Enerplus Corp (ERF) 2018 Q1 法說會逐字稿

Good morning, my name is Cheryl, and I will be your conference operator today. At this time, I would like to welcome everyone to the Enerplus' Q1 2018 Results Conference Call. (Operator Instructions)

Mr. Drew Mair, Manager, Investor Relations, you may begin your conference.

Thank you, operator, and good morning, everyone. Thank you for joining the call. Before we get started, please take note of the advisories located at the end of today's news release. These advisories describe the forward-looking information, non-GAAP information and oil and gas terms referenced today as well as the risk factors and assumptions relevant to this discussion. Our financials have been prepared in accordance with U.S. GAAP. All discussions of production volumes today are on a gross company-working interest basis and all financial figures are in Canadian dollars, unless otherwise specified. I'm here this morning with Ian Dundas, our President and Chief Executive Officer; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; Ray Daniels, Senior Vice President, Operations; and Shaina Morihira, Vice President of Finance. Following our discussion, we will open up the call for questions.

With that, I'll turn the call over to Ian

Good morning, everyone. Thanks for joining us today. I know, it's a busy day right now for many of you. First quarter production was approximately 85,000 BOE a day of which 49% was liquids. Adjusted funds flow was $155 million, just above our exploration and development capital spending in the quarter of $151 million. As we talked about last quarter, our first quarter production came in lower than Q4. This planned decline was largely due to offset completion activity on adjacent acreage, which required us to shut in some very prolific wells for a period of time. An additional factor was that the timing of our onstream activity in Q1 was back-end loaded. We've now worked through those transitional issues and are positioned to drive some very robust oil growth for the remainder of the year. And that growth is already underway. Although our liquids production in Q1 averaged 41,500 barrels per day, we have seen significant liquids growth since the first quarter, underpinned by our North Dakota project.

Today, we're producing around 49,000 barrels per day. We expect to effectively sustain this level over the course of Q2, as we anticipate liquids production to average between 48,000 and 50,000 barrels per day in the second quarter. Our annual liquids guidance of between 46,000 to 50,000 barrels per day of liquids is unchanged. In short, we are well positioned to deliver our 2018 guidance. Additionally, the recent strength in oil prices is supporting a solid outlook for our cash flow. When we released our 2018 guidance at the end of last year, we indicated that we expected to be approximately cash flow neutral at around $50 to $55 per barrel in West Texas. Now with the current forward stripped in the mid-$60 range, we are forecasting our adjusted fund flow to exceed capital expenditures and our dividend by approximately $100 million. We remain well-positioned relative to our plans this year. We're on track to deliver strong returns on our capital program, competitive and profitable production growth and meaningful free cash flows.

I'll now pass the call to Jodi to talk through some of the financial highlights.

Great. Thanks, Ian. Starting with our pricing realization, our realized Bakken differential to WTI widened to USD 3.27 per barrel this quarter, which was wider than our 2018 guidance of USD 2.50 per barrel. This was largely driven by growth in North American crude oil supply that resulted from a 13% increase in WTI prices during the quarter as well as continued strength in the forward curve. Despite the somewhat wider price differential, our realized price received for Bakken oil still increased by 11% compared to the prior quarter. Although we have firm sales in place for approximately 18,000 barrels per day of our Bakken production for the remainder of 2018 at an average differential of just under USD 2.50 per barrel, the strength in the forward strip for WTI and our expectation that this will continue to drive crude oil supply growth in North America has caused us to widen our 2018 Bakken oil differential guidance for the full year to USD 3.50 per barrel below WTI. We also saw differentials for our Canadian oil production widen by over USD 10 per barrel in the first quarter compared to the previous quarter. This was due to continued Canadian oil supply growth as well as pipeline apportionments and flow restrictions following the service disruption of the Keystone pipeline in late 2017.

In the Marcellus, our sales price differential tightened considerably in the first quarter averaging USD 0.21 per Mcf below NYMEX. We've seen quite meaningful pipeline expansion in the Marcellus in the last 6 months and we believe the supply-demand dynamics in the region have continued and will continue to become more balanced as a result. The narrow differential in the first quarter was also supported by a particularly cold winter in the Northeast U.S. We do expect, however, our Marcellus differential to widen during the remainder of the year, particularly in the summer months as our sales portfolio has exposure to the New York market, which are typically weaker during this period.

Based on this, we are leaving our average 2018 Marcellus differential guidance unchanged at USD 0.40 per Mcf below NYMEX. Our operating costs, G&A and transportation expense during the quarter were all consistent with our forecast. And as a result, we have left guidance unchanged. Adjusted funds flow was $155 million in the quarter. As Ian mentioned, under current strip pricing, we see meaningful free cash flow in 2018 relative to our capital spending guidance of between $535 million and $585 million, which is also unchanged.

Notwithstanding this free cash flow generation, we will remain disciplined in executing our growth plans. Our capital allocation decisions continue to be focused on generating robust corporate level returns, while maintaining a strong financial position to allow for flexibility through all commodity cycles.

And finally, our balance sheet remains solid. At the end of the quarter, our net debt to adjusted funds flow ratio was 0.5x. I'll now turn the call over to Ray.

Thanks, Jodi. Operational execution is growing as we had planned coming into the year. In North Dakota, we had about 2,000 to 3,000 barrels of oil equivalent per day of downtime in Q1 that we have largely anticipated due to offset frac activity and our completion schedule was weighted to later in the quarter to minimize the impact of the typical bad weather we see early in the year.

Now as we've come through April, we're seeing the strong ramp in our productions, which is expected to continue as we bring some larger, higher working interest pads onto production.

Towards the end of April, we began to flow back 91% working interest 6-well pad. Today, we've got 4 of the 6 wells on production and are encouraged by the strong initial raise. We expect to have the 2 remaining wells flowing back in the next few days.

So for context, our North Dakota production has gone from around 30,000 barrels of oil equivalent per day in Q1 to around 40,000 barrels of oil equivalent per day currently.

In total, we expect to bring 11 gross operated wells onstream from 2 pads in North Dakota in the second quarter with an average working interest of 94%. We get asked fairly regularly about the cost environment in the Bakken. While activity in the basin has picked up somewhat in 2018 and we've seen some inflationary pressures, we believe we can offset these increases through efficiencies and execution. As a result, we anticipate that we can hold our baseline well costs largely flat to 2017 levels. There were a couple of notable items operationally in Canada in the first quarter. We drilled and brought on production 2 Ratcliffe wells in Southeast Saskatchewan, which have been outperforming our predrilled expectations. We believe 1 of the wells is on track to be among the top producing wells in Saskatchewan in 2018. In the Ante Creek, the increased water injection has helped arrest the oil decline and stabilized oil production, which is anticipated to begin to increase during the second half of 2018.

And lastly, in the DJ Basin, our initial well in the play is continuing to produce encouraging rates. In April, 7 months on production, the well averaged 400 barrels of oil equivalent per day, 73% oil. We're drilling 4 wells in the DJ Basin in 2018 with plans to bring the wells in production in the third quarter.

In summary, the growth we have been expecting in the second quarter is well underway and we're in a good position relative to our guidance.

With that, I'll pass the call back to Ian for some closing comments.

Thanks, Ray. In summary, I'll conclude by reiterating that our plans are well on track, and we believe we are comfortably positioned to continue to deliver strong returns on capital, competitive production and cash flow growth per share and meaningful cash flow generation -- free cash flow generation. And so I'll turn the call over to the operator for any questions that you may have.

(Operator Instructions) Our first question comes from Greg Pardy, RBC Capital Markets.

Ian, really 3 quick ones, actually 2 quick ones because I think you took care of the DJ question, but just given the backdrop of cash flow versus CapEx this year and where the balance sheet sits, you've got a 7% NCIB in place. What's your thinking about just acting on that and how aggressively?

The NCIB we view as a tool. We plan to keep it in place and we'll look to execute on that opportunistically from time to time. Strategically, right now, I'd say, we're a little more interested in building for the future and those sorts of things. But it will be something that we'll evaluate on a realtime basis. You asked will we be aggressive. We put NCIB in place for only $200 million. So I think that inherently isn't aggressive what we have sort of discussed. So it will be a tactical tool that we'll look at if circumstances make sense for us.

Okay. Great. And just the other question is on the Canadian realizations. Have you -- since the first quarter results and so on, have you seen improvements in terms of realizations versus the benchmark or/and can you just talk about your egress positioning and so forth?

Yes. Actually, we've got Garth Doll here, who is our Manager of Marketing. Garth will -- I don't know if you've chat to him before. He will give you a little context on that.

We're seeing -- we've seen some improvement certainly in the Canadian differential side, heavy diffs improved to the $15 level here for June. They were significantly weaker than that in Q1, and we've actually got a fair bit of our WCS exposure hedged through the rest of this year as well. So we feel pretty good about how we are positioned on the Canadian differential side for the rest of this year.

Okay. And then I'm thinking more just light and then vis-à-vis the benchmark like your realization versus the benchmark?

We would expect our realization to improve relative to the benchmark certainly through the third and fourth quarters. The egress on the oil side, it means, this is -- obviously, we need to see some pipeline egress improvements for sure. Gas realizations were fully hedged. So we're insulated from this incredibly weak acre basis market that we're seeing as well. So we believe we'll continue to outperform both crude and gas benchmarks in Canada.

Just a little bit of extra context for those of you, who might not recall. We're producing 49,000 barrels a day, Canadian oil is approximately 10 of that, split pretty evenly between heavies and lights. So we saw those differentials widen out, but it's not particularly meaningful for us. And on the gas side, we've very, very little Canadian gas exposure, obviously.

Our next question comes from Brian Kristjansen from Macquarie.

Just had a question about your Bakken rates. It looks like the Q1 IP-30 has looked a bit lower than type curve, but clearly Q2 sounds like they are considerably higher? Any color on those differences?

I would say, Q1 was directionally in line. You're talking 1,300 BOE a day, Q4 we're 14-ish, if I recall. So directionally in line. We're getting [these] a little bit here. There was a little bit of operational noise on some of those wells. So some of those wells even though they're 30-day rates, they actually included a period during which the wells were cleaning up. So those wells if you'd sort of chosen peak 30 days, which we didn't have that much time, we would have pulled it up a little bit. So I'd say that's all directionally in line. And then, Ray talked a little bit about this most recent 6-well pad. It's the cats pad. It's realtime. Right now, we only have 4 of those 6 wells on. We would certainly expect there to be outperformance on the 4 that we've seen. We'll see how long that lasts, but we'd expect that to show up in the early time data for sure. So it's encouraging.

And was that location based or completion style based? Or are you still experimenting with greater frac intensities?

There's a range of areas. So this would be an area that may be a little better than average from a type curve perspective. We have seen -- we do continue to, I don't know if the word is experiment, but we've gone from smaller fracs to bigger frac and now we're -- I don’t know smarter on some levels. And so we're testing a lot of different concepts here. And so in the 4 wells we've seen, we actually have [steam] -- some differences in completion technology that's encouraging what we are seeing. So you do see some variability in the field, but right now it's, I think, people are pretty interested in these things. I mean, there's possibility, I mean, a lot of our operational activity over the next -- well, on a go-forward basis it's going to be dominated by pad development, right. And so that sets up -- there's obviously a little bit of lumpiness that comes with that, but it sets up potential advantages in [final] ops and super fracs and these sorts of things and maybe we're seeing a little bit of that going on as well. I think, it's actually the first time -- a fun fact for people. I don't recall a time when we've brought on 6 high working interest wells on a pad before. It's -- I think, it's the biggest operation we brought on. So we're very encouraged by the success we're seeing right now. Ray, something you would like to add to it.

Yes. Ray Daniels, here. With a multivariate analysis that we've carried out, we tune our completions depending on where we are in the acreage. We'll continue to learn from that and continue to tune them up, but what we're trying to do is to make sure we're optimizing all of our completions to maximize value. And as Ian says, we're continuing, we call it testing, but we are -- we understand -- we've got great understanding of what we need to do to improve production in different areas and to optimize these wells. So we'll continue learning and we'll continue modifying our completions to make sure we maximize that value.

(Operator Instructions) Our next question comes from Travis Wood National Bank Financial.

Travis, we can't hear you, if you can hear us.

I wasn't muted by the way. So I was trying to understand that you've guided the Q2 liquids corporate number 48,000 to 50,000, obviously a nice step function up from Q1. Can you give us some color around how much of that are -- is the shut in volumes coming back on from the concurrent operations as you bringing the pad on? And then, can you help us guide into the lumpiness into -- is it another step function in Q3 and then flatter? Or should we start to layer in a big exit rate to get to the 49,000 or 50,000 as an average number.

Let me hit this a couple of ways. So this is all about North Dakota, right. North Dakota is where all the movement is. So North Dakota on a BOE basis was 35,000 BOE in Q4 and was effectively 30,000 in Q1. The decline there came from 2 pieces, Ray talked about the downtime. We always see downtime, right. So this would have been unanticipated -- not unanticipated, extraordinary. Let's use extraordinary downtime, 2,000 3,000 barrels. We also had normal decline because as people may recall, we were a little flushed up in Q4 as we brought on a pad. And we saw a little more decline than normal. And then we brought on 8 wells, those actually 5 net and those again pads largely came on effectively in March. So it didn't give you a lot of rate. So that sort of takes you through the quarter. And then, we've now brought on -- so we've got that downtime is effectively behind us. And so the 2,000 to 3,000 is back. We've got the full run rate on those net 5, and we've now got 4 high working interest wells on right now and so that takes us, and I'm switching to oil now, to 49,000 BOE corporate -- sorry, barrels of oil corporately. So then, let's talk about the rest of the year. So everybody is pretty good at math. So if liquids were guiding to between 46,000 and 50,000 barrels over the year. If you just assume, we hit the mid -- if we just keep this 49,000 constant over the course of the year, just assume that were to happen, that position us -- positions us within the range of our corporate liquids, maybe little under average, but sort of in line there. I mean that's not our goal. Our goal would be to beat the high-end so is that possible what has to happen. We certainly have the well count to make that happen. We've got round numbers, let's call it, 1/3 to 40% of the total wells on in that number and we're starting to moving sort of relatively steady over the next 5-ish months or so. We highlighted a pretty -- there is a decent amount of activity coming out of this over the rest of this quarter. Of the 11 wells that we talked about in Q2, about half of those are on right now. So the other stuff is coming pretty quickly at us. And then another decent round in Q3. So we're -- we keep taking about being well positioned relative to our liquids guidance and I think those are good words. We are dealing with some really near time data, I think that pad has the wells aren't even on yet. So we don't have a lot of runtime on it, but we feel pretty good right now and made a decision to give you fair amount of color on this so they would understand sort of the noise, if you will, moving to the first quarter on the liquids side.

We have a question from Brian Kristjansen, Macquarie.

I didn't have an extra one. That was just my original.

That does conclude the questions in the queue at this time. I'll turn the call back to the presenters.

Thank you very much. We appreciate your time this morning. I know there's a lot of reporting going on around so I'll let everyone get back to it. But thanks, again. Have a good day, cheers.

Thank you very much. Ladies and gentlemen, this concludes today's conference. You may now disconnect.