Feb 24, 2017
Executives
Drew Mair - Manager, Investor Relations Ian Dundas - President and Chief Executive Officer Jodine Jenson Labrie - Senior Vice President and Chief Financial Officer Raymond Daniels - Senior Vice President, Operations Eric Le Dain - Senior Vice President, Corporate Development Commercial
Analysts
Patrick O'Rourke - AltaCorp Capital Adam Gill - CIBC World Markets
Operator
Good morning. My name is Sherrin, and I will be your conference operator today.
At this time, I would like to welcome everyone to the Enerplus Corporation 2016 Year-End Results Conference Call. All lines have been placed on mute to prevent any background noise.
After the speaker remarks’ there will be a question-and-answer session. [Operator Instructions] Thank you.
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 am 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, and Jodi Jenson Labrie, Senior Vice President and Chief Financial Officer.
Following our discussion, we will open it up for questions. With that, I will now turn the over to Ian.
Ian Dundas
Thanks Drew. Good morning, everyone.
Thanks for joining us today. 2016 was a pivotal year for Enerplus.
In addition to continued strong operational performance, we had considerable success strengthening our balance sheet as we remained committed to our plan of focusing and high grading our portfolio. Our non-core asset divestment program generated aggregate proceeds of $670 million, which combined with a modest equity raise allowed us to reduce net debt by $840 million or almost 70% reduction from the beginning of the year.
Our focus on managing and reducing our costs yield at a reduction of over $100 million of cash costs relative to our initial 2016 budget. When you put this number in context of $306 million in funds flow in 2016 you see how impactful this cost reduction is to our margins.
We saw important structural improvements to our realized pricing, particularly in North Dakota, where differentials have significantly tightened. And we believe there is room for further improvement with additional pipeline capacity expected in service this year.
We continue to deliver competitive F&D costs at $4.82 per BOE on a 2P basis, including future development capital and $4.77 per BOE on a PDP basis. And despite an exceptionally limited capital budget, reserve replacement in our core growth areas was strong.
We replaced 207% of Operated North Dakota Production and 175% of Marcellus production via the drill bit through 2P reserve additions and revisions in the year. The success we had in 2016 has laid the foundation for Enerplus to deliver what we think will be differentiated growth over the coming years.
We see an ability to deliver 20% compound annual liquids production growth through 2019, funded through cash flow at $55 TI and $3 NYMEX. The key driver of this organic growth is our core position in North Dakota, where we are increasing activity level this year and expect to continue to accelerate activity into 2018.
We will however, always remain disciplined at our capital plans. We will not chase unfettered, unprofitable growth, and our capital allocation remains firmly grounded on the principles of value of full cycle returns.
Lastly, before I turn the call to Ray to discuss the operational highlights, I would add that Enerplus focused on environmentally responsible and safe operations has been and will remain cornerstone of the Company's consistent and high performing operational execution. Ray, over to you.
Raymond Daniels
Thanks, Ian. We met or exceeded all of our operational targets in 2016.
These included delivering strong production in line with our forecast, reducing operating cost per BOE by 17% year-over-year, delivering exceptional capital efficiencies demonstrated by a top curtail, possibly top decile F&D costs, reducing our North Dakota drill, complete and timing costs by over 20% year-over-year and increasing our high quality drilling inventory in North Dakota by nearly 40% with our move to higher density drilling, and we have the safest year in our history. In addition, through proactive contracting in 2016 was secured and protected about 75% of our North Dakota capital program from escalation in 2017.
I am very pleased with our performance and excited about the year ahead as we ramp up operations. In fact, this year in North Dakota, we will complete and bring on stream more wells than in any previous year.
Although we experienced extreme weather conditions in North Dakota, the tail end of last year and the start of this year, our program is on track for 2017. Staying in North Dakota, we had a relatively limited capital program in the fourth quarter.
Capital activity was centered on a three-well density test, that’s what we call a fishing pad. As a refresher, this was two Middle Bakken wells spaced 500 feet apart offset by a First Bench Three Forks well at 700 feet.
Production performance from these wells has been very strong with all three tracking the high end of type curve expectations. Each well has produced over 100,000 BOE’s during the initial 90 days of production and the wells are currently producing approximately 850 BOE per day on average and/or in the fifth months of production.
One of the goals for this test was to better understand the impact of higher density drilling wells on longer term production performance and ultimate recovery. We are encouraged with these results and we will continue to monitor the wells performance.
In addition to further drilling density testing this year, we will test various completion designs to try and further improve our capital efficiency. Turning to the Marcellus, we saw a modest increase in activity levels in the fourth quarter in response to improve regional pricing.
Prior to fourth quarter, drilling activity in the Marcellus had essentially stopped. Our 2017 capital budget in the Marcellus is approximately $60 million, which is more than double what we spent last year, but still reflects relatively modest drilling and completions activity.
We do expect some increase an activity in 2018 in advance of new pipeline projects coming into service in the region. In our Canadian waterflood portfolio, we have been continuing to focus on expanding and optimizing secondary and tertiary recovery, but also enhancing profitability through cost efficiencies.
We've been able to bring operating costs in the waterfloods down by over 30% over the last two years. In par this has been due to divesting higher cost properties, but also through driving efficiency improvements.
In our new anti-Creek asset, we consolidated plant and equipment resulting in significant operating cost savings and after successfully stimulating a [source water rail], we have started ramping up water injection volumes in accordance with the development plan. Once again our waterflood assets will generate meaningful free cash flow in 2017 and to continue to help moderate our overall decline.
I'll now turn the call over to Eric.
Eric Le Dain
Thanks Ray. I wanted to touch briefly on our Bakken and Marcellus differentials, providing an update on our crude oil hedge position.
The decline in Basin production in the Bakkan in 2016 is meant that less rail is required to clear the basin. This dynamic combined with strong local refining demand help narrow Enerplus Bakken differential to WTI in 2016 by approximately US$2 per barrel compared to 2015.
We have seen a meaningful improvement in our Bakken differential over the last couple of years and we think that we will see another step change with the completion of the Dakota Access Pipeline around mid 2017. Bakken differentials from March are trading tighter than US$5 per barrel below WTI today.
The Bakken portfolio is well-positioned to take advantage of these narrowing differentials. We have approximately 50% of our expected production in 2017 contracted under firm sales agreements.
However, the majority of these sales are at floating market differential prices. We will add to our term sales portfolio and lock in these type of differentials as opportunities arise throughout the year.
Accordingly, we are updating our forecast to 2017 Bakken differential to US$4.50 per barrel below WTI, a 40% improvement from 2016. This improvement in our realized pricing is another area that is helping to drive our margin expansion.
In the Marcellus, we also saw differentials improve through the fourth quarter and into the new year. With the lack of drilling activity in the last couple of years, the industry in Northeast Pennsylvania has worked through a good part of its inventory of curtailed production index, while regional demand and takeaway capacity have steadily grown.
The daily correlation between the in-basin spot pricing and the NYMEX so far this winter has reverted to levels we last saw in the winter of 2013, 2014. In basin forward prices today are pointing to a tighter basis in 2017 and beyond.
We are forecasting a US$0.90 per Mcf realized differential below NYMEX in 2017 for the Enerplus sales portfolio and think it will tighten further in 2018. Turning to commodity price risk management, our financial hedges are designed for us to both protect our 2017 capital plan economics and our 2017 funds flow.
We have on average 18,000 barrels per day or 63% to forecast crude oil production net of royalties hedged for 2017 at price levels that support our economic returns. We also have 12,500 barrels per day of crude oil protected in 2018 with 4,000 barrels per day protected for 2019.
With that, I’ll turn the call over to Jodi.
Jodine Jenson Labrie
Thanks Eric. As Ian mentioned earlier, we significantly strengthened our financial position in 2016 during an extremely challenging market environments.
We reduced our total debt net of cash and restricted cash by over $840 million or approximately 70% ending the year with a net debt to trailing adjusted funds flow ratio of 1.2 time. On a forward-looking funds flow basis, this ratio is expected to be below one-time at the end of 2017.
Importantly, the bulk of our debt reduction did not come at the expense of significant dilution, but instead it was a result of our divestment program which is continuing to drive efficiencies across the business. Restricted cash balance at year-end reflects the proceeds from the sale of our Non-Operated North Dakota Assets, which we chose to place in escrow with a qualified intermediary.
These fund maybe held in escrow for a period of up to 180 days from the date of closing in order to facilitate a possible like-kind exchange in accordance with U.S. federal tax regulations.
Essentially, this is a tax efficient option for us if we were to pursue certain U.S. based acquisition opportunities.
To be clear, this does not mean a transaction will happen, but this option comes at virtually no cost to us and could help with future tax planning. In the fourth quarter, we completed a one-year extension of our $800 million bank credit facility, which now matures October 31, 2019 with no changes to our terms or covenants and the year-end we were only 3% drawn.
We have made significant progress continuing to reduce cost across the business, which has been key to ensuring we can execute on our profitable growth strategy in a lower commodity price environment. In 2016, we match or beat all of our guidance targets and realized over $100 million in annual cost saving.
These include interest savings from lower debt level as well as savings on operating costs, transportation expenses and G&A compared to our original 2016 guidance. Our net income was $840 million during the fourth quarter.
This was the result of $339 million gain on the sale of our Non-Operated North Dakota properties as well as a reversal of a portion of the valuation allowance on our deferred tax asset at year-end. Adjusted fund flow for the quarter was $108 million or 34% higher than the third quarter as commodity prices continue to improve.
As I reflect on 2016 and the challenges we faced at the beginning of the year, it was very clear in our minds, but that’s we needed to take. The news quickly and aggressively to reduce capital on our dividend, as well as sell non-core asset with the final step being a modest equity rise in May.
Now in 2017, we can use our financial strength and improve margins to reestablish long-term profitable growth and create additional value for our shareholders. I will now pass the call back Ian for some closing comments.
Ian Dundas
Thanks Jodi. In summary.
We are well on truck to deliver substantial production and cash flow growth in a potentially ring bound certainly volatile commodity price environment. Our balance sheet is strong, capital efficiencies are among the best in industry and we have a deep high rate of return inventory.
With that, we will turn the call over to the operator and are available for your questions.
Operator
[Operator Instructions] Your first question comes from Patrick O'Rourke from AltaCorp. Your line is open.
Patrick O'Rourke
Hey, guys. Great here and looks like you've done some really good things.
I just have a couple of reserve based questions here. First, question south of the border in terms of the Bakken asset and it looks like you guys have reduced FDC at least the 2P level and actually the 1P level year-over-year.
You've done some dispositions costs are coming in lower, but there's also the inner play of higher density drilling? Can you guys just kind of give some color in terms of how your books right now in the Bakken, especially in terms of that higher density drilling please?
Eric Le Dain
Sure. This is Eric.
I can talk to that. Looking at how we're booked today or probably our average EUR for – plus PDP in North Dakota is about 726,000 BOE just over 600 oil and we're looking for our UDs at roughly similar level about 720,000 barrel oil equivalent.
Patrick O'Rourke
But I guess more what I'm looking to understand is you've had the success with the higher density drilling. Have you booked more locations because the FDC number did come down year-over-year and I know some of that will be with the dispositions that you've done and like we mentioned cost savings or the cost curve coming down.
I'm just trying to understand how tightly the engineers would be booking you there now?
Ian Dundas
Yes. We added roughly 17 locations for UDs at year end, and I need to correct something, I said 720,000 is in oil booking level for UDs.
So about 17 incremental locations with associated FDC and there was some cost reduction deferred of FDC and they actually netted out the overall pluses and minuses ended at about minus $4 million in the end on the change in FDC.
Patrick O'Rourke
Okay. So are those 17 wells still booked on the old spacing assumptions or if they gone to kind of the new piloting assumptions?
Ian Dundas
Everything is put in context of that 10 wells per DSU spacing.
Patrick O'Rourke
Okay. And then just one quick question north of the border, in terms of the Ante Creek asset that you've acquired and I know you see quite a lot of upside there from potential water flooding.
Is it safe to assume that that's not booked in the PDP of that asset as of right now and that could be something that's a bit of a tailwind as we move into that and started thinking about the 2017 reserve report?
Raymond Daniels
That's correct. We have not booked reserves for that waterflood potential beyond existing PDP.
Ian Dundas
Patrick on that I think you said 2017. I think its 17, maybe 18.
Patrick O'Rourke
Okay.
Ian Dundas
As Ray said in the note, we’re positioning to start significant water injection and so as you may recall we talked about this build coming, the production build over the next sort of two-ish years.
Patrick O'Rourke
Yes.
Ian Dundas
And so you're sort of right around that time table, so we’ll see how it goes.
Patrick O'Rourke
Okay. Thanks a lot guys.
Operator
[Operator Instructions] Your next question comes from Adam Gill from CIBC. Your line is open.
Adam Gill
Hi guys. Two questions, one just in the Marcellus.
Is there anything that you're doing to actively protect the stronger differentials that were seen in 2017 and 2018? And then my second question, this one is pretty high level.
But just in terms of the 2017 plan, where do you see the biggest risk in your plan and where do you think the area is where you're most likely to outperform your plan?
Ian Dundas
Maybe I’ll hit those both quickly. We've got quite a bit of detail in our Investor Presentation that’s talked about our marketing portfolio, transport portfolio in the Marcellus.
So we were quite proactive on that in anticipation of tightening up. So I think we’re really well positioned to dealing with that.
There's some short-term stuff that we've started looking at right now as we manage the near-term. The risk in the portfolio or in the program, the capital program, on one hand it is a significant increase in capital from where we were and Ray talked about the most completions we’ve had in our history, but it's a pretty discrete program.
We are going from one rig to two rigs and the system is pretty well. One of the things that we were particularly concerned about it nine months ago cost inflation associated with this.
And so we got out in front of it and we’re able to secure the lion share of the program. So as these things go, I think it's a pretty well understood machine that we’re just ramping up a bit.
So I would say there's no dramatic risks associated with obviously the next program. Now the guys on the ground are already talking about, we're about to go, spend a lot of money and go lot faster.
But I think it's really well understood and we’re really well positioned to be able to manage those risks. Ray, do you want to add some color to that?
Raymond Daniels
No I think you’ve covered it. We have a great team down in the U.S., they are set up and ready to go and so far we're on track and it looks like we’ll continue that way.
Ian Dundas
We’re not getting granular, right. So this weather event which got a fair amount of play in other Bakken companies call, it was dramatic, it was dramatic.
We anticipated winter and so we have built in cushions for those kinds of things, but it's significant, it takes a lot of work and that stuff continue to play out and continues to play out in a higher spend environment like it creates issues, but I think we are well positioned.
Adam Gill
Great. And just where do you think you could maybe outperform on your plan?
Ian Dundas
Well, you get 30 wells coming on. Little improvements here and there can really add up, right.
I think it would be hard to go much faster. We're not dealing with things that are – got a pretty good cycle time right now.
As you think about these 30 wells the most in our history, but we're only drilling – using two rigs. We’ve run five rigs before, right, but that then we had cycle times, it took you 40 days to drill a well and three months to bring it on.
So our cycle times are pretty fast right now. So I would think the bigger upsides are going to be as we continue optimize this completion design.
And it could be quite impactful, we were still budgeting for $8 million well which mean 1,000 pounds of proppant and then we use a little higher cost proppant. If we can make that happen for less and you multiply that by low, you could see significant proppants and capital efficiency, but we're continuing to test lots of different things along that line.
Adam Gill
Great. Thank you.
End of Q&A
Operator
[Operator Instructions] We do not have any questions in the phone at this time. I will turn the call over to the presenters.
Ian Dundas
Well thank you very much. Appreciate your time and hope everyone enjoys the rest of their day.
Cheers.
Operator
This concludes today’s conference call. You may now disconnect.