Enerplus Corp (ERF) 2015 Q1 法說會逐字稿

Good morning. My name is Chris, I will be your conference operator today. At this time, I'd like to welcome everyone to the Enerplus Corporation 2015 first quarter results conference call.

(Operator Instructions)

Drew Mair, Manager of Investor Relations, you may begin the conference.

Thank you operator and good morning everyone. Thanks for joining the call. I'm filling in today for Jo-Anne Caza, Vice President, Corporate Investor Relations.

Ian Dundas, our President and Chief Executive Officer, will provide an overview of our first-quarter results released this morning. Rob Waters, Senior Vice President and Chief Financial Officer, will be giving details on our financial position and cost reduction measures. Ray Daniels, Senior Vice President of Operations, will give some additional detail on our capital spending and operational performance for the quarter. Eric Le Dain, Senior Vice President of Corporate Development Commercial, will be giving some color on our marketing and hedging activities.

Our financials have been compared in accordance with US Generally Accepted Accounting Principles. All discussion of production volumes today are on a gross Company working interest basis. All financial figures are in Canadian dollars, unless otherwise specified. 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 available on our website at www.Enerplus.com.

Following our discussion, we'll open up the phone lines and answer questions you may have. 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.

Good morning everyone. Thank you for taking the time to join us this morning. Our results released this morning demonstrate another quarter of consistent and strong operating results. We continue to demonstrate prudent financial stewardship through a focus on disciplined capital allocation and cost control.

Daily production averaged 109,000 BOEs, crude oil and natural gas liquid volumes were 43% of production in the first quarter, consistent with our guidance range of between 42% and 44%. Production is down 4% quarter over quarter, which is fairly standard for our first quarter. But also in response to reduced capital spending and deferred completion activities.

Of note, we delayed virtually all well completion activity in North Dakota from late November until the end of February, in response to lower oil prices and cost uncertainties at that time. With prices stabilizing and meaningfully improved cost structures, we plan to accelerate second-quarter well completions in North Dakota and reestablish growth in the region.

Given the solid momentum going into the second quarter, in part based upon strong well performance in North Dakota, we are well-positioned to achieve our annual average production guidance of between 93,000 and 100,000 BOE a day, and liquids guidance of between 42% and 44%, despite the previously announced sale of 1,900 BOE per day of non-core producing assets. Sorry, apparently I mentioned 109,000 BOE a day, it's 100,900 BOE a day, which is our first quarter production.

Significant declines in commodity prices resulted in first quarter funds flow of $109 million compared to $213 million in the fourth quarter of 2014. Although supported by our commodity hedge position, funds flow over the quarter was impacted by one-time charges and foreign-exchange losses. Funds flow was also impacted by our decision to delay completion activity in North Dakota.

Capital spending is on track with $167 million spent in the quarter, we continue to expect $480 million in 2015. Our cost savings initiatives are also delivering results. Operating costs came in better than guidance.

G&A costs were also better than guidance despite the inclusion of one-time severance charges. Subsequent to the quarter, we closed on our previously announced asset sales generating proceeds of $186 million. We've also started to add additional commodity price hedging for 2016.

Overall, we are on track to meet and possibly exceed all of our 2015 guidance targets. Despite the lower prices in Q1, we're also well-positioned to meet our key financial goal of not building debt and delivering within our means by having our spending plans fully funded this year.

I will now turn the call over to Rob to provide some further details on our financial position.

Thanks, Ian. I will start with funds flow in the quarter. First quarter funds flow of $109 million was down 49% from the fourth quarter. The sharp drop in commodity prices was, of course, the biggest driver in the reduction, but there were a few other factors I would like to touch on.

As Ian mentioned, we didn't complete any oil wells in North Dakota from late November until late February. Given the subsequent improvement in oil prices and cost reductions, that was a good thing. Nonetheless, this delay is responsible for some of the weakness in Q1 funds flow. The pace of oil well completions is picking up in North Dakota and Ray will have details on that in a moment.

We had $11 million of one-time charges in the quarter, comprised of severance payments, rig termination charges, and retroactive royalty adjustments. In addition, as the Canadian dollar weakened against the US dollar, we incurred cash losses of $8.6 million on foreign-exchange callers associated with our revenues.

On a positive note, we crystallized $40 million of foreign-exchange gains by unwinding positions relative to our US dollar term debt. This item is easy to miss because the gain does not appear in our funds flow number. We recorded the gain in cash flow from financing, not cash flow from operations, as the hedges were originally intended to hedge the FX associated with the principal repayment of US dollar debt. Despite the accounting, it's important to note that $40 million in proceeds went towards debt reduction.

We incurred a non-cash asset impairment charge in the quarter of $268 million, $163 million after taxes. Unlike IFRS accounting, the US GAAP stimulates -- stipulates that we use historical trailing 12 month commodity prices when calculating asset impairments. The decline in crude oil pricing for the last two quarters obviously impacted the impairment calculation, and just to reiterate, this was a non-cash charge.

We have reclassified Marcellus gathering charges from operating expenses to transportation costs, to be more comparable to our Marcellus peers. These charges pertain to pipeline costs to transport salable gas in the Marcellus from the lease to a downstream sales point. This is a change in presentation between two expense accounts and does not affect our netbacks, funds flow, or net income. The before and after comparison of the reclassification and the associated guidance is described in detail in the MD&A.

Our cost-reduction initiatives are gaining traction as evidenced by our lower operating and G&A costs. Operating costs were $6 million lower in the quarter than in the fourth quarter of 2014, as we began to see cost savings materialize. We've reduced discretionary spending, challenged supplier pricing, and introduced incentives to realize cost efficiencies across the Company. We've also reduced our workforce by approximately 8% compared to this time last year. On the CapEx front, Ray Daniels will discuss our success at managing drilling and completion costs down.

Turning to the balance sheet, we remain well positioned. We ended the quarter with a debt to trailing 12 month funds flow ratio of 1.7 times. Our debt to EBITDA ratio was 1.6 times, and this is the most sensitive ratio with respect to our lending agreements. In the liquidity section of the MD&A, we disclosed the status of our debt metrics relative to all our financial covenants. We're in good shape.

At the end of the quarter, we were 13% drawn on our $1 billion bank facility. However, subsequent to the quarter, we closed on divestments of $186 million. The proceeds were used to pay off the bank debt, leaving our entire $1 billion bank facility essentially undrawn. Our plan was to have a fully funded program this year. We have a strong hedge position, we lowered our CapEx spending, made the tough decision on reducing our dividend, and we've been successful in non-core divestments.

Despite the weak commodity prices in the quarter, our plan is intact. We expect to be fully funded. We're not expecting to increase debt, assuming no dramatic changes in FX. In fact, with improving oil prices and costs coming down, the plan is looking a little more robust these days.

Now I'll turn the call over to Ray, who will provide details on our capital spending and operations.

Thanks Rob. Operationally, we had another solid quarter with some strong well results. The majority of our activity was directed to North Dakota in the US and the Deep Basin and Brooks in Canada.

Starting in North Dakota, where we spent $79 million in the quarter, our pace of activity slowed as we dropped to one drilling rig, and we drilled 8.2 net wells in that period. We paused our completions activity from late November 2014 through to late February this year in response to low crude oil prices and cost uncertainty. But as prices began to stabilize and cost structures improved towards the end of February and into March, we began to bring some wells on stream, and by the end of the quarter, we brought 3.6 net wells on to production.

We've continued to evolve our completion design and are very pleased with the results. During the quarter, we brought a four well pad on stream with an average rate per well of over 60,000 barrels of oil in the first 50 days of production. We're also particularly encouraged by one of our most recent Three Forks wells, located in the southeast area of Fort Berthold. We modified the completion design and the will is significantly outperforming our expectations for the region, with an IP30 of approximately 37,000 barrels of oil. This is an encouraging sign with respect to productivity of that region.

Turning to costs, we're seeing cost reductions materialize with well costs trending down about 15% from 2014 levels. Our average well cost in Fort Berthold, year to date, is approximately $11.5 million, and our most recent well came in at just under $11 million; and remember, these costs are all inclusive, including drilling, completions, and facility costs. We also used a very intensive completion design.

We're continuing to work with our suppliers and contractors to improve our cost structures, not just in North Dakota but across our portfolio. We're starting to reap the benefits of these cost savings and expect to continue to improve our capital efficiency as the year progresses. We continue to build an inventory of drilled and completed wells in North Dakota, which stood at 18.8 wells at quarter end.

As completion activity begins to increase in the second quarter, in response to price stabilizing and improved cost performance, we will start to work through some of our uncompleted well inventory, and are expecting to reestablish production growth in North Dakota in the second quarter. We're planning to complete our bring on about 6 net wells during Q2.

In addition, we're evaluating increasing the number of planned completions in the second half of 2015. We're adding four incremental completions to our program, which could be funded without increasing our capital budget due to cost savings. On top of this, we could add additional completions to our program in the back half of the year. We will remain flexible as we monitor the market conditions.

Turning to the Marcellus, where we -- where there was a significant slowdown in activity. We spent $11 million, almost 60% down from the fourth quarter. Drilling and completion activity slowed with just 2.2 net wells drilled and 2.9 net wells brought on stream. Although we continue to curtail production, average daily production remained relatively strong at about 195 million cubic feet per day.

In our Canadian oil portfolio, spending was largely focused at Brooks, where we drilled 14.4 net wells with 10.9 net wells brought on stream. Average well results are in-line with our expectations, and we expect to add just under 1,400 barrels of oil equivalent per day from the program during 2015. The timing of the Brooks wells -- the Brooks drilling program was driven by lease retention given impending land expirys.

Turning to the Deep Basin, we saw encouraging results from our operated three horizontal well pad Ansell. The wells were completed under budget, and initial production results support our assessment of a sweet spot trend across our lands. Initial production from the pad is approximately 25 million cubic feet per day and is facility constrained.

Overall, our assets in Canada and the US continue to perform at or better than our expectations. As importantly, and a plus in the service partners, have not let up on our strong commitment to safety and responsible operations in spite of the recent market turmoil. Looking forward, the majority of our activity and capital for the remainder of the year will be focused at our North Dakota oil properties. Our annual average daily production guidance for 2015 is unchanged at 93,000 to 100,000 barrels of oil equivalent per day. Given the strong momentum going in the second quarter, we remain well positioned to achieve this.

With that, I'll turn it over to Eric, who will discuss our oil and natural gas marketing and hedging program.

Thank you, Ray. Obviously, both crude and natural gas prices were weak during the first quarter. As well, both heavy and light crude oil differentials in Canada weakened slightly, with WCS averaging $14.73 per barrel below WTI, and MSW averaging $6.80 per barrel below WTI during the quarter.

Despite Canadian crude differentials trading wider in the quarter, the outlook ahead is positive. The bottlenecking on the Enbridge system proved market access to the US Gulf Coast and reduced supply from oilsands producers during seasonal maintenance is expected to strengthen Canadian crude differentials in the second quarter.

In the US, our average realized crude oil differential improved from the previous quarter. The narrowing of the Bakken crude differential was a result of increased rail capacity coming into service during the quarter. The upcoming reversal of Enbridge's line 9, scheduled for second quarter of 2015 is expected to provide further support for US Bakken differentials. We're maintaining our outlook of $9.50 per barrel before trucking and gathering for Bakken differentials in 2015.

Natural gas prices at both AECO and NYMEX were lower in the quarter, due primarily to strong production in both Canada and the US. Natural gas prices in the Marcellus also traded lower in the quarter. Spot prices at Transco Leidy and TGP Zone 4 averaged $1.29 per MCF, over 35% lower, roughly, than the previous quarter. With approximately 46% of our Marcellus production sold under long-term sales contracts with stronger price exposure, outside of the northeast Pennsylvania producing region, our overall realized Marcellus sales price was $1.66 per MCF. This equated to a basis discount to NYMEX of $1.32 per MCF for our Marcellus production, which is in line with our full-year basis guidance of negative $1.25 per MCF.

Turning to our hedge position, approximately 35% of our crude oil production, net of royalties, from April through December 2015, is hedged at roughly $92 per barrel against WTI, and approximately 46% of natural gas volumes, net of royalties, are hedged at $3.90 per MCF against NYMEX over the same period.

Subsequent to the quarter, we established an initial crude oil hedge position for 2016. We hedged approximately 26% of our forecasted 2016 crude oil production, net of royalties, or 8,000 barrels per day. Of that volume, 2,000 barrels per day were swapped at just over $65 per barrel, and for the other 6,000 barrels per day, we used a three-way, 50 x 65 x 80 structure. We bought a put at $65 per barrel, so we could participate in the price upside potential above that level. We paid for part of that option premium through selling an $80 per barrel cap and $50 per barrel put. Thus the three-way, 50 x 65 x 80.

For some time now we've also been establishing a significant physical AECO basis position for the coming five year period, to protect against the potential erosion of Alberta prices as Marcellus gas pushes into the mid-continent. We have 60 million cubic feet per day sold for 2015 and 2016, and 80 million cubic feet per day sold for 2017 through 2019, at an average basis differential of roughly $0.65 per MCF. In Q1, we produced roughly 135 million cubic feet a day of gas in Western Canada.

I'll now turn it back Ian.

Thanks Eric. Despite the current commodity price environment, Enerplus is well-positioned. Our balance sheet is strong with virtually our entire $1 billion credit facility undrawn, and we continue to achieve excellent results from our asset base.

We remain committed to disciplined capital allocation with a strong focus on cost control. We're seeing encouraging signs in the market with a modest recovery in crude oil prices and costs continuing to trend down. As we build on the operational momentum coming into the second quarter, we look to reestablish production growth in the Bakken and drive efficiencies across our portfolio.

And with that I'll now turn the call over to the operator and we will open it up for your questions.

(Operator Instructions)

Greg Pardy, RBC Capital Markets.

Thanks, good morning. A couple of questions having to do with the Bakken. I know you mentioned your backlog here is almost 19 net wells. How would that compare to a typical year backlog?

Greg, it's Ray here. We would normally go into the year with somewhere between four and six wells as we drill through the year end, so somewhere between 4 and 6 would be a normal year.

The other thing is, the IPs are very large on these. If you are to even look at what a first-year production contribution could be from that 19 net, before it declines, obviously, on the base, but this is -- these are large numbers like 10,000, 12,000 barrels a day that you could bring on?

That's true. I think if you think about type curves, we've generally been focusing, of late, in some of the better areas. A first-year cum production on those wells -- some of our top wells are 400,000 barrels, our type curves would be 150,000 to 200,000 barrels in those areas, with a first-month rate of over 1,000.

It's a lot of oil that can come on, and the reason -- I think this is important for people to understand. We thought it made no sense whatsoever to start to flow a large percentage of these wells when the price of oil was CAD42 TI and the differential that, at that moment, to the wellhead would've been CAD13. Something along those lines. We look at where we are today and that started to get better in, call it, March -- dramatic improvements in the price of the wellhead. So what we're doing right now is figuring out how many of those do you want to bring on.

As Ray talked about in his call, we had the original plan which had this deferral in it, so that is as per the original plan, when we look at the cost savings we're going to be able to add, call it, four operated wells just in the context of the original budget. That will come on -- let's call that Q3. And we've now got, call it, operational flexibility to maybe add another 8 on top of that. I would say we are looking at it really carefully. There are some positive signs out there. If you think about the conditions we would want, I think we have probably taken the risk of CAD30 oil off the table. That likelihood is less than it was.

We've been able to put some hedging in at more attractive rates for 2016 than we were able to before. The economics of these programs of these wells are really powerful, and so we just want a plan that makes sense, and we're trying to work through it all, but I would say we are looking at it real carefully.

And maybe on the backlog, I know you are running one rig, and from the opening comments, you've taken a termination fee, so I can't imagine there being any rush to go back to a two-rig program, and frankly you don't need to, just given the number of wells that you've got right now to tie in. Is that fair?

That is fair.

Okay, thanks very much guys.

(Multiple speakers)

I think that is very fair, but things change quickly out here, and we're trying to be real nimble as we work our way through that. Under most scenarios, we don't see the possibility of getting through our entire backlog this year. Just operationally, that wouldn't make sense for us. So when would you start to increase the pace of drilling? I don't know, my sense is it's later in the year or early next year, but we're going to remain really flexible.

Okay, thanks again.

Patrick O'Rourke, AltaCorp Capital. Patrick O'Rourke, your line is now open.

He's probably on mute.

Patrick, we cannot hear you if you're saying something right now.

Patrick, check your phone and make sure it's not on mute.

Maybe it's a pocket dial situation. Let's move on operator. Patrick can call back in if he's having phone issues.

(Operator Instructions)

Dan Healing, Calgary Herald.

Good morning, guys. I wanted to see if you could give some color around the workforce reduction you mentioned in the severance, 8%. What does that represent in terms of full-time equivalent positions and can you give an indication of where those cuts were made?

Yes. We would have throughout all of our operations, Canadian, US operations, offices, and field, approximately 700 full-time employees right now. That's approximately where we are. I would say those reductions were over a time period and across-the-board, as we looked at our workforce, and we looked at our capital plans. Some of those were influenced by -- we sold an asset, and so there was some consolidation and rationalization activity where some of those employees would have gone to the purchaser of that asset, and so I would say there's no single place that stood out from.

And just to clarify, the 700 is the current workforce after the 8% reduction?

Approximately.

Okay. And the other thing would be with activity in North Dakota coming back more strongly this year, would you see hiring back some of those folks?

I think we're well-positioned today to execute an expanded program.

Okay great, thanks.

Patrick O'Rourke, AltaCorp Capital.

Can you hear me this time?

Yes, we can.

My apologies for those technical difficulties there. Sorry, I was having a phone issue. My question here revolves around the Southeast Bakken well there. Result looks very very impressive and generally in the Three Forks, the northwestern edge of your property, you've had terrific results. You spoke about a change in completion technique. Are you able to add a little bit of granularity? And then in terms of this well relative to any other southeast wells you've drilled there, was this a change or is this a technique that you used in any other particular wells?

Patrick, it is Ray here. We did change our completion technique. We moved to a Slick Water Completion, we used a suspended propane-type frac material. What this meant is that we had more near well-bore damage then longer half-lengths. Result of that was that we saw improved production in the Three Forks first bench.

Is it a method that we can use all over our area? We are assessing that just now. We think in some of the other areas, the cross-link gel that we used in the northwest of our lands is the right completion design there right now. We will continue to assess this central SSP product in other wells there in the southeast corner, and we will continue to evolve our completions as we see these continued improved results coming through.

Okay, great. And if you do see -- if you are able to extrapolate these results more broadly in the southeast corner, does this change the well density assumptions -- you got them in 6 or 7 there versus 8 towards the north, in the past?

I would say it increases the well density. What it does is improves the volume of the wells. We think what is happening is that we're not striking down into different water zones, the second bench and the third bench, which tends to have more water down there in the second and third bench than up in the northwest areas of our land. And so by containing the frac within the first bench, we are getting maximum oil productivity.

Terrific. And one last question. In terms of the backlog, what sort of impact does infrastructure in the new North Dakota gas-flaring regulations and EPA regulations have on your ability to work through that backlog here?

We have to be very conscious of our planning and how we bring these wells on. We have to work very closely with our gatherer, and we also have NGL skids on there that we use to help with the -- with minimizing the flaring that we have on these fields.

Okay. Is there any impact on the pace or the ability, timing wise, to bring them on, though?

We planned that, Patrick, but it's one of these things where we understand we're working closely with our gatherer, we actually plan where we're bringing our wells and what volumes are coming on.

Okay great, thank you.

Patrick, if you recall, one I was answering questions from Greg, when we thought about what a really expanded program could look like, that's another 8 completions on top of the 4 that we're going to do. There's obviously more than that, but that takes into account those issues Ray was talking about. If we were to do the expanded program, we'd still exit the year with, call it, maybe 6 wells that we drilled uncompleted, and then that would be largely for -- I'll call it operational reasons, but a lot of that is actually infrastructure.

Okay, terrific. Thank you very much.

(Operator Instructions)

There are no further questions at this time.

Thank you, we appreciate everyone's time this morning. For those in Calgary, Go Flames, go. And enjoy your day. Cheers.

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