We've been very careful in not counting on it because it such a difficult A&D market with such a dramatic bid ask spread but that's one of the reasons that I think we've been so successful in unlocking what arguably are above market metrics on some more recent trades.
Okay that's great, maybe just to follow up for Ray, what was the duct count at the end of 2015, just in the North Dakota?
Ray J. Daniels
Did you see duct there?
Yes, just obviously you've drilled but not either proceeded or tied in.
Ray J. Daniels
Yes, we had nine drilled uncompleted well at the end of 2015.
Okay, perfect. Okay thanks very much.
Your next question comes from the line of Kyle Preston with National Bank. Your line is open.
Ian, I know it's probably a little bit too early to talk about 2017, but just wondering if can you give us some context around where you expect production to exit the year, what happens to your Deep line profile with this capital program executed this year-end. And also if you would anticipate more on Marcellus drilling in 2017 as some of those bottlenecks get relief with there?
Ian C. Dundas
Hey Kyle, while you answered your own questions a little bit, a 2017 is long ways away. That said, I guess a couple of themes here. The softening decline is an outcome of this and for us it gets impacted a little bit also by the curtailment in the Marcellus, that's what we've been talking about it too much, but we are forecasting a little more curtailment than we had before. It's relatively modest, but another 1,000 to 2,000 BOE a day of addition curtailment that actually has an effective depressing decline more.
So we can think about 20% decline it’s not a bad way to think about it 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're talking 43,000 to 45,000, so at the mid-point that's down 4%, we haven't specifically guided to an exit number, but when we had talk with 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 to have a doesn't highly prolific wells sitting in inventory where you can almost turn those on. so you blow on that capital at tiny bit, then you are going to alleviate that. As you think to 2017, I'm somewhat hesitant because if you think about conversations we all were having year and half a ago in about what sustaining capital was. We're dealing the completely different productivity and capital efficiencies than we ever imagined were possible.
A year ago, we were thinking we had been $550 million to keep production flat - 650 to keep production flat. Last year we spent 490, now we are talking about 200 million within adjustment investments, pretty modest decline. So I don't know what 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've got this incredible capital efficiency engine in North Dakota and this incredible asset in the Marcellus. And in the absence of those it will look lot worst for us. So we are relatively constructive on decline showing up in North America this year.
On the Marcellus specifically, there are not questions we'll start to spend some money as this pricing dynamic improves. We think, we're going to start to see it this year, you could commence yourself it might be a little bit longer than that and I think you'll start to see the spend increased a little bit, but we've been keeping production flat spending $20 million to $30 million, it's been really, really modest
Sorry, what did you say about the corporate decline, was its 20% or low 20s?
Ian C. Dundas
20% is a good number to think about.
Okay. Thanks Ian.
[Operator Instructions] Your next question comes from the line of Patrick O'Rourke with AltaCorp Capital. Your line is open.
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 guys are thinking about decline in terms of production in North America here. How are you thinking about hedging and are you looking at setting higher upper bands your collars, how are you going to go forward here?
Ian C. Dundas
Maybe Eric and I'll will mutt and jeff this, I would it's a bit complicated, we have consistently hedged and that is based on strategy of cash flow protection and managing risks. So we've been quite consistent with that. We have layered on a price view and so when you look at our hedging this year, it's okay, it's a lot better than some and it's got three-way collars structure as well as we've used the most. That’s tied to price due that it was going to be hard for oil to average under $50 for the whole year.
We didn’t get the farm on that call, but we gave up a little bit of protection with that call; to-date that isn't true, we'll see what happens, but it gave us an ability to participate up to $80 that we hadn't capped ourselves. So that was sort of the structure that's underpinned. I think we're all now living in this lower for longer world and thinking that when do you start to layer on hedges and price due 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 we start to see $40 that's going to be sold hard if you see $50 that's going sold really hard and I would say we haven't quick finalized our view as to when and how we are going to be layering that in. Eric, do you want to add some more to that may be on gas a little perhaps?
Eric Le Dain
Well, our view on gas is not dissimilar to oil. We do see a supply demand imbalance coming towards 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 for protection for the 2017 period in content within the context of our price view and we will be considering incremental hedges as prices move further this year.
Okay great and in terms of the ducts there in North Dakota just something that we've been watching very closely, we saw North Dakota in the directors' type production actually declined last month. Well the ducts North Dakota wide went down by a wide margin too and as the view point being that the quality of the ducts is starting to degrade. Do you guys share that viewpoint and then can you comment in terms of where your drilling and your ducts will be set up, at the exit of 2016, will they be more levered to the [indiscernible] area or will you have more of those wells more down in the southeastern part of the acreage?
Ian C. Dundas
We do share that view that not all ducts will get completed they are not all equal. I mean 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 - you have been focused on core areas and you are clearly seeing that come to a screeching halt. Relative to exactly where those ducts are we went to quite 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 think you would like. As you think about drivers relatively to at least retention, even drainage issues in the few little areas. So I would say of those 12 ducts at year-end they are sort of evenly spread over to the acreage block.
Okay and then final question here, you guys have about $50 million in capital in Canada, its looks like the bulk of it's going to be directed to the waterflood. Recently royalty review they - they haven't added specificity or any granularity, but they did mention that they're going to be looking for waterflood in center 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?
Ian C. Dundas
So it's not 50 million of D&C in Canada in waterflood, you have got capitalized G&A, you’ve got some maintenance, you've got a whole bunch of stuffs that comes into that and some of that already spent. So there isn't a significant program and some of it was we've got a polymer project that started last year that was carrying over yearend. So some of that is well in hand without a particle ability to slow down. Maybe just as a general comment on the royalty structure specific to EUR. 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 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 - for what amounting type of capital. Our expectation though is some of the more complicated areas like EUR and some exploratory drilling, some recompletions, and things that are 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 is thinking about maybe spending more money in EUR and 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 is still a lot of uncertainty there.
Okay. Thanks guys.
Ian C. Dundas
You are welcome.
Your next question comes from the line of Ryan Ho with Credit Suisse. Your line is open.
Hi, it's actually Jason Frew here, but either Ian or Eric, would like to get your view, like a multiyear view on Marcellus’ takeaway capacity and where you see differentials overtime? And can you envision a scenario where your Marcellus asset contributes meaningfully or more meaningfully to cash flow in the future? Thanks.
Eric Le Dain
The fast answer to that last part of the question is yes, we do see a world whether this asset contributes significantly to cash flow. There is few fundamental changes occurring in the region, the Northeast Pennsylvania region where we produced from, for this 2016 the industry is 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 an incremental takeaway.
And we 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 differentials as we've said in our press release, we are forecasting a $1 under NYMEX for this current year and the current forward market is right around that kind of 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 is more capacity comes on stream.
And there are no further questions in queue at this time. I'll now turn the call back over to Mr. Ian Dundas, President and CEO for any closing comments.
Ian C. Dundas
Well, just once again I would like to thank you for your time today and participation in the call and hope everyone has nice day. Thank you cheers.
Ladies and gentlemen this concludes today's conference call. You may now disconnect.
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