Enerplus Corp (ERF) 2013 Q4 法說會逐字稿

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.

(Operator Instructions)

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

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, 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 would like to point out that we have converted our financial reporting from International Financial Reporting Standards 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 US. We continue to qualify as a foreign private issuer with the Securities and Exchange Commission in the US, we pass the requisite test under US GAAP.

All discussion of production volumes today is on a 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 or barrels of oil equivalent are done on a 6-to-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 enerplus.com. Following our review, we will open up the phone lines and answer questions you may have. We will also have a replay of this call available later today on our website. With that, over to you, Ian.

Good morning, everyone. 2013 was an exciting year for Enerplus. Our clear focus on operational results and disciplined capital allocation drove profitable growth in cash flow, production, and reserves with significant improvements 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 our 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. Production 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 a record reserve replacement, proved plus probable 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 costs came in at CAD11.28 per BOE, including future development costs. Based upon our 2013 operating netback of CAD27.40 per BOE, this represents a recycle ratio of 2.4 times. On a three-year basis our F&D costs were CAD19.25 per BOE. On-stream capital efficiencies were also strong at CAD26,000 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 Waterfloods, and our Wilrich assets.

At our current production rate, this contingent resource estimate could provide about 10 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 the 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 funds flow 17% higher to CAD754 million, or up 14% per share.

On a portfolio front, we continued to execute on our strategic plan to enhance our operational focus. We spent CAD245 million consolidating interests in our core areas, acquiring 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 CAD365 million. The accretive nature of these trades resulted in an FD&A cost of CAD8.36 per BOE.

Growing cash flows and much 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-funds 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 increase, combined with the dividends paid throughout the year, translated into a 58% annual total return for Canadian shareholders, 48% for our US shareholders. I will now turn it over to Ray to provide some additional details on our operations.

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 drove 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 our 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 the increase in proppant and frac stages, as our focused cost management, we were able to reduce our costs on average by about CAD1 million per well. More significantly, 30-day initial production rates increased by about 50% with a 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 continued to evolve our completions. Our two most recent Bakken wells have been completed using about 1,000 pounds of sand per lateral foot, with roughly 40 frac stages. In their first 30 days, these wells have produced a record of roughly 48,000 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 netback of CAD53 per barrel in 2013.

We are continuing to test downspacing and have two high-density tests underway. In fact, it is from one of these tests that we have the record 30-day Cum rates I just mentioned. We've drilled and cored our vertical pilot hole 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 a third of three 3-mile long lateral wells. Completion activities on these well will be done at the end of Q2. Based upon our 2P reserves and our contingent resource estimates, we have approximately 150 future drilling locations, which translates into seven years worth of drilling inventory at the current pace. Increased downspacing and success in the lower Three Forks would extend this inventory. We expect to be in a position to provide an update on all our Fort Berthold activities later in 2014.

In Marcellus, we also continue to see cost reductions and productivity improvement. Well costs decreased by approximately 20% year-over-year through more efficient pipe drilling and lower costs. Our Marcellus program was focused in Bradford, Susquehanna, and Sullivan Counties where we continued to see the best well 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 0.5 Bcf per well in the first month.

We currently have 11 non-op wells waiting to be tied in, in the Marcellus. We also had another year of solid reserves addition in Marcellus as a result of both of our development and acquisition activities. 2P reserves increased by 168% to over 600 Bcf of natural gas at an FD&A of CAD0.91 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 have seen a 40% reduction in the 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 CAD8 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've also drilled and commenced completions activity on our first horizon well in the Duvernay, and just TD'ed a second horizontal well. We expect to be in a position to discuss our Duvernay well results later in the year. With that, I will hand it back to Ian.

In looking at the year ahead, we will continue to focus on developing our core assets and driving strong capital efficiencies. We plan to spend about CAD760 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 CAD100 million since the end of the year. We plan to continue our development plans in North Dakota, the Marcellus, and our Waterfloods, 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 tests 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 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 weighing of natural gas higher. We expect to see a reduction in our per-BOE operating and G&A costs 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 over 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 have 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 CAD1.80 an MCF, reflecting a negative differential of CAD0.53, very similar to what we saw in the third quarter. Now, despite relatively consistent differentials in Q4, we remain cautious on base differentials over the next year or two.

While there are a number of pipeline projects ongoing to provide future incremental takeaway capacity in the northeast region, we do not believe they will fully balance supply growth within the next two years, and so expect base differentials to widen through 2014 and 2015. For Enerplus, just over half of our sales are subject to the 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 $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 remain strong, we could see some modest increases in activity as we move throughout the year. In terms of fund flow production, we've 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 protection priced off of NYMEX at about $4.15 per MCF.

Now, with both the forward prices for crude oil and natural gas in backwardation, we have minimal hedges in place for 2015. As we see improvements in the 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 US 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 affect on our revenues.

Finally, I am very pleased to say that Hilary Foulkes has joined our Board. Hilary is a geologist by training, but over 30 years of extensive industry experience. She will be an excellent addition to the Board. I welcome her to Enerplus. So in close, it was obviously a strong 2013, and I think we are well positioned as we move into 2014. With that, I will close, and open it up to questions.

(Operator Instructions)

Carson Tong with RBC Capital Markets.

Hi. Thanks and good morning. Two quick questions for me. Give us color on Enerplus' takeaway capacity out of the Marcellus.

And my second question is around corporate decline rates. Can you remind us what it was for 2013 and what you expect it to be in 2014? Thanks.

Sure. Let's start with decline. As we entered 2013 we were forecasting decline in the 23% to 24% range. As we rolled out our guidance coming out of 2013, we talked about it going to potentially 25%. That increase, pretty modest. Sort of driven by some of the ramp-up in the Marcellus.

On the takeaway issue, it is probably a little broader than just takeaway. Maybe I will turn it over to Eric Le Dain to give you a little more color on broadly what we are dealing with there.

Sure. On the terms of takeaway, we have roughly 50% of our production that has -- is marketed directly to downstream users that has the capacity on the interstate pipeline grid. The remainder of our production, a good portion of which came with our recent acquisition, is marketed at the spot points on Tennessee and Transco pipeline.

We will take it as silence is a good answer. We have some details on our investor materials that give a little more color on some specifics and delivery points and all there.

Patrick Bryden with Scotiabank.

Good morning, everyone. Just curious if you might be able to comment on Q4 transportation costs in terms of magnitude. Was the amount related to the conversion to US GAAP, or is there more read-through in terms of the puts and takes in terms of differentials and activity with transportation in the quarter?

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

Sure. Yes, 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 US.

Okay. Great. And then, just on the US side in North Dakota. I am not sure if it is possible to try to help characterize where the inventory could go, but you had mentioned 150 locations in about seven years at current pace.

Are you able to provide any context of running room? Should we see play extension through the Three Forks benches or down-spacing initiatives? Thanks.

I can give you some color there, Pat. So, the 150 wells, that ties to our 2P reserves and our contingent resource. The assumptions that are embedded 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 the Three Forks at just under half of the land, and then nothing for the lower benches.

So, what are other people saying? Other people are saying you might see up to four wells in any particular zone where it is productive.

And so, just use that simple math, you double -- you more than double the inventory into those assumptions. And then on the lower benches, I would tell you it is not reasonable to think that we will have lower bench prospectivity over our whole acreage block.

We do not believe that is the case. We do believe we will see some. I think a conservative estimate is maybe 10% to 15% of our acreage is somewhat likely, but we will have more information on that as we move through the year.

The other thing I will leave you with too, though, in terms of those upper end, loose guide scenarios, 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. That presumably has some type of implication on maybe not needing as much of a well density to get there. But I would say the data is pretty supportive, that we are feeling pretty good there is upside on the base scenarios now.

Great. And then lastly for me, on the Duvernay I appreciate the comment that you are more interested in updating later in the year on which progress is there. Would it be possible to get some kind of elaboration on what you would hope to see or learn, and a sense of expectations, if possible, please?

Sure. So two wells planned. As Ray said, we are in completion activity on one of them right now. At the northern areas of our acreage block, we are really looking for two things. One is productivity, but maybe more importantly is liquids content.

And so our goal would be to, I guess start to establish the high end of our type curves. Hopefully something over 100 barrels per million in terms of free condensate at the wellhead and on a solid gas rate. So those are the things that we are hoping for.

In terms of the timetables, if you've been watching really carefully some of the operational things that is have evolved in many of the shales, but particular the Duvernay, industry is bringing these wells on very slowly with a relatively extensive soak time. So that could be mid-yeary kind of stuff before we get any kind of information. But again, the technical information that we are looking for is in furtherance of the high end of our type economics.

And then if we get those, let's say the good well economics, then we're going to be in a position to think about what next steps are for that play. And in a success scenario, we will have some choices available to us as to how we move forward on that play, I think.

Great. Thank you.

Cristina Lopez with Macquarie.

Hello, 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 go-forward 2014 guidance at this time, but given the productivity out of the Marcellus, do you expect to see that gas weighting start to shift a little bit to being a little more gassy through the course of this year?

I think it could. Yes, I think it could. It really is going to tie mostly to Marcellus performance, and we came into the year, as you said, strong. A few things contribute to it, but mostly it was well out-performance.

So, we will see if that hangs in. It is looking pretty encouraging right now. But that could put upward, I don't know if pressure is the right word, but put, I guess upward pressure on that gas weighting. And then we will see how that unfolds as we come to the first quarter, I guess.

And that upward gas weighting, does that come with, then, incremental production? And then saying potentially also beating your production guidance at this point?

Well, that would be excellent.

(Laughter) and then finally with 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 have been experiencing as a result of the cold weather?

Weather has been a bear throughout North America. It actually started really early -- really in December. That is when it first started to show up.

It effected North Dakota, it affected Canadian operations, Marcellus to a lesser extent. When we built our guidance we knew we were coming 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.

I say modest, but we have cushions and contingencies and had plans for all that. So we're back to the guidance question. We are feeling comfortable with where we are in guidance.

And then as far as the down-spacing goes. I am sorry, Ray, if I missed it when you stated when you'd expect to have results from the two pads. Can you remind me as to when we would be expecting those types of results?

Yes. On the [four-bearer] we've actually have production going just now. And on the [snake's] pad it will it be later in the quarter. And so by the middle of the year we will have an idea of where we think that might take us in terms of looking at down-spacing in a larger scale.

Christina, there is a growing sample set out there in inventory. 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 mixed performance, depending on the areas, as people have moved forward with 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. Some of the other tests are in areas that are a little bit tighter and not as robust. So I think at the end of the year we will feel more comfortable through the combination of our data and what others have done, and really started to do early last year, actually.

And sort of for that four-bearer pad, are you starting to see pressure, any sort of pressure depletion, at all? Or is it like you were saying, from some other operators that they really haven't seen that depletion early on? Are you still seeing the high pressures in the down-spaced wells as you would have expected?

These wells are holding up pretty well. And we are pleased with the results that we have got, Christina. As I said when I was talking, both of these Bakken wells in the three-well tests that we've got going have been record producers in the first month at 48,000 barrel a day. So we are very encouraged by the results that we are seeing in that area of our land.

Perfect. Thank you so much for your time.

(Operator Instructions)

Dirk Lever with AltaCorp Capital.

Thanks very much. Congratulations on a great year. Actually, I was going to ask on guidance, but since Christina hit it, I am good. Thank you.

Thanks, Dirk.

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

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

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