Nov 10, 2017
Executives
Drew Mair - Manager, IR Ian Dundas - CEO & President Raymond Daniels - SVP, Operations, People and Culture Eric Le Dain - SVP, Corporate Development and Commercial Jodine Jenson Labrie - CFO and SVP
Analysts
Michael Dunn - GMP Securities Jason Frew - Crédit Suisse AG
Operator
Good morning, my name is Sharon, and I will be your conference operator today. At this time, I'd like to welcome everyone to the Enerplus' 2017 Third Quarter Results Conference Call.
[Operator Instructions]. Drew Mair, Manager of Investor Relations, you may begin your conference.
Drew Mair
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 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; Ray Daniels, Senior Vice President, Operations; Eric Le Dain, Senior Vice President Corporate Development, Commercial; Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer; and Shaina Morihira, Corporate Controller.
Following our discussion, we'll open up the call for questions. With that, I'll turn the call over to Ian.
Ian Dundas
Good morning, everyone. Thanks for joining us today.
The key message we hope you take away from our third quarter release is that we are on track and on budget to execute our plan this year, and remain well positioned with respect to our long-term targets. Our strategic plan is anchored on a capital program, which is delivering robust returns and supports meaningful cash flow growth per share while maintaining our highly competitive financial footing.
With over 85% of our 2017 capital program directed to our oil projects, we entered the year anticipating 25% company liquids growth, from the first quarter to the fourth quarter of 2017. I'm pleased to say that we are on pace to meet this target despite having sold one of our Canadian oil waterflood properties earlier in the year.
Importantly, our capital budget of $450 million has not changed. This morning, we tightened up our 2017 liquids production guidance to the midpoint of 40,500 barrels per day and narrowed our fourth quarter liquids production range to 45,000 to 46,000 barrels per day.
We are well positioned to achieve our Q4 liquids target. As October liquids production was 44,600 barrels per day, up from our Q3 liquids production of just under 39,000 barrels per day.
Turning to the Marcellus. Pricing in Northeast Pennsylvania was soft in September and October, with the daily cash prices at times trading below the U.S.
-- USD 1 per Mcf. In our view, this pricing weakness is transitory as we believe we are in the final stages of reaching a more balanced regional supply/demand dynamic.
Given this view of the near-term structural improvement in Marcellus pricing, we saw no reason to fully produce into a weak market. We remain committed to focusing on value and not volume and see the decision to curtail production as prudent.
Frankly, I would find any other decision peculiar. On account of the price-related gas curtailment in the Marcellus, we have revised our total production guidance.
We are now guiding to full year 2017 production of 84,000 BOE per day, which is the lower end of our previous range and fourth quarter production of 86,000 to 88,000 BOE per day. And lastly, before I turn the call over to Ray, I'd like to reiterate the strong financial position we are in, and highlight the resiliency of our growth plans.
At the end of the third quarter, our net debt to adjusted funds flow ratio stood at 0.7x and we're committed to maintaining our balance sheet strength and believe this will be a competitive advantage for our company. As we think about our plans for 2018, and while we're not yet out with our guidance, the principles, which have guided our decision making remain intact.
A plan, a grounded in the returns-based capital allocation, price risk mitigation to protect the economics of our capital program and the support of a conservative balance sheet. The majority of our capital next year will once again be directed to North Dakota and our 3-year compound annual growth targets of approximately 10% total production growth and 20% liquids growth on a divestment-adjusted basis remain on track.
And now, I'll pass the call to Ray to talk to some of the operational highlights of the quarter.
Raymond Daniels
Thanks, Ian. Starting in North Dakota, we had slightly low production quarter-over-quarter due to the completions program being weighted towards the end of the third quarter.
This, in part, is due to the lumpiness that comes with pads development. As Ian mentioned, the ramp-up in fourth quarter oil production underway as planned.
With the number of strong wells come on stream during September, this included 4 wells on our Snakes pad with an average peak day-to-day production rate per well of 2,185 barrels of oil equivalent per day. We also brought on stream 2 wells at our Crane's pad with an average peak day-to-day rate per well of approximately 1,870 barrels of oil equivalent per day.
Of the 10 completions in the quarter, 7 were completed using our base proppant intensity design of 1,000 pounds per foot and 3 with a higher proppant intensity. 2 of the 3 higher proppant intensity wells were completed using 2,000 pounds per foot and 1 using 1,500 pounds per foot.
These 3 wells had an average peak day-to-day production rate per well of approximately 2,470 barrels of oil equivalent per day. These are strong results and as we think about the application of higher intensity completions in relation to our development plan, certain locations will see better economics with higher intensity completion than others.
Along with the other well performance testing and analysis we have done, we're headed to a place where each variable that impact the cost and performance of the completion can be customized in order to maximize the value of that well and its pad. Turning to the Marcellus, production was sequentially lower as volumes in September were curtailed in response to pricing weakness.
25 million cubic feet per day in September was curtailed. And as prices weakened further in October, curtailment increased to 35 million cubic feet per day.
Currently, we're don't envision additional curtailment during the remainder of the fourth quarter as we anticipate higher pricing. And in early November, we returned to producing at unrestricted rates.
Moving to Canada. It was a relatively quiet quarter in terms of capital activity.
We're continuing to advance to full field waterflood development at Ante Creek. We're a little behind initial water injection plan.
We have 4 wells currently on projection, on track to have 6 wells on by year end and working towards having the final 3 outstanding injection well locations being in operation in the first half of 2018 completing our overall waterfloods design of 9 injectors. I'll now turn the call over to Eric to speak about our marketing and investment activities.
Eric Le Dain
Thanks, Ray. I'll start with our Bakken differentials.
As expected, we saw these improve by over USD 2 a barrel versus the second quarter to average USD 324 per barrel below WTI. The Broader Bakken market had a full quarter of the Dakota Access Pipeline in operation, which when combined with ongoing Canadian synthetic supply outages and some disruption due to the hurricanes in the Gulf Coast, helped drive the narrow differential.
I think that we will benefit from even tighter differentials in the fourth quarter. We're guiding to a fourth quarter Bakken differential of USD 2 per barrel below WTI.
With the strength we have seen in recent pricing, and considering that some of the drivers are more temporary, we took steps to lock in some additional volumes at these tighter differentials. We have now entered into 2018 term sale contracts on an average of 14,000 barrels per day at a weighted average differential of USD 2.70 per barrel below WTI for Bakken production.
The remainder of our Bakken portfolio is exposed to floating market differential prices. In the Marcellus, as Ray noted, we saw differentials widened considerably in September.
In our view this was a result of milder than average weather in the Northeast United States combined with incremental supply coming on stream in anticipation of the subsequently delayed Rover pipeline. Marcellus pricing weakened further in October with Leidy daily cash prices averaging USD 0.76 per Mcf.
We do anticipate stronger pricing in November and December as additional pipeline capacity comes on line, along with normal heating demand. That said, with the pricing weakness in October, our fourth quarter Marcellus realized differential is expected to be approximately USD 1.05 per Mcf below NYMEX.
We continue to see 2018 as a pivotal year for Marcellus pricing with some large FERC approved pipeline projects expected in service in both the southwest and northeast Marcellus. We expect our average 2017 Marcellus differential below NYMEX to be approximately USD 0.80 per Mcf, and expect this will tighten meaningfully in 2018.
Our current view of 2018 is that our realized Marcellus differential, excluding transport costs, will average about USD 0.40 per Mcf below NYMEX. We plan to form this number up when we provide our 2018 guidance.
Briefly on hedging, we've added to our 2018 and 2019 crude oil hedge positions and now have approximately 70% of 2018 and over 30% of 2019 crude oil production net of royalties hedged based on 2017 volumes. These hedges are predominantly 3-way caller structures with participation up to about USD 60 to USD 62 per barrel WTI.
Lastly, I'll provide an update on our noncore divestment activity. We've had considerable success in 2017 moving lower margin, high liability assets that do not compete for capital internally out of the portfolio.
We currently have remaining about 5,000 barrel oil equivalent per day of noncore production, largely Canadian gas. In general, these assets have a higher operating costs in our corporate average and they won't generate meaningful sale proceeds.
But moving them out of our portfolio will continue to improve focus, enhance margins and reduce liabilities. We are currently working to divest some of these noncore assets and if successful, would plan to incorporate the implications of those investments into over 2018 guidance, which we expect to issue towards the first half of December.
I'll now turn the call over to Jodi to talk about our quarterly financial results.
Jodine Jenson Labrie
Thanks, Eric. Our adjusted fund flow in the quarter was just over $90 million.
This was down from the previous quarter, primarily due to wider natural gas differentials, the stronger Canadian dollar as well as lower volumes. Offsetting this, was the USD 2 per barrel improvement in our Bakken differential as well as lower transportation costs.
The $25 million cubic feet per day of curtailed Marcellus production during September reduced our transportation cost. However, the loss of lower cost production contributed to higher overall third quarter operating expenses of $6.71 per BOE.
Operating costs were up 15% from the prior quarter while transportation expenses were down 3% from the prior quarter to $3.61 per BOE. Total cash G&A expenses were broadly flat from the previous quarter at $11.7 million.
On a per BOE basis, cash, G&A expenses were slightly higher than the prior quarter averaging $1.61 per BOE. We revised our 2017 operating expense guidance modestly higher and our transportation and cash G&A expenses guidance lower.
Overall the net effect is $0.15 per BOE reduction in our cost guidance. In addition, we ended the third quarter with debt, net of cash of $318 million, down over 50% from the same period a year ago.
Our debt to fund flow ratio and debt-to-EBITDA ratios remain unchanged from the second quarter at 0.7x and 0.8x. Finally, subsequent to the quarter, we extended the term of our $800 million bank credit facility by 1 year, which now matures October 2020.
That is a no change to our pricing and covenant and the facility currently remains undrawn. With that, I'll pass the call back to Ian for some closing comments.
Ian Dundas
In summary, we are pleased with our operating and financial performance to date 2017. Our execution has been solid and we remain confident that we will deliver on our targets, finishing the year with strong operating momentum.
Looking ahead into 2018, I think we are very well positioned to continue to deliver competitive, profitable growth through our disciplined and [indiscernible] focused approach to capital allocation. With that, I'll turn the call over to the operator, and we will be available for questions.
Operator
[Operator Instructions]. Your first question comes from Michael Dunn from GMP FirstEnergy.
Michael Dunn
Ian, I think somebody asked this question 3 months ago, just looking for an update on how you folks are seeing the cost environment in North Dakota as you head into 2018?
Ian Dundas
Yes, the 2018 look has evolved over the course of '17 and you can sort of plot it against the oil deck. At the end of last quarter, we said if you think about a $50 world, think about 5% kind of top line inflation.
That probably holds, we're pointing to something little above $50 now. So I think $50 and 5% is not a bad way to think.
I think from our perspective, we've taken advantage of maybe weakness over the course of the year to be able to lock in a fairly large percentage of our cost structure next year. So when we think about our North Dakota program, which will be the lion share of our capital next year, we're locked up on at least half of that at pricing that looks relatively consistent with price dynamic we've been dealing with over the course of the year.
So our goal next year would be North Dakota capital efficiencies pretty flat year-on-year. It feels like there's a little bit of tension in the system, sort of upward pressure on it, but hasn't been manifested yet, and again we're pretty well protected.
Operator
[Operator Instructions]. Your next question comes from Jason Frew with Crédit Suisse.
Jason Frew
This may be more for Eric, on differentials. Just curious on the Bakken side you said you had locked and I think 14,000.
Can you just walk us through how you view the short term dynamics versus the sustainably of that short term over the long run? Why that may not be sustainable?
And then maybe on the Marcellus, what on some variables that might move your assessment around for 2018 and beyond? If there are any delays in the system that you are aware of?
Eric Le Dain
Sure. Looking at the Bakken first.
Why we feel that the market is performing as well as it has been in the last few months through December, probably into the early new year, is, in part, that down time [indiscernible] Canadian synthetic production, which normally flows into the mid-continent and that created a bid at Clearbrook for more additional Bakken barrels to replace that. The hurricane disruptions, a lot of refineries had to adjust sourcing and they had to actually, after they started back up, feed in lighter barrel they can't just flow heavy into the complex initially.
So that created an incremental demand. So we felt that has pushed things, which currently are closer to really flat to WTI, kind of Bakken supply region.
Currently pushed that a little tighter than maybe what we see as the long-term dynamic, which, to us, will be more defined by the variable cost to flow on marginal pipelines out of the Bakken toward the Gulf Coast and then relative price at the Gulf, which we see to be a bit wider. And that drove our decision to head some incremental volumes because we believe that had a, it's a good price point and also had a prudent methodology to help manage cash flow protection.
Your question on the Marcellus, the Marcellus as we said in our release has been probably a function of the Rover delay and the incremental supply that came on kind of in a milder Q3 weather wise, pushing prices wide. As we see the pipeline projects that directly impact us in the Northeast coming on in fourth quarter '17 and through '18, we see a much better balance in the supply demand dynamic.
And as we look at that slate of pipeline projects, certainly some may be delayed I mean,, we just saw Leach which has more impact on the Southwest, Marcellus in the Northeast just delayed a couple of months, but we continue to see progress and projects coming on-stream.
Operator
[Operator Instructions]. We do not have any questions at this time, I will turn the call over to the presenters.
Ian Dundas
Thank you. And folks, it's a pretty busy day for many of you.
I just want to take just a brief moment to recognize the loss of long-term Enerplus employee Rick [indiscernible]. Rick was with our company for over 30 years, which is a pretty rare event these days.
He was one of the key players in our marketing group and played a really big role as we expanded our operations into the U.S., which is a big part of our company now. He's well known and was well-respected in industry.
He passed away this last weekend after a long battle with cancer. He was truly one of the good ones and will be -- missed and our thoughts go to his wife, Jennie, and children, Dan and Brent, and rest of the family.
All right. Thank everyone.
Appreciate calling in today and really busy day. And have a good rest of your day.
Thank you.
Operator
This concludes today's conference call. You may now disconnect.