May 9, 2014
Executives
Ian Dundas – President and CEO Ray Daniels – SVP, Operations Eric Le Dain – SVP, Corporate Development, Commercial Jodi Labrie – VP, Finance
Analysts
Greg Pardy – RBC Capital Markets Aaron Bilkoski – TD Securities Kyle Preston – National Bank
Operator
Good morning, ladies and gentlemen. My name is Erin, and I will be your operator today.
At this time, I would like to welcome everyone to the Enerplus Corporation 2014 First Quarter Results Conference Call. At this time all lines have been placed on mute to prevent any background noise.
After the speakers’ remarks we will have a question-and-answer session. [Operator Instructions] Thank you.
I’d now like to turn the call over to Ms. Jo-Anne Caza, Vice President, Corporate Relations.
Ms. Caza, you may begin.
Jo-Anne Caza Thank you very much, Erin. Good morning, everyone.
Thanks for joining us this morning. Ian Dundas, our President and Chief Executive Officer will be providing an overview of our results for the first quarter that we released this morning.
Ray Daniels, Senior Vice President of Operations will also give some additional detail on our capital spending on our operational performance in the quarter. We also have Eric Le Dain, Senior Vice President of Corporate Development, Commercial and Rob Waters, Senior Vice President and Chief Financial Officer on the call today.
I’d like to point out that our financials have been prepared in accordance with the United States generally accepted accounting principles. We made this change at year end as more than 50% of our shares and more than 50% of the book value of our assets under International Financial Reporting Standard which were held in the U.S.
All discussions of production volumes today is on a growth basis – sorry gross company working interest basis and all financial figures are in Canadian dollars unless otherwise specified. Conversions of natural gas to barrels of oil equivalent are done on a 6:1 energy equivalent conversion ratio which does not necessarily represent the current value equivalent.
Information we are discussing today contains forward-looking information. Listeners are asked to 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 will open up the phone lines and answer questions you may have and we will also have a replay of this call available later today on our website.
So with that, I will now turn the call over to, Ian.
Ian Dundas
Good morning everyone and thanks for dialing in this morning. We delivered another strong quarter of production and cash flow growth for investors in Q1.
Production was ahead of our expectations at 98,821 BOE a day and represented a 5% increase over average volumes in the fourth quarter of 2013. The increase was due to record production in the Marcellus which averaged to nearly 118 million cubic feet of gas a day and drove the production mix in the quarter to 58% of natural gas.
We experienced some production interruptions and delays in our capital spending due to extreme winter weather conditions in both Canada and U.S. Despite these challenges our crude oil volumes were maintained quarter-over-quarter.
Capital spending of $218 million was slightly less than planned particularly in our U.S. oil assets.
Although our drilling program was relatively active, we only completed a 11 net wells in the quarter, two Fort Berthold. We continue to see strong well performance particularly from Fort Berthold region and in the Marcellus.
Well results year-to-date are some of the best we have seen out of each of these plays. We continued with our high density tests and also saw some very encouraging production results on our first lower Three Forks test that Ray will give you some additional color on.
In spite the weather, our full year capital remains on track. We are, however, increasing our capital spending forecast from $760 million to $800 million to account for the change in exchange rate given that 60% of our program is spend in the U.S.
We continue to see strong capital performance and expected to sustain the capital efficiency improvements of last year of less than $30,000 for on-stream flowing barrel. We benefited from the increase in both AECO and NYMEX natural prices, our realized natural gas prices over 50% higher than in the fourth quarter.
We also significant narrowing of crude oil differentials in both Canada and the U.S. These changes drove a 35% improvement in our corporate net back before hedging compared to last quarter.
With the growth in production volumes and the increasing commodity prices fund flow was up 22% over Q4 to $220 million or $1.09 per share. With the ongoing improvement in the sustainability of our business over the last year, we elected to eliminate the discount within our stock dividend program in order to reduce the dilution associated with the program.
That change was effective with the April dividend payment and we saw a drop in participation from approximately 23% on average in the first quarter 10% in April. Our previously announced non-core asset sales closed in the quarter generating proceeds of $117 million which included proceeds from the sale of our core interest in the Jonah field and the final payment relating to the sale of our Montney assets.
These proceeds along with the increase in fund flow resulted in a further strengthening of our balance sheet. We ended the quarter with a debt trailing 12-month fund flow ratio of 1.3x with over 80% of this term debt and only a small amount drawn on our bank line.
So with that, I will turn it over to Ray to talk more about our operational results for the quarter.
Ray Daniels
Thanks Ian. The cold weather Ian mentioned did cost some production downtime and some capital program delays in both Canada and the U.S.
Despite this, we continued to advance programs across all of our core areas. We brought 11.5 net wells on-stream during the quarter down from 19 net wells in Q4.
This reduction was in part of the plan and in part due to weather related delays. In North Dakota, we continue to run two rigs and we are able to maintain production volumes quarter-over-quarter despite the weather interruptions.
We continue to be encouraged by our North Dakota well performance. We commenced our first high density spacing test by bringing on three wells of a seven well pattern at our Fur Bearers Pad.
There are two Bakken wells spaced at approximately 1,400 feet that came on-stream in late December and the third well that came on stream in January and the record distant between these wells about a 60-feet deeper in the Three Forks first bench. In the first 90 days of production, one of the Bakken wells produced 115,000 barrels of oil and the second 108,000 barrels of oil.
These are impressive rates particularly given the sustained performance we continue to see. The Three Forks well produced 31,000 barrels in the first 30 days and now reached over 1000 barrels a day.
We have just completed an interference test of these three wells and the results are currently been analyzed. But as you might imagine, we are very encouraged with the performance we have seen to-date.
The other well bought on-stream in Q1 was a short Bakken well. This well produced 32,000 barrels of oil in the first 30 days and the average of almost 1,100 barrels a day.
Our best short well to-date and was our best well for lateral foot. I say it was because in early April, we brought on two long horizontal wells from the Snakes Pad located on our northern most acreage up near the Antelope extension that are now our best wells to-date.
We knew this is a good area and one of the objectives from drilling these wells was to test the lower benches of Three Forks. So we drilled one-well in the Bakken and one-well in the lower bench of the Three Forks.
The Bakken well has produced 64,000 barrels of oil in the first 26 days on production that’s an average of almost 3,500 barrels a day. The lower bench Three Forks test has produced 60,000 barrels of oil in its first 26 days, an average of 23,000 barrels a day.
These cumulative production rates made on the top performing wells we have drilled from an IP data perspective and also some of the best wells ever drilled in North Dakota. We are excited about these results.
We know this area is very productive based only on our own well results but also the results from other producers in the area. However, we know the lower benches of the Three Forks are not productive across our entire acreage block and we have additional drilling coming up in the remainder of the year that will help improve our understanding of the lower zones.
The key technical change driving this better performance is the increase in tentative frac which is delivering higher production rate. We are targeting about $12 million per well and these wells are coming in on target.
In the Marcellus, production continues to perform well. We averaged 180 million cubic feet a day during quarter one up almost 10 million cubic feet a day from our exit rate in December.
Similar to what we are seeing in North Dakota, frac optimization is driving improved well performance. The amount of sand per foot has increased from 1500x to between 2500x and 4000x and the number of frac stages has doubled.
On-stream to-date in 2014 with our partner chief have achieved average 30 day IP rates of 15 million cubic feet a day with two wells producing over 20 million cubic feet a day in the first 30 days. Our Marcellus production now accounts for over 50% of our corporate gas volumes.
Our realized price increased to $4.06 U.S. per Mcf in the quarter and the net-back was $2.86 Canadian per Mcf.
With increase in NYMEX pricing and production volumes, the Marcellus generated over $46 million of net operating income in the first quarter resulting in approximately $50 million of cash flow in excess of our capital spending. We continue to see the effect of supply growth in the region, we have long-term contracts and transportation to market point an approximately 80 million cubic feet a day, which is helping to mitigate our exposure to these widening differentials.
However, roughly 55% of our volumes are not contracted. With an average of $0.88, an average discount of $0.88 per Mcf in the first quarter and April is looking to be in line with the first quarter.
In Canada, we continued our development across the waterflood portfolio during the quarter with activity at our Medicine Hat Glauconitic "C", and Pouce Coupe Boundary Lake properties in Alberta and in Southeastern Saskatchewan where we targeted the Mydeal and the Ratcliffe. In addition, we kicked off a large program in the Brooks area targeting the Manville where we expect to drill about 20 wells this year Our polymer project in Medicine Hat continues to perform well and we believe that’s a commercial success.
We are preparing for our second polymer injection project which we expect to implement in 2015. In our Canadian deep gas assets, we continued to run the program in the Wilrich and we have also drilled and completed two horizontal Duvernay wells in the Willesden Green area year-to-date.
One Wilrich well was brought on-stream late December and three others were drilled in Q1. Of these four wells one was not tied in, two wells were completed and came in are under type curve and we will complete the fourth well after break-up.
We are letting the Duvernay wells soak a few months and expect to bring them on-stream in Q2 and Q3. We will be in a position to talk about these well results in the second half of the year.
This sums up our operations activities for the quarter. Our capital program is on track with two year plans before any currency adjustments.
And we are well-positioned to deliver approximately 10% production growth year-over-year. I will now turn the call back over to Ian.
Ian Dundas
Thanks Ray. Q1 was another quarter of strong consistent execution for our company.
We expected to deliver on our plan throughout 2014 with a focus on capital discipline and a strong execution. Natural gas volumes are performing ahead of expectations driven the strength in the Marcellus.
And our oil program is accelerating after tough weather in January and February. We are maintaining our production guidance; however, we expected to track to the high-end of the range given the strong start to the year.
With the Marcellus outperformance is driving our natural gas weighting higher to 56%. In total we continued to expect, we will deliver about 10% growth in production year-over-year.
Reported capital spending is increasing slightly due to the weakening Canadian dollar and some modest increases in our non-operated spending. If you recall approximately 60% of our capital is allocated to our U.S.
assets and it is denominated in U.S. dollars, as well the weak Canadian dollar is certainly helping our revenue.
We are now forecasting approximately $800 million up from $760 million previously; again, I’m referencing the capital. Operating in cash and general and administrative costs are unchanged from our original guidance.
Cash, equity based compensation expense will increase from $0.25 per BOE to $0.45 per BOE due to the increase in our relative share price. To-date in 2014, our share prices appreciated approximately 25%.
On the people side, I want to take a momentum to discuss Board and executive changes. You may have noticed, we also announced this morning the Doug Martin, our Chairman is planning to retire at the end of 2014 after setting the shareholders benefit for 14 years.
Mr. David O’Brien is also retiring from our Board and will not be standing for reelection.
Doug and David have been instrumental in guiding the company through not only various commodity price cycles, but also our transformation over the past few years. I would like to thank them both for their contributions.
Doug will step down as Chairman on June 1st, and will remain on the Board until the end of the year. Mr.
Elliott Pew who is currently a Board member will replace Doug in the role of Chairman. For those who don’t know Elliott is geologist.
He has extensive experience within the oil and gas industry particularly in the shales. He was EVP in Newfield Exploration, leading the company’s exploration program and was a co-founder of Common Resources.
He currently sits on the Board of Common Resources too. He is a deep technical and commercial background that will serve Enerplus well.
In planning for these changes, we added two new Board member last quarter, Ms. Hillary Foulkes and Mr.
Mike Culbert. Both of these individuals are well-known in industry and each brings more than 30 years’ experience in oil and gas.
With their knowledge and expertise it will continue to strengthen our Board. At the executive level, Lisa Ower is joining us in the role of Vice President, Human Resources.
Lisa also brings a wealth of experience to the table as held similar positions in a number of companies. I welcome our new Board members and Lisa; I look forward to their contributions in helping shape our future.
And finally, we do plan to host a session on June 18th, focusing on our North Dakota operations and the opportunities we see in the Bakken and the Three Forks formations. A webcast will be held from 10 a.m.
to 11:30 Mountain Standard Time and is open to anyone who is interested. We hope it will make for an enlighting 90 minutes and I encourage you to register for it.
Full details will be sent out next week. So with that I turn the call over the operator, and we will open it up for questions.
Operator
[Operator Instructions] Your first question comes from the line of Greg Pardy from RBC Capital Markets. Please go ahead.
Greg Pardy – RBC Capital Markets
Thanks. Good morning.
Just wanted to dig in a little bit into your – just your backlog and maybe just to start with the Bakken, how many wells did you drill in the Bakken in the first quarter, so the 30.5 net?
Ray Daniels
Help me, what we drilled?
Greg Pardy – RBC Capital Markets
Yes. Of the 30.5 net horizontals that you drilled where – how many of those would have been in the Bakken or just – sorry, did the North Dakota?
Ray Daniels
That’s a five net wells which would effectively be five gross wells as well.
Greg Pardy – RBC Capital Markets
Okay. And then Ian, what is your – what is the tie-in so drilling and just tie-in schedule will look like through the second, third and fourth quarters, just – I know you have gotten off to a slower start but assuming you are going to gather momentum as the years goes on?
Ian Dundas
Sure. As you can imagine, there is always moving parts around that.
But, I will turn that over to Ray to give you a little bit of color.
Ray Daniels
Hey, Greg. Thanks for the question.
So we have got seven tie-ins in Q2. Sorry, we have got five tie-ins in Q2.
There were two in July that was counting there. And then in Q3, we have – sorry, we have seven tie-ins in Q2 and we have three – sorry, seven tie-ins in Q4.
Greg Pardy – RBC Capital Markets
Okay.
Ian Dundas
And Greg, as you think about this, I would anticipate reasonable build in the oil volumes as we move into the sort of second quarter sort of flattish and then popping up again as you move through the third sort of stead-ish ton of growth.
Greg Pardy – RBC Capital Markets
Okay. So seven in Q2, nothing in Q3?
Ray Daniels
No plans right now.
Greg Pardy – RBC Capital Markets
No plan. And then seven in Q4, okay.
That’s fine. And these will be – are these – these will be predominantly long reach and then Bakken and first bench in Three Forks?
Ray Daniels
Yes.
Greg Pardy – RBC Capital Markets
Okay. Okay.
That’s fine. And then just on with the Marcellus not typically as you guys, how many wells do you have drilled, net wells that you drilled and completed but not yet tied-in.
Ray Daniels
17.6.
Greg Pardy – RBC Capital Markets
Okay. Good precision, right.
Thanks for that. And then what do you thinking in terms of exit rates in the Marcellus, I mean, I know obviously, its non-op, so you can’t predict the first day.
But, like your numbers are really, really strong, so I’m trying to get a sense as to what you look like going into the next year?
Ian Dundas
It’s a very good question. So the Marcellus, we were producing 170 million a day last December.
And with really limited on-streams in Q1, we have grown it. So you can see the well results are – they continue to impress.
And so depending upon how that unfolds that really can move the numbers in. I would say my expectation is, we are growing.
My expectation is we are growing as you think about leaving the year relative to the Marcellus. That can move around a lot though.
I think or if you step back Greg, we are targeting corporate growth in that 5% to 10% kind of range. And last couple of years, it’s been gravitating to 10% and that outperformance in the Marcellus has been a decent part of that.
So I don’t see how that’s going to – I think that’s going to continue for a while.
Greg Pardy – RBC Capital Markets
Okay. Okay.
Great. Then last question, just with respect to Marcellus egress, you are going to be – so you will be able to – no issues I guess in terms of moving your gas physically recognize that the good chunk of it is uncontracted.
So we are really just looking at ongoing fairly wide basis. But, physically you are still going to be able to move this.
Is that a fair assessment?
Ian Dundas
That’s a fair assessment. Let me turn over to Eric Le Dain to give you – maybe just a little more color on this though.
Eric Le Dain
Greg, its Eric here. We don’t see any issues with the physical moment at this time.
But we do see as you know a price difference between the spot sales and our contracted volumes. But we are obviously watching it all the time with our partners on both the gathering side and link into the interstate pipelines and we haven’t seen any issues at this point.
Greg Pardy – RBC Capital Markets
Okay. Great.
Now thanks for that. And last question is, just on the capital, understand the most of it then was that FX related.
But you are going to hope a line right now like guys has exercised great capital this for the last few years. You are going to hold the line this year, right on that kind of a number, any number?
Ian Dundas
We are not changing our guidance and at this moment we don’t have plans too. I think the key for us is to have a plan that makes sense that we can afford doesn’t rely on equity.
And so we will – I don’t – your numbers will be but depending upon how you think of both the gas price and the oil price, even trade some pretty still cash flows over the course of the year. So we will see how that unfolds.
The gas price stays in, it will be more cash in the system. We have got a lot of opportunities and we want a plan to make sense.
And so at this moment very comfortable with where we are and very comfortable with holding line, things going to obviously move around a little bit based upon non-op. But at this point, I’m really comfortable with program we have.
And I think it’s going to give us pretty attractive growth.
Greg Pardy – RBC Capital Markets
Okay. Great.
Thanks very much all.
Ian Dundas
Thank you.
Operator
Your next question comes from the line of Aaron Bilkoski from TD Securities. Please go ahead.
Aaron Bilkoski – TD Securities
Hi, guys. Good morning.
I just have a few questions. I will start with the general one.
How much production Q1 be estimated certainly due to weather?
Ian Dundas
Probably several thousands. We would have days where there was more than 1000, 2 to 3 gas and oil, on some instances there were third party outages and trucking issues.
Then you have a little bit of delay issue on top of that as well.
Aaron Bilkoski – TD Securities
Okay. If I moved on to the Marcellus, Greg, touched on this.
But, do you guys have a revised full year average in Marcellus target like 120 to 140 seems pretty unrealistic, now, if you are going to talk about your year-over-year growth?
Ian Dundas
We said 180.
Aaron Bilkoski – TD Securities
Okay. And then on a gross basis in the Marcellus, how many low digit Susquehanna and Bradford, I’m just getting to how many wells comprised that average that you posted?
Ian Dundas
That was seven wells, seven gross wells.
Jodi Labrie
Gross wells, right. So we had 2.3 net wells that were tied-in in the Marcellus and I tell you that 2.2 of them were Bradford and Susquehanna.
Aaron Bilkoski – TD Securities
Okay. And on the pricing side on the Marcellus, what price discount to NYMEX you are receiving on the volumes that are being shipped under long-term contract?
Ian Dundas
In what time period?
Aaron Bilkoski – TD Securities
Q1, I think it was $0.88 back on average but I’m just trying to get a split between the discount between what were shipped on contract and what were shipped not on contract?
Eric Le Dain
Probably Q1 was a bit unusual because of the volatility as you know and the market points were so significant. But in general the marketed contracted is coming in at about half the basis differential of the uncontracted or call it spot sales.
And we are seeing that in for example April you will – with all of the market data out there now, Dominion south and other contracted market points is roughly got same relationship half of the spot.
Aaron Bilkoski – TD Securities
Sure. Would you guys have the opportunity to lock-in more long-term takeaway contracts and what price would you be looking at, given that would be sort of $0.40 back?
Ian Dundas
We are always looking at our contracting strategy there including long-term takeaway which can have quite long terms of tenures and so on. But it really depends where you contracting out of this point depends on the full tolls, if it’s a transport physical related delay on the financial side.
We can still contract out a few years on the Dominion south type points. But it’s not a very liquid market for past year on the spot sale points of Marcellus.
Marcellus own four or Leidy. And we just don’t – we are not interested at this point in contracting financially to fix the basis because the market as you know is quite negative about basis in this area.
And the reality in the day market is a bit different and is more a representative of what we see in terms of the supply/demand picture. So we just don’t see any real value in term financial contract.
But, on the physical side, we are always looking to that. And we are always talking to our customers in the area and looking at arrangements that might move out more than one year or part of the year.
Aaron Bilkoski – TD Securities
Okay. Perfect thanks.
Two more questions, these are both in North Dakota. Am I correct to assume that there is no second bench Three Forks locations booked in the 2P or 2C reports?
Ian Dundas
You are right.
Aaron Bilkoski – TD Securities
And the final question is, I realized it’s kind of really I’m asking you to speculate, about what proposition of your North Dakota acreage, do you think is prospective for second bench orders of magnitude 10%, 20%, 30%?
Ian Dundas
I might have written the TD note slightly different this morning.
Aaron Bilkoski – TD Securities
Okay.
Ian Dundas
So we are quite confident it does not extend in a commercial way to the southern portion of the acreage. And we have proven, we have it right at the Northern portions of the acreage.
And so it’s difficult to know where that transitions. If you look on a map, you can draw a line that it sort of takes about a quarter of our acreage there is a possibility you could see a quarter of the acreage, but we don’t know yet.
There is some more data coming to us from third-party actually non-operated that were participating in – that we would anticipate gives us some data, we are drilling right now actually. So this is encouraging, and it’s difficult to say exactly how meaningful it is.
Aaron Bilkoski – TD Securities
Okay. Fair enough.
That’s it for me. Thank you, guys.
Ian Dundas
Thanks Aaron.
Operator
[Operator Instructions] Your next question comes from the line of Kyle Preston from National Bank. Please go ahead.
Kyle Preston – National Bank
Thanks. Good morning, guys.
Just one general question here somewhat related to the last question Aaron asked. But more relating to your down spacing initiatives in the Bakken and North Dakota there with the high density well pads you have done to-date and the success you have had there?
You give an indication on how more confidence you have in those 150 potential down spacing locations you have identified in the past?
Ian Dundas
We have an extreme – sorry, let’s just make sure we are on the same page. If you look at our 2P report and our contingent resource estimates that has just under 150 locations in it.
That seven year inventory at the current pace of development. We have an extremely high degree of confidence in those locations and we believe with high view of confidence they are going up.
The number of locations is going up. And we will get people some flare and hopefully some quantification of that as we talked to people in June with maps and details and the likes.
Kyle Preston – National Bank
Okay. And if and when would you look at accelerating that program just given the success you are seeing?
Ian Dundas
I think acceleration, if it happens is probably 2015 kind of thing, right now we are running two rigs actually at this red hot minute, we are running three because we are transitioning out of one into another. We are able to get all the information we want with the pace of this program.
It provides a financial picture that makes sense to us, its affordable those sorts of things as we are able to sort of talk about a broader inventory and quantify the scope of that and that lends now a conversation about how much inventory do you have, should we accelerating at with the – obviously with the added benefit of present value acceleration, does that financial plan makes sense, what are the other alternatives we have as well. We have got a lot of interesting things going on in the company but I think it – from a timing perspective it’s really a 2015 budget kind of conversation.
Kyle Preston – National Bank
Okay. Sounds good.
Thanks a lot guys.
Ian Dundas
Thanks Kyle.
Operator
And we have no further questions in the queue. I will turn the call back over to the presenters.
Ian Dundas
Well, thank you, everyone, appreciate you calling in this morning. And hope everyone has a great day and a good weekend.
Thank you very much.
Operator
This concludes today’s conference call. You may now disconnect.