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Enerplus Corporation (NYSE:ERF)

Q4 2013 Earnings Conference Call

February 21, 2014 11:00 AM ET


Jo-Anne Caza – Corporate and IR

Ian Dundas – President and CEO

Raymond Daniels – SVP, Operations

Eric Dain – SVP, Corporation Development and Commercial

Jodi Labrie – VP, Finance


Carson Tong – RBC Capital Markets

Patrick Bryden – Scotia Bank

Cristina Lopez – Macquarie

Dirk Lever – AltaCorp Capital


Good morning. My name is Mike, and I will be your conference operator today. At this time I would like to welcome everyone to the Enerplus Corporation 2013 Year-End 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). Thank you.

I will now turn the call over to Jo-Anne Caza, Vice President, Corporate and Investor Relations. You may begin your conference.

Jo-Anne Caza

Thank you, operator. Good morning, everyone. Thanks for calling in.

This morning, Ian Dundas, our President and Chief Executive Officer will be providing an overview of our 2013 results along with our outlook for 2014. Ray Daniels, our Senior Vice President of Operations will also provide some color on our operation. We also have Eric Le Dain, our Senior Vice President of Corporate Development, Commercial and Rob Waters, Senior Vice President and Chief Financial Officer on the call with us today.

We’d like to point out that we have converted our financial reporting from international financial reporting standard to United States generally accepted accounting principles as more than 50% of our shares and more than 50% of the book value of our assets under IFRS were held in the U.S. we continue to qualify as a foreign private issuer with the Securities and Exchange Commission in the U.S. as we pass the requisite tests under U.S. GAAP.

All discussions of production volumes today is on our company working interest basis as has been our previous practice and all financial figures are in Canadian dollars unless otherwise specified. Conversions of natural gas to barrels of oil equivalent are done on a 6:1 energy equivalent conversion ratio which does not represent the current value equivalent.

Our discussion today will contain forward-looking information. Listeners are asked to review our advisory on forward-looking information to better understand the risks and limitations of this type of information. This advisory can be 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 available on our website at

Following our review we will open up the phone lines and answer questions you may have and we will also have a replay of this call available later today on our website.

With that, over to you, Ian.

Ian Dundas

Good morning, everyone. 2013 was an exciting year for Enerplus. Our clear focus on operational results and disciplined capital allocation drove profitable growth and cash flow, production and reserves with significant improvement in our cost structures. We also advanced our strategic portfolio objectives, improved our financial flexibility and the overall sustainability of the business. We delivered all of our guidance objectives for 2013 and positioned Enerplus for further success in 2014.

Our strong operating performance allowed us to increase our production guidance three times throughout the year and exceeded both the annual and exit targets we set. This is despite the sale of non-core assets that were producing just under 3,000 BOE a day. Productions grew by 9% year-over-year, 7% on a per share basis, with our oil production increasing by 5% and our natural gas production growing 15%.

We also achieved record reserve replacements, proved plus profitable reserves grew 17%, 15% on a per share basis, we also replaced 175% of our oil production and 440% of our natural gas production. This production growth and reserve replacement was achieved with a 50% reduction in our finding and development costs year-over-year. F&D cost came in at $11.28 per BOE including future development costs, based upon our 2013 operating net-back of $27.40 per BOE this represents a recycle ratio of 2.4 times. On a three year basis our F&D cost were $19.25 per BOE.

On-stream capital efficiencies were also strong at $26,000 per flowing BOE, under our 2013 targets and significantly improved over the last several years. We estimate 363 million BOE of economic contingent resources associated with a portion of our asset base at year end. This amount is essentially unchanged from last year despite reclassifying about 70 million BOE into reserves. This estimate includes contingent resource from the Marcellus, the Bakken and Three Forks, a portion of our waterflood and our Wilrich assets.

At our current production rate this contingent resource estimate can provide about ten years of organic reserve replacement. We also see potential upside to these numbers from downspacing in North Dakota, potential contribution from the lower benches in Three Forks as-well-as from the Duvernay. Ray will provide some more details on some of our delineation activities in these areas.

Strong production growth, effective cost management, combined with improved commodity prices drove fund flow 17% higher to $754 million or up 14% per share. On the portfolio front we continue to execute on our strategic plan to enhance our operational focus. We spent $245 million consolidating interest in our core areas, acquire an acreage in the Wilrich, in the Bakken as-well-as tuck-in acquisitions in our waterflood properties and in the Marcellus. These four core areas now represent over 95% of the value of the company.

We also sold non-core assets that represented 12.1 million BOE of 2P reserves along with undeveloped acreage for proceeds in 2013 of $365 million. The accretive nature of these trades resulted in an FD&A costs of $8.36 per BOE.

Growing cash flows and much too improved capital efficiencies resulted in our adjusted payout ratio improving to 114%. This combined with the deal activities further enhanced our financial flexibility and we ended the year with a trailing debt-to-fund flow ratio of 1.4 times down from 1.7 times a year ago. As we executed our strategy throughout the year the market began to take notice and we saw a decent share price appreciation. This increased combined with the dividends paid throughout the year translated into a 58% annual total return for Canadian shareholders, 48% for our U.S shareholders.

I will now turn it over to Ray to provide some additional details on our operations.

Raymond Daniels

Thanks, Ian and good morning everyone. Our capital program in 2013 was focused on delivering profitable growth while demonstrating capital discipline. Our total capital spending ended up slightly under our guidance and down 20% year-over-year. However through cost reductions and productivity improvements we exceeded our growth targets and advanced our emerging plays.

We drilled 62 net wells last year two-thirds of which were in our oil plays. 45% of our capital spending was in North Dakota where we are targeting both the Bakken and Three Forks. Our focus was on driving improvements in capital efficiencies through a reduction in drilling costs and improvement in productivity.

The most significant change in our program was the increase in the amount of proppant and number of frac stages in our completions along with a shift to white sand from ceramic proppant. In spite of increase in proppant and frac stages with our focused cost management we were able to reduce well costs on average by about $1 million per well. More significantly 30 days initial production rates increased by about 50% with the new completion design and we averaged 30,000 barrels of oil in the first month.

As a comparison the average 30 day cumulative production in 2012 was just over 20,000 barrels of oil. We continue to evolve our competitions of our two most recent Bakken wells have been completed using about a thousand tonnes of sand per lateral foot with roughly 40 frac stages. In their first 30 days these wells have produced a record of roughly 4,000 to 8,000 barrels of oil each.

We had another strong year of reserve additions in North Dakota. We replaced 400% of daily production adding 25 million BOE of 2P reserves at a cost of just under $20 per BOE. This represents a 2.7 times recycle ratio based upon an average net back of $53 per barrel in 2013. We are continuing to test those spacing and have two density tests underway. In fact it’s from one of these tests that we have the record 30 day rates I just mentioned.

We’ve drilled and cored a vertical pilot well to test the lower benches of the Three Forks in the northern areas of our lease. With positive core data we kicked off the horizontal section landing the well in a second bench and expect to rig release this well at the end of the month. This well should be completed and start flowing back by mid-April.

We are also currently drilling our third of three mile long lateral wells, completion activities on these wells be done at the end of Q2. Based upon our 2P reserves and our contingent resource estimates we have approximately a 150 future drilling locations which translates into seven years’ worth of drilling inventory at the current pace. Increased down spacing and success in the Lower Three Forks would expand this inventory. We expect to be in a position to provide an update on all our [exploration] activities later in 2014.

In Marcellus we also continue to see cost reductions and productivity improvements. Well costs decreased by approximately 20% year-over-year through more efficient pad drilling and lower costs. Our Marcellus program was focused in Bradford, Susquehanna and Sullivan counties where we continue to see the best of our results. 30 day initial production rates on wells drilled in these counties increased by almost 60% year-over-year and averaged 9.6 million cubic feet a day in 2013. Seven wells from these counties produced over 15 million cubic feet a day of natural gas during the first 30 days in production that’s nearly half a BCF per well in the first month. We currently have 11 non-op wells waiting to be tied in the Marcellus.

We also had another year of solid reserves addition in the Marcellus as a result of both of developments and acquisition activities. 2P reserves increased by a 168% to over 600 BCF of natural gas at an FD&A of $0.91 per MCF. The Marcellus now accounts for 50% of our corporate natural gas reserves.

In Canada we recently drilled and completed another two wells in the Wilrich play. Our activity to-date has focused on drilling delineation wells. We have been driving hard to reduce our costs and we have seen a 40% reduction in drilling costs across the eight wells we’ve drilled to-date. In addition through our optimization efforts completion costs are down 46%. We believe we can continue to drive down costs once we move into the development phase.

Our most recent well cost about $8 million and had a 30 day initial production rate of approximately 7 million cubic feet a day which is in-line with our 6 BCF type curve. We have also drilled and commenced completion activity on our first horizontal well in the Duvernay and just PDed a second horizontal well. We expect to be in a position to discuss our Duvernay well results later in the year.

And with that I’ll hand it back to Ian.

Ian Dundas

So looking at the year ahead, we will continue to focus on our developing on our core assets and driving strong capital efficiencies. We plan to spend about $760 million on our capital program in 2014, up about 12% from last year. 2014 transaction closings from previously announced non-core sales have generated proceeds of over $100 million since the end of the year. We plan to continue our development plans in North Dakota, the Marcellus and our waterflood and to advance our delineation activities.

Particular areas of focus over the year will be advancing our understanding of downspacing potential in both the Bakken and Three Forks as-well-as key well depths in the lower benches of the Three Forks, the Duvernay and the Wilrich.

We are targeting annual average production of between 96,000 BOE a day and a 100,000 BOE a day in 2014. We expect production to stay at 48% liquids, 52% natural gas. Although with continued out-performance in the Marcellus that could push the weighting of natural gas higher. We expect to see reduction in our per BOE operating and G&A cost in 2014.

40% of our total planned spending will be dedicated to the Bakken and Three Forks where we expect to grow production by over 30% again in 2014. Combined the Bakken and Marcellus assets will account for more than 50% of our corporate volumes.

Our largest natural gas investments will continue to be allocated to the Marcellus. We exited 2013 producing a 170 million cubic feet of gas a day which positions us well in this play as we head into this year. Now despite the tremendous operational performance we’ve seen in the Marcellus price realizations are obviously a focus area for us and industry as basin wide production growth has been very strong and has pressured regional price differentials.

In the fourth quarter Marcellus netbacks were about a $1.80 an Mcf reflecting a negative differential of $0.53 very similar to what we saw in the third quarter. And despite relatively consistent differentials in Q4 we remain cautious on base differentials over the next year or two where there a number of pipeline projects ongoing to provide future incremental takeaway capacity in the Northeast region we now believe that will fully balance supply growth within the next two years and so expect base differentials to widen through 2014 and ‘15.

For Enerplus still over half of our sales are subject to spot markets on Tennessee and Transco pipelines which have remained relatively weak compared to NYMEX. In fact these markets seem to have effectively disengaged from the NYMEX. Therefore we are now increasing our forecast Enerplus realized basis discount versus NYMEX from $0.75 per MMBTU to U.S. $1 per MMBTU for both 2014 and 2015 for our aggregate Marcellus production.

Now despite the wider basis forecast the combination of higher NYMEX pricing improving cost structures and very strong well performance has resulted in continuing strong drilling economics. In fact if economics remained strong we could see some mass increases in activity as we move through the year.

In terms of fund flow production we hedged about 59% of our expected 2014 crude oil production after royalties at $94 per barrel. We also have downside protection in place for 2014 for over 40% of our forecasted natural gas production after royalties, with the majority of this production price off of NYMEX at about $4.15 per MCF. Now with both the forward prices for crude oil and natural gas and backwardation we have minimal hedges in place for 2015.

As we see improvements in forward prices for 2015 we will look for opportunities to increase our 2015 hedge positions. With over 50% of our capital program dedicated to our U.S. assets the recent weakness in the Canadian dollar could put upward pressure on our reported capital spending as we do report in Canadian dollars. The offset to this is that the weaker Canadian dollar would obviously have a positive effect on our revenues.

Finally I am very pleased to say that Hilary Foulkes has joined our Board. Hilary is Geologist by training but with over 30 years of extensive industry experience she will be an excellent addition to the Board and I welcome her to Enerplus.

So to close it was obviously a strong 2013 and I think we are well positioned as we move into 2014. And so with that I will close and open it up to questions.

Question-and-Answer Session


(Operator Instructions). Your first question is from Carson Tong with RBC Capital Markets. Your line is open.

Carson Tong – RBC Capital Markets

Hi, thanks and good morning. Just two quick questions from me. Give us color on Enerplus’ takeaway capacity under the marketing dollars. And my second question is around the corporate decline rates. Can you remind us what it was for 2013 and what you expected to be in 2014? Thanks.

Ian Dundas

Sure I’ll start with decline. So as we entered 2013 we were forecasting decline in the 23% to 24% range. As we rolled our guidance coming out of 2014 coming at 2013 we talked about going to potentially 25% that increased pretty modest\driven by some of the ramp up in the Marcellus. On the takeaway issue it’s probably a little broader than just takeaway. Maybe I’ll turn it over to Eric Le Dain to give you a little more color on broadly what we are doing over there.

Eric Dain

Sure on the – in terms of takeaway we have roughly 50% of production that has – is marketed directly to downstream units that have the capacity on the interstate pipeline grid. The remainder of our production and a good portion of which came with our recent acquisition is marketed at the spot points on Tennessee and Transco pipeline. I will take it as silence is a good answer.

Ian Dundas

We have some details on our investor materials to give a little more color on some specifics and delivery points like that.


Your next question is from Patrick Bryden with Scotia Bank. Your line is open.

Patrick Bryden – Scotia Bank

Good morning everyone just curious if you may be able to the comment on Q4 transportation cost in terms of magnitude was the amount related to the conversion in U.S. GAAP or is there more read through in terms of the puts and takes in terms of differentials in activity with transportation in the quarter?

Ian Dundas

I’ll turn that over to Jodi Jenson, is our VP of Finance to give you some color on that, Pat.

Jodi Labrie

Sure yeah they did go up a little bit. We had a little bit more unmitigated demand charges in both the Marcellus and in the North Dakota area as well as the increased production in the U.S.

Patrick Bryden – Scotia Bank

Okay, great. And then just on the U.S. in North Dakota I am not sure if it’s possible to try to help us characterize where the inventory could go over you’ve mentioned 150 locations and about seven years at current pace. Are you able to provide any color in terms of running room, should we see play extension through the Three Forks benches or downspacing initiatives? Thanks.

Ian Dundas

Yeah I can give you some color there Pat. So the 150 wells that ties to our 2P reserves and our contingent resource. What the assumptions that are imbedded in that inventory is effectively a fully developed Bakken section based on two wells per zone on the vast majority of the land. And then two wells in the first bench of Three Forks, just under half of the land and then nothing with other benches.

So what are other people saying? Other people are saying you might see up to four wells in any particular zone where it’s productive. And so just using that simple math you more double the inventory into those assumptions. And then on the lower benches I would tell you it’s not reasonable to think that we will have lower bench prospectivity over our acreage block, we do not believe that’s the case.

We do believe we’ll see some. I think a conservative estimate is may be 10% to 15% of our acreage is somewhat likely but we’ll have more information on that as we move though the year.

The other thing I will leave you with too though in terms of those upper-end [loose tie] kind of scenarios many, much of the data out there when people are talking about down spacing is based on areas that don’t appear to be as perspective as our areas. And so that presumably had some type of implication on maybe not needing as much of a well density to get that. Actually the data is pretty supportive that we’re feeling pretty good, there’s upside on the base scenarios now.

Patrick Bryden – Scotia Bank

Great and then just lastly from me, on the Duvernay I appreciate the comment that you are more interested in updating later in the year on what your progress is there but would it be possible to get some kind of elaboration on what you would hope to see at [vern] and a sense of expectations if possible please?

Ian Dundas

Sure so two wells planned as Ray said we’re in completion activity on one of them right now at the Northern areas of our acreage block. We’re really looking for two things, one is productivity but may be more importantly is liquids content. And so our goal would be to I guess start to establish the high end of type curves hopefully something over 100 barrels per million on the – in terms of free condensate at the well head and on a solid gas rate.

So those are the things that we are hoping for. In terms of the time tables as you’ve been achieving carefully some of the operational things that have evolved in many of the shales but particularly the Duvernay industry is bringing these wells on very slowly with relatively extensive soak time. And so that could be mid-year time to start before we get any kind of information.

But again the technical information that we’re looking for is in furtherance of our the high end of our type economics and then if we get those let’s say the good well economics then we are going to be in a position to think about what next steps are for that play in a success scenario we’ll have some choices available as to how we move forward on that play, I think.

Patrick Bryden – Scotia Bank

Great thank you.


Your next question is from Cristina Lopez with Macquarie. Your line is open.

Cristina Lopez – Macquarie

Hey guys, a lot of my questions have been answered. But with respect to guidance, obviously the gas weighting was a bit higher in Q4, no change to your goal for 2014 guidance at this time, but given the productivity out of the Marcellus, do you expect to see that gas ratings to shift a little bit to be a little bit more gassy through the course of this year?

Ian Dundas

I think it could, yeah I think it could. It really is going to tie to mostly to Marcellus performance and we came in to the year as you said strong. A few things contribute to it, but mostly it was well out performance and so we’ll see if that hangs in. It’s looking pretty encouraging right now but that could put upward pressure is the right word, but I guess that’ll put pressure on gas weighting. And then we feel that unfolds as we come through the first quarter, I guess.

Cristina Lopez – Macquarie

And then upward gas weighting does that come with what’s been incremental production and then say potentially also beating your production guidance at this point?

Ian Dundas

Well that would be excellent.

Cristina Lopez – Macquarie

And then finally with the North Dakota, obviously weather has been a concern for many North Dakota operators so far this year. Any thoughts on any delays that you guys are experiencing in as a result of the cold weather?

Ian Dundas

The production – weather has been a bear throughout North America. It actually started really early in, really in December, that’s when it first started to show up. It affected in North Dakota, it affected Canadian operations, Marcellus to a lesser extent, when we built our guidance we knew we’re heading into a tough winter and have accounted for that so, the specific answer is yes, it has affected operations, it has slowed things, it has resulted in some modest cost increases, a bit modest but I think we have cushions in contingencies and had plans for all of that so we’re back to the guidance question. We’re feeling comfortable with where we’re in guidance.

Cristina Lopez – Macquarie

And then as far as the downspacing goes, I’m sorry Ray if I missed that one, when you stated, when you expected to have results from the two pads. Can you remind me as to when those when we would be expecting those type of results?

Raymond Daniels

Yeah, on the Fur Bearers pad we got production going just now, and on the Snakes Pad it will be later in the quarter and so by the middle of the year we’ll have an idea of where we think that may take us in terms of looking at those basin in a larger scale.

Ian Dundas

Cristina, there is growing samples that are out there in inventory and I would say generally speaking in most areas people have been encouraged that on initial rates there hasn’t been much if any depletion and then maybe some mix performance depending on the areas as people have moved for longer run times in production.

But I think generally speaking the down space tests have been pretty favorable but we are really in a highly productive prolific area and some of the other tests are in the areas that are a little bit tighter and not as robust. So I think at the end of the year we’ll feel more comfortable through combination of our data and what others have done and really started to do early last year actually.

Cristina Lopez – Macquarie

And sort of for that Fur Bearers pad are you starting to see pressure, any sort of pressure depletion at all or that you were saying that from some other operators that they haven’t seen a depletion early on? So you’re still seeing high pressure even the downspaced wells as you would have expected?

Raymond Daniels

These wells are holding up pretty well and we’re pleased with the results that we’ve got Cristina. And as I said when I was talking both of these Bakken wells and the Three wells tests have been record producers in the first month 48,000 barrels a day. So we are very encouraged by the results we are seeing in that area of our land.

Cristina Lopez – Macquarie

Perfect. Thank you so much for your time.


(Operator Instructions). The next question is from Dirk Lever from AltaCorp Capital. Your line is open.

Dirk Lever – AltaCorp Capital

Thanks very much. Congratulations on a great year. Actually I was going to ask on guidance but since Cristina hit it, I’m good thank you.

Ian Dundas

Thanks, Dirk.


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

Ian Dundas

Well, thank you for your attendance today. We’ll end the call now and allow people to go turn on Hockey game that I understand is coming relatively soon. So thank you very much.


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

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