Enerplus' (ERF) CEO Ian Dundas on Q1 2018 Results - Earnings Call Transcript
Enerplus Corp. (NYSE:ERF) Q1 2018 Earnings Conference Call May 3, 2018 9:30 AM ET
Drew Mair - Manager, IR
Ian Dundas - President & CEO
Jodi Jenson - SVP & CFO
Ray Daniels - SVP, Operations
Garth Doll - Manager of Marketing
Greg Pardy - RBC Capital Markets
Brian Kristjansen - Macquarie
Travis Wood - National Bank Financial
Good morning, my name is Shell [ph] 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 of 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 US GAAP. 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.
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 [technical difficulty]. 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 C$155 million just above our exploration and development capital spending in the quarter of C$151 million. As we talked in the last quarter, our first quarter production came in lower in 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. And additional factors was the timing of our on stream activity in Q1 was backend 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've 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 it 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're 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 C$50 to C$55 per barrel less taxes. Now with the current forward stripped in the mid C$60 range we're forecasting our adjusted fund flow to exceed capital expenditures and our dividend by approximately C$100 million. We remained well positioned relative to our plans this year, we're on track to deliver strong returns on a 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 $3.27 per barrel this quarter which was wider than our 2018 guidance of $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 at our Bakken production for the remainder of 2018 at an average differential of just under $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 $3.50 per barrel below WTI.
We also saw differentials for our Canadian oil production widen by over $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 $0.21 per Mcf below NYMEX. We've seen quite meaningful pipeline expansion in the Marcellus in the last six 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 US.
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're leaving our average 2018 Marcellus differential guidance unchanged at $0.40 per Mcf below NYMEX. Our operating cost G&A and transportation expense during the quarter were all consistent with our forecast and as a result we have left guidance unchanged. Adjusted fund flow with C$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 C$535 million and C$585 million which is also unchanged. Notwithstanding this free cash flow generation, we'll 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 0.5 times.
I'll now turn the call over to Ray.
Thanks Jodi. Operational execution is going as we've 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've largely anticipated due to offset frac activity and our completion scheduled was waited to later in the quarter to minimize the impact of a typical bad weather we see earlier in the year. Now as we've come through April, we're seeing the strong ramp in our production 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 six-well pad. The day we get four of the six wells on production and are encouraged by the strong initial raise, we expect to have the two 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 on stream from two 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. Productivity 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 couple of notable items operationally in Canada in the first quarter. We drilled and brought on production two Ratcliffe wells in southeast Saskatchewan which are being outperforming our pre-drill expectations. We believe one of the wells is on track to be among the top producing wells in Saskatchewan in 2018.
And Ante Creek, the increased water injection has helped rest of oil decline and stabilize oil production which is anticipated to begin to increase during the second half of 2018. And lastly in the DJ Basin, our initial well and the play is continuing to produce an encouraging rate. In April, at seven-month on production, the well averaged 400 barrels of oil equivalents per day 73% oil. We're drilling four wells in DJ Basin in 2018 with plans to bring the wells on production in the third quarter.
In summary, the growth we've 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 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. Your line is open.
Ian, really three quick ones or actually two 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 7% NCIB in place, what you're thinking about acting on that and how aggressively?
I mean 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 think we're little more interested in building for the future and those sorts of things, but it will be something we'll evaluate on a real-time basis. You asked will we be aggressive, we put Ante in the place for only C$200 million, so I think that inherently isn't aggressive, but we've sort of discussed. So it will be a tactical tool that we'll look out circumstances make sense for us.
Okay, great. And just the other question is on the [indiscernible] realizations. Have you since the first quarter results since - have you seen improvements in terms of realizations versus the benchmark or and can you just talk about your egress positioning and so forth.
Actually we've got Garth Doll, here is our Manager of Marketing. Garth, I don't know - he will give you a little context on that.
Yes, we're seeing some improvements certainly in the Canadian differential side, heavy depths have improved the $15 level here for June. There 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're positioned on the Canadian differential side for the rest of this year.
Yes I'm thinking more just light and then vis-à-vis the benchmark like your realization versus the benchmark.
We don't expect our realization to improve relative to the benchmark certainly through the third and fourth quarter. The egress on the oil side - it needs - this is obviously we need to some pipeline egress improvements for sure. Gas realizations were fully hedged so we're insulated from this incredibly week ACO basis market that we're seeing as well, so we believe we'll continue to outperform both crude and gas benchmarks in Canada.
Thanks very much.
Unidentified Company Representative
And just for a little bit of extra context for those who might not recall. We're producing 49,000 barrels a day Canadian oil is approximately 10 of that split pretty evenly between heavys and light, so we saw those differentials wide and open, but it's not particularly meaningful for us on the gas side, we've very, very little Canadian gas exposure obviously.
Very good. Thanks very much.
Thank you. Our next question comes from Brian Kristjansen from Macquarie. Your line is open.
Just had a question about your Bakken rates. It looks like the Q1 IP30's looked a bit lower than type curve, but clearly Q2 sound like they're 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 were 14-ish if I recall, so directionally in line, we're getting to believe the little to here, there was a little bit of operational noise on some of those wells. So some of those wells, even though the 30-day rates they actually included a period where which during this the wells were cleaning up, so those wells if you sort of chosen peak 30 days which we didn't have that much time, it 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 six-well pad it's the CATs pad. And it's real-time right now, we only have four of those six wells on. We would certainly expect there to be outperform on the four that we've seen, we'll see how long that last but we'd expect that to show up in the early time data for sure, it's encouraging.
And was that location based or completion style based, are you still experimenting with greater frac intensities?
There's a range of areas, so this would be in area that's maybe a little better than average from a type curve perspective. We have seen, we do continue to do - I don't know 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 four wells we've seen. We actually have seen this - some differences in completion technology that encouraging what we're 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 lot of our operational activity over the next, on a go forward basis is going to be dominated by pad development, right. And so that sets up, there's obviously a little bit of lumpiness comes with that, but it sets up potential advantages and [indiscernible] and [indiscernible] 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 six high working interest wells on a pad before. It's - I think the biggest operation we brought on, so we're very encouraged by the success we're seeing right now. Ray, you'd like to add to it.
Ray Daniels here. With the multi-well 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 understand with 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 our value.
Great. Thanks Ian. Thanks Ray.
[Operator Instructions] our next question comes from Travis Wood, National Bank Financial. Your line is open. And please go ahead, your line is open.
Travis, we can't hear you. If you can hear us.
There we go, hi Travis.
I wasn't muted by the way.
I was trying to understand you've guided the Q2 liquids corporate number 48 to 50 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 bring in the pad on, and then can you help us guide into lumpiness, into - is it another step function in Q3 and then flatter or should we start to layer in big exit rate to get to the 49 or 50,000 than average number.
Sure, let me hit this a couple ways. So this is all but North Dakota. 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 so came from two pieces Ray talked about the downtime and we always see downtime, right this would have been on anticipated, not anticipated. Extraordinary down time 2,000 to 3,000 barrels. We also had normal decline because there is people may recall, we're 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 eight wells that was actually five net and those again pads largely came on effectively in March, so didn't give you a lot of rate. Right so that's 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 five's and we've not got four high working interest wells on right now, so that takes us switching to oil now to 49,000 Boe corporate, sort of barrels of oil corporately. So then let's talk about the rest of the year.
So I mean everyone's pretty good at math. So liquids were guiding between 46 and - 50,000 barrels over the year. if you just assume we hit the mid - if we would just keep this 49,000 constant over the course of the year just assume that where to happen, that positions us within the range of our corporate liquids 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 you know if that's possible that has to happen, we certainly have the well count to make that happen. We've got round numbers let's call it third to 40% of the total wells on in that number and we're certainly moving, sort of relatively steady over the next five-ish months or so, we highlighted pretty. There's a decent amount of activity coming at us over the rest of this quarter so off the 11 wells that we talk 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 ramp in Q3. So we keep talking between well positioned relative to our liquids guidance and I think those are good words. We're dealing with some nearly near time data like pad has two wells aren't even on yet. So we don't have a lot of run time on it but we feel pretty good right now and made a decision to give people fair amount of color on this. So they would understand sort of the noise if you will move into the first quarter on the liquids side.
Okay, thank you.
And thank you. We have a question from Brian Kristjansen, Macquarie. Your line is open.
Didn't have an extra one that was just my original.
Thank you. That does conclude the questions in the queue at this time. I'll turn the call back to the presenters.
All right, well thank you very much. We appreciate everyone's time this morning. I know there' a lot of reporting going on. So we'll let get everyone back to it. But thanks again. Thanks again. Have a good day. Cheers.
And thank you very much ladies and gentlemen. This concludes today's conference. You may now disconnect.
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