Enerplus Corp (ERF) 2014 Q4 法說會逐字稿

Good morning, ladies and gentlemen. Thank you and welcome to the Enerplus Corporation year-end 2014 results call. All lines are currently in a listen only mode. After the speakers' remarks, there will be an opportunity for questions and answers.

(Operator Instructions)

I would like to now turn the call over to Jo-Anne Caza, Vice President, Corporate and Investor Relations. Please go ahead.

Thank you, operator and good morning, everyone. Thanks for joining us this morning.

Ian Dundas, our President and Chief Executive Officer, will be providing an overview of our year-end operational, financial, and reserves results this morning. He'll also discuss our revised outlook for 2015. Given the significant drop in commodity prices since our guidance released in mid-December.

Also with us on the call this morning is Ray Daniels, Senior Vice President of Operations; who will give some additional detail on our capital spending and operational performance in 2014, and the outlook in 2015. Eric Le Dain, Senior Vice President of Corporate Development, Commercial; who will provide some additional color on curtailment in the Marcellus. And, Rob Waters, our Senior Vice President and Chief Financial Officer.

Our financials have been prepared in accordance with United States generally accepted accounting principles. 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.

All reserve information that we'll talk about today has been prepared under the Canadian Standard National Instrument 51-101. And, are on a gross working interest basis using forecast prices and costs, as provided by our independent reserve evaluator. Conversions of natural gas to barrels of oil equivalent, are done on a 6 to 1 energy equivalent conversion ratio. Which, does not represent the current value equivalent.

The information we're discussing today contains forward-looking information. We ask listeners to please 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, also available on our website at Enerplus.com.

Following our discussion, we'll open up the phone lines and answer questions you may have. And, we'll also have a replay of this call available later today on our website. With that, I'll turn the call over to Ian.

Thanks, Jo-Anne. Good morning, everyone. Thank you for calling in. We appreciate your time this morning. We'd like to leave you with two messages today.

First, we delivered another impactful year of operational and financial performance in 2014. This included a strong Q4 and exceptionally strong reserve performance. Second, as we navigate through the current market we are taking proactive actions to ensure we maintain our financial strength and enhance value for our shareholders.

So, let's start with a recap of 2014. Production grew by 15% or 13% per share. Driven by strong performance. Once again, in the Bakken and the Marcellus.

We met our upwardly revised production targets, averaging just over 103,000 BOE a day, despite selling 3500 BOE a day of non-core assets and, despite voluntarily curtailing production in the Marcellus that averaged approximately 5000 BOE a day in the second half of the year. Funds flow grew by 14% or 12% per share due to the growth in production and the strength of our hedging program.

Capital spending came in under guidance at CAD811 million as we slowed down activity in the fourth quarter in response to the drop in commodity prices. We ended the year in a very strong financial position with a debt to trailing 12 month funds flow ratio of 1.3 times and, less than 10% of our CAD1 billion credit facility drawn.

We achieved another year of strong, organic reserve replacement at very competitive costs. 2P reserves grew by 7%; 6% per share representing 175% production replacement. Crude reserves increased by 9% and now represent two thirds of our reserve base. Proved producing reserves also increased; up by 11%, and now represent about half of our total reserves. The majority of our reserves growth came from Fort Berthold and the Marcellus. Strong well performance throughout 2014 drove significant positive technical revisions in both plays.

We added 75 million BOE of 2P reserves through our development activities. This led to F&D costs of CAD9.80 per BOE including future development capital for a recycle ratio of 2.7. FD&A costs were also attractive at CAD8.62 per BOE.

Strategically, we continued to high-grade our portfolio throughout the year with the divestment of non-core gas assets at attractive prices. Our 2014 divestments program realized net proceeds of CAD204 million at a metric of CAD19.65 per BOE. We also increased our contingent resource estimates by CAD86 million BOE bringing our total to 449 million barrels of equivalent. This increase was largely from our oil assets in North Dakota.

Finally, in addition to our strong operational financial performance, we also established a very healthy hedge position for 2014, sorry, for 2015. So, a large percentage of both our oil and gas production is currently hedged at prices well above current market.

Okay, so now, let's look forward to 2015. This strong performance in 2014 has put us in a position of strength as we entered this year. But, as we continue to experience significant commodity price weakness, we are adjusting our plans to preserve value in the near term and ensure the financial strength of the Company.

First, we are further reducing our capital spending. We are now forecasting CAD480 million of capital spending which, represents a 40% reduction from 2014 levels, and, is CAD150 million lower than our current guidance. Although, a portion of the reduction relates to cost savings that we are now seeing, the large majority of the reduction is based on lower activity in the Marcellus and the Bakken.

Secondly, we have entered into agreements to sell two non-core properties producing approximately 1900 BOE a day of primarily oil production for proceeds of CAD182 million before closing adjustments and transaction costs. We expect these transactions to close early in the second quarter.

Third, we are planning for high levels of production and curtailment in the Marcellus in this low natural gas price environment. We believe dialing backward our production when prices are lower, allows us to retain the value of our assets and provides us with the flexibility to increase production quickly as gas prices strengthen.

And finally, we are reducing our monthly dividend to a more appropriate level. Effective with the April payment, we are reducing our dividends to CAD0.05 per share from the current level of CAD0.09 per share. We know that the dividend is important to our investors. And, it will continue to play a role in our strategy to deliver value to our shareholders. We did not take the dividend reduction lightly, but believe the new level of CAD0.05 per month is a more sustainable and appropriate level in the current commodity price environment.

As a result of these proactive steps, we are revising our 2015 annual average production guidance range to 93,000 to 100,000 BOE a day with oil and liquids representing between 42% and 44%. Our year-over-year production volumes would actually be effectively flat excluding the impact of the voluntary production curtailments in the Marcellus. These actions have clearly improved our financial flexibility. Including the proceeds from divestments, our capital program and dividend are effectively funded this year under forward prices with an adjusted payout ratio of below 100%.

We expect our debt level at year end 2015 to be essentially unchanged from year end 2014. Although, with lower cash flows, we expect a higher ratio of debt to funds flow. We forecast our debt-to-trailing-twelve-month funds flow ratio will be about 2.2 times at year end 2015 assuming a WTI price of CAD55 per barrel, a NYMEX gas price of CAD2.75 per Mcf, and a US to Canadian dollar exchange rate of 1.25.

And now, I'll pass the call over to Ray. To provide some details on our operating activities in 2014 and our plans for 2015.

Thanks, Ian and good morning, everybody. What I would like to leave you with today, is that one, we continue to deliver improved operational execution in 2014. And two, our organization is focused on spend discipline in 2015 in both our capital programs and our operating activities.

In 2014, we drilled 88 net wells during the year; 65% of which were directed to crude oil drilling. As a result, our average liquids production increased 5% to 43,800 barrels a day. And, at the and of 2014, liquids represented 42% of our annual average production.

In North Dakota, where we spent 42% of our capital, we continue to deliver industry-leading well performance at Fort Berthold. This is achieved by advancing our completion design, optimizing our drilling density design, and testing the lower batches of the Three Forks. Both are thirty- and sixty-day initial production rates were 20% higher, on average, than our high case type curve. And, our total Fort Berthold production increased by almost 30% year over year averaging 21,700 barrels of oil equivalent per day.

Well costs did initially trend higher as a result of increasing the number of frac stages and volume of proppant pumped. But, we saw meaningful reductions in the order of 8% in the latter part of the year. These savings were primarily driven by the efficiencies of pad drilling. In fact the five wells we drilled and completed on the totals [butterflies] pad, at the end of 2014, averaged $12.1 million each. The combination of increasing initial production and reducing capital costs, drove a 25% improvement in capital efficiencies year over year. And by the end of 2014, we drilled 27.2 net wells and brought 18.4 net wells on stream at Fort Berthold.

We also completed a rigorous Fort Berthold resource assessment early in 2014 resulting in a significant increase in our estimate of discovered original oil in place by 500 million barrels to 1.5 billion barrels. With an estimated recovery factor of 15%, this enables us to increase well density and therefore, meaningfully increase the number of drilling locations by around 127%.

With the revised resource assessment and improved well performance, we added approximately 25 million barrels of oil equivalent of proved plus probable reserves, inclusive of extensions and technical revisions at the end of 2014. This equates to replacing 2014 production by over 300% with an average F&D cost CAD16.87 per BOE, including future development capital.

In addition, we added 76 million barrels of oil equivalent of economic best estimate contingent resource, an increase of almost 200% versus December 31, 2013 bringing our new best estimate of contingent resource to 115 million barrels of oil equivalent.

Turning to our operations in the Marcellus. Wells continue to outperform in this core area as well. Take the frac spacing and increased proppant, resulted in a positive impact on well performance. Thirty day initial production rates averaged 11 million cubic feet per day in 2014 compared to 10 million cubic feet per day in 2013. And, despite the increase in frac stages and proppant, on average, total well costs in 2014 were roughly CAD1 million lower per well than in 2013.

With the additional working interests acquired in December of 2013 as a result of our drilling program, production doubled year over year from about 15,000 barrels of oil equivalent per day to over 30,000 barrels of oil equivalent per day despite average curtailment of 5000 barrels of oil equivalent per day in the last half of 2014. We currently have a total of 13.7 net non-operated wells waiting to be tied in.

Proved plus probable reserve additions and revisions in the Marcellus were over 300 Bcf at the end of 2014 replacing nearly 450% of production at the lower F&D cost of just under CAD0.50 per Mcf, including future development capital. And, despite the decline in natural gas prices, our best estimate of economic contingent resource increased from 1.3 Tcf to 1.4 Tcf at year end driven by strong well performance and higher expected ultimate recoveries. In addition, although we experienced wide base of differentials, which reduced the netback, our recycle ratio was a very attractive 3.6 times.

In Canada, we continued to invest in our crude oil at water flood portfolio during 2014. At Brooks, we drilled 14 wells, targeting the lower Mandel sands as part of a 55 well development program. Early production performance has been positive with average results in line with our expectations.

At Medicine Hat, we continued to develop the Glock sea waterflood where we drilled seven injection wells and seven producing wells, as part of our waterflood expansion project. Results from this drilling activity, as well as our polymer project, continue to exceed expectations.

Our Canadian gas activities were directed at the Wilrich and the Duvernay. We drilled 3.2 net wells in the Ansell area, targeting the Wilrich. And, in the low Willesden Green area, we drilled two horizontal wells, targeting the Duvernay.

Turning to our 2015 plans. As I mentioned, we are focused on spend discipline. First, we have been very strict around capital allocation. And secondly, we are working to maximize savings in all areas of spend.

The result is that we have reduced our capital spending program significantly in 2015 to CAD480 million, a 40% reduction from 2014. The CAD480 million has some cost savings factored in. But, the majority of the reduction from our current guidance is deferral of activity.

With respect to our operating activities at Fort Berthold, we will be dropping our rig at the end of Q1. And, we will continue with only a one-rig program for the remainder of 2015. We have also reduced the number of completions, primarily to those deemed essential. This minimizes spend and also builds an inventory of about 16 wells by the end of 2015 that we can bring on-stream expeditiously when market conditions improve.

In the Marcellus, we are reducing activity significantly resulting in approximately a 75% reduction from our 2014 spend. With current gas prices, our plan also includes a continuation of production curtailment averaging between 6,000 and 7,000 barrels of oil equivalent per day in 2015. Eric will talk a little about that later.

The curtailment will moderate our decline rates and enable us to ramp up production quickly when natural gas prices improve. Canadian activity in 2015 has also been minimized with effectively, only two operated drilling programs planned. We have a three well program at Ansell in our top tier area in the Wilrich, that will be completed by the end of Q1.

The second program is at Brooks, targeting the lower Mandel. This program will continue into Q3 and is primarily driven by lease expire rates. In addition to these programs, we have some funds allocated to new facility construction, facility maintenance, and well optimization within our waterflood portfolio.

With respect to cost savings in 2015, our supply chain organization is very active working with our vendors exploring ways to save costs. This is including direct negotiations with key contractors, bidding or rebidding work, and written communications with lower-spend contractors. We have had a very positive response from our vendors and, have secured savings across the board ranging to as much as 40% on a contractor-by-contractor basis.

Currently, we are seeing bottom line savings in the order of 10% to 15%. But, anticipate savings could rise to as much as 15% or 20%, if the current business environment persists. In addition to cost savings, we are also targeting technology to help our cost structures. And, some examples in our Fort Berthold operations including -- include using insulating time covers on our frac jobs, using natural gas instead of propane for water heating and, special frac plugs that don't require drilling out.

These three modifications alone could reduce our completion costs by as much as CAD300,000 per well. Suffice to say, our staff across operations are focused on driving costs out, without compromising economics or safety.

With that, I'll now turn over to Eric.

Thanks, Ray. I'll just say a few brief words concerning the Marcellus curtailment. As both Ian and Ray have mentioned, we foresee curtailing production at the levels of 6,000, 7,000 barrels of oil equivalent per day of Marcellus production on average in 2015. We just are not prepared to produce all of our capability into this low price market.

Therefore, we see production on average, somewhere between 170 million and 190 million cubic feet a day. The 6,000 to 7,000 barrel oil equivalent per day level of curtailment is based on our December and January experience. And, our view that NYMEX and Marcellus prices will remain soft through 2015 due to the oversupply in the Northeast and across the wider continent.

Our projected net level of production provides about CAD40 million of net operating income from our Marcellus production. At current forwards, roughly that $2.75 US, an MMbtu NYMEX we quote and, roughly CAD1.25 basis differential. This level of spend is enough to roughly offset the decline in the Marcellus for projected production on an annual average basis. We're spending about -- projecting spending in the lower CAD40 million range. It doesn't quite balance decline on an exit-to-exit basis.

Do we foresee curtailing production into 2016? At the moment we do. Infrastructure, as you know, continues to be built to take gas away from the Northeast. So, there's no question the industry can absorb some level of growth year over year.

In the end, though, it comes down to whether competitors act, as we and our partners are doing, to limit production into this market environment. Indeed, we are seeing similar behavior and announced reductions and spend across the competitive world there. And, with that, I will turn it back to Ian.

Thanks, Eric. Before I turn it over to questions, I'll just wrap up.

We believe that our primary job in the current environment is to ensure our financial strength and to focus on maximizing shareholder returns. We believe that the steps we are taking have positioned Enerplus to withstand a low oil and gas price environment which, could potentially continue past 2015.

Although our plan will have modest implications to near-term cash flow, we believe we are taking the right steps to position Enerplus to, not only weather this downturn, but to potentially capitalize on opportunities as we see them. We retain significant flexibility, and are well positioned to reestablish production and dividend growth, as market conditions improve. Although, this may be seen as conservative, we view it as prudent.

And with that, I will turn the call over to the operator and we are here to answer any questions you may have.

(Operator Instructions)

Greg Pardy, RBC Capital Markets.

Thanks, thanks, good morning. Just a number of nitty questions. But, Ian, I'm wondering, could you lay out what you think your spending trajectory looks like just over the course of 2015? I mean on a quarterly basis? Rough numbers are fine.

Sure. We will have 90% -- 60% done. Sorry, nobody use real numbers here. We will be more than half done as we move into the second quarter. And, a good 70% to 90% done as we move through the summer. Very limited spend in the fourth quarter.

Okay, okay. Which is -- kind of, brings me to my next question. I think the Marcellus speaks for itself in terms of -- that you can bring on additional volumes, kind of, as and when you want to. With the one rig program now in the Bakken, what does that mean in terms of an exit rate -- approximate exit rate?

And, I guess to balance that, what Ray was saying, where you've got a number of wells that you'll -- I think its 15 or 16 wells you'll be able to bring on it quickly. But, just trying to understand those dynamics a bit better?

Yes. So, we don't talk exit-to-exit too much. But, down a bit, I think the key message we would want people to retain is one of flexibility here. And so, we will have -- we already have a bit of an inventory. We're going to have a bigger inventory, holes in the ground, as we move to the end of the year.

Ray talked about 16 wells. Those aren't instantaneous completions but, that could come on really quite quickly. And so, is it a possibility we will adjust again this year? Absolutely, that's a possibility if we see price response. We are already seeing costs come down.

A completion? Last year in that CAD12.1 million number, Ray referenced a completion, it was CAD8 million. Of that, approximately, now that's probably [CAD]6.5. And, the longer we stay in this price environment, the more that we see potential improvement coming there. So, I'd say it's not the same as literally dialing up currently producing wells in the Marcellus. But, there is a lot of flexibility to bring more than ten wells on.

Our expectation is -- well, I don't know. We're going to see how the market responds. But, we can move pretty quickly there. And, then -- so when -- and when you think about 2016, which we're not really talking about explicitly, but, obviously this is a plan that positions us much better for 2016 if this continues.

So, in a modest priced environment, 2016 what will happen there, low spend will happen there as well, obviously. And so, as we think about a two-rig program versus a one-rig program in a lower spend area, that one-rig program, we think gives us enough inventory in 2016 as well.

Okay, great. No, thanks for that. The waterflood you sold at a -- the assets you sold today, about a 7% decline on that. Can you just remind us what your corporate decline would sit at now, approximately?

We still talk 25% and that's not a bad number to think about. Selling 1,900 barrels a day of low decline. I don't think we said 7%. But, in any event, low decline assets moves it a little bit, I think 0.3% or something along those lines.

Okay.

And then, as Eric talked about, this curtailment in the Marcellus is a tricky thing to think your way through. So, it's at the upper levels of curtailment. You actually have quite a modifying effect on decline. But again, that can -- that changes on a -- can change on a monthly basis as we bring it back on. But, net, net I would say 25 is a good number to be thinking about still.

Okay. And, then maybe, just to define curtailments right now. So essentially, those are wells that you've drilled, completed, and they're essentially, just awaiting connection? Or, would we be further back in the process? I'm just trying to understand what -- how you define curtailment?

Curtailment, as we define it, are wells that are -- have produced. That we are producing at a level other than their productive capacity. Not their theoretic productive capacity, but their actual productive capacity. Think about just choking it back.

Yes.

And so, on a day basis, we could see 10,000 BOE a day of swing. And, you saw a fair amount of volatility in the fourth quarter. And, there's a lot of stuff that was going on in fourth quarter in terms of, first, pipe expansion. And then, some really weak day prices that were happening in December.

But, over average in the fourth quarter, we saw that 6,000 to 7,000 BOE a day. So, today, production's reasonably high as we're seeing a weather event in the East. But, in January, it was down a bit, as it wasn't there. So --

I know there's no --

Okay, and that's 100%? The 6,000 to 7,000; that's 100% gas?

Yes.

Okay, and two last quick ones for me. Just the production guidance you've got out now. Is that -- that's inclusive of the 1,900 BOE a day that you're selling?

Yes.

Okay.

And, it is -- and it is -- it assumes a early Q2 close.

Okay. Perfect. And, the last thing. Just on -- just with respect to liquidity. I mean, your balance sheet has actually been in good shape all along, even better now. But, can you just remind us on your liquidity? And, then just what your covenants are around that?

Sure. I'll turn that over to Rob Waters.

Okay. And, Greg, actually in our MD&A this time. We actually laid out what the covenants are. And, where we were with respect to the covenants at the end of 2014. So, that material is in there.

I think it's around eight -- under liquidity and capital resource section. So, the covenants on our senior bank facility, which is a CAD1 billion facility, are, we can take our senior debt to EBITDA, which is earnings before interest, taxes, and depreciation, whatnot, to 3.5 times. But, we can only do that for six months and then, it has to come down to three times. And, at the end of the year, we are running at 1.3 times. And, that's, sort of, the most -- that's the covenant we watch the most. The other covenants wouldn't cause us much trouble at this time.

We also have a total debt-to-capitalization covenant and the maximum ratio there is 50% and, we're running at 26% right now. And, on our senior notes, we have fairly similar covenants of that 3 to 3.5 times on senior debt to EBITDA. But, we also have a maximum debt to consolidated net present value of total proved reserves. And, that ratio is that 60% and we're currently running at 37% at the end of the year.

And then, there's an interest coverage ratio, EBITDA to interest. And, the minimum ratio -- minimum there is four times and we're running at 14.4.

So really, we're not worried about our covenants at this stage our balance sheet's in good shape. We ended the year at a 1.3 times debt to funds flow. And, that was pretty close to what you'd call a debt to EBITDA at that time as well.

Okay. That's great. Thanks, all.

Thanks, Greg.

(Operator Instructions)

There are no further questions. I will now turn the call back over to Mr. Ian Dundas, President and CEO.

Great. Well, appreciate everyone's time today and I hope you have a great weekend. Thank you for paying attention. Cheers, bye.

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