final transcript

Transcription

final transcript

FINAL TRANSCRIPT
Enerplus Corporation
First Quarter Results
Event Date/Time: May 9, 2014 — 10:30 a.m. E.T.
Length: 31 minutes
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Enerplus Corporation First Quarter Results
CORPORATE PARTICIPANTS
Jo-Anne Caza
Enerplus Corporation — Vice-President, Corporate Relations
Ian Dundas
Enerplus Corporation — President and Chief Executive Officer
Ray Daniels
Enerplus Corporation — Senior-Vice President, Operations
Eric Le Dain
Enerplus Corporation — Senior Vice-President, Corporate Development, Commercial
CONFERENCE CALL PARTICIPANTS
Greg Pardy
RBC Capital Markets — Analyst
Aaron Bilkoski
TD Securities — Analyst
Kyle Preston
National Bank — Analyst
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PRESENTATION
Operator
Good morning, ladies and gentlemen. My name is Aaron (phon), and I'll be your Operator
today. At this time, I'd 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
our speakers' remarks, we will have a question-and-answer session. If you'd like to ask a question at
that time, please press *, then the number 1 on your telephone keypad. And if you wish to
withdraw your question, simply press the # key.
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 — Vice-President, Corporate Relations, Enerplus Corporation
Thank you very much, Aaron. 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 and 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.
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I'd like to point out that our financials have been prepared in accordance with United
States generally accepted accounting principles. We made this change at year-end, as more than 50
percent of our shares and more than 50 percent of the book value of our assets under International
Financial Reporting Standards were held in the US.
All discussion of production volumes today is on a 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.
The information we're 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'll open the phone lines and answer questions you may have,
and we'll also have a replay of this call available later today on our website.
So with that, I'll now turn the call over to Ian.
Ian Dundas — President and Chief Executive Officer, Enerplus Corporation
Good morning, everyone, and thanks for dialling in this morning. We delivered another
strong quarter of production and cash flow growth for investors in Q1.
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Production was ahead of our expectations at 98,821 BOE a day, and represented a 5
percent increase over average volumes in the fourth quarter of 2013. The increase was due to
record production in the Marcellus, which averaged nearly 180 million cubic feet of gas a day, and
drove the production mix in the quarter to 58 percent natural gas.
We experienced some production interruptions and delays in our capital spending due to
extreme winter weather conditions in both Canada and in the US. Despite these challenges, our
crude oil volumes were maintained quarter over quarter.
Capital spending of $218 million was slightly less than planned, but particularly in our US
oil assets. Although our drilling program was relatively active, we only completed 11 net wells in the
quarter, two at Fort Berthold.
We continue to see strong well performance, particularly from the Fort Berthold region
and in the Marcellus. Well results year to date are some of the best we've seen out of each of these
plays.
We've continued with our high-density tests, and also have some very encouraging
production results on our first lower Three Forks tests that Ray will give you some additional colour
on.
Despite 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 the
exchange rate, given that 60 percent of our program is spent in the US.
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We continued to see strong capital performance, and expect it to sustain the capital
efficiency improvement of last year of less than $30,000 per on-stream flowing barrel.
We benefitted from the increase in both AECO and NYMEX natural gas prices. Our realized
natural gas price was over 50 percent higher than in the fourth quarter. We also saw a significant
narrowing of crude oil differentials in both Canada and the US. These changes drove a 35 percent
improvement in our corporate netback before hedging compared to last quarter.
With the growth in production volumes and the increase in commodity prices, funds flow
was up 22 percent 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 percent on average in the first quarter to 10
percent in April.
Our previously announced noncore asset sales closed in the quarter, generating proceeds
of $117 million, which included proceeds from the sale of our core interests in the Jonah field and
the final payment relating to the sale of our Montney assets.
These proceeds, along with the increase in funds flow, resulted in a further strengthening
of our balance sheet. We ended the quarter with a debt to trailing 12-month funds flow ratio of 1.3
times, with over 80 percent of this term debt, and only a small amount drawn on our bank line.
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So with that, I'll turn it over to Ray to talk more about our operational results for the
quarter.
Ray Daniels — Senior-Vice President, Operations, Enerplus Corporation
Thanks, Ian. The cold weather Ian mentioned did cause some production downtime and
some capital program delays in both Canada and the US.
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 the plan and in part due to weather-related delays.
In North Dakota, we continued to run two rigs, and were able to maintain production
volumes quarter over quarter despite the weather interruptions. We continued to be encouraged
by our North Dakota well performance.
We commenced our first high-density spacing test by bringing on three wells of a sevenwell pattern at our Fur Bearers Pad. There were two Bakken wells spaced at approximately 1,400
feet that came on-stream in late December and a third well that came on-stream in January, runs
equidistant between these wells, but is 60 feet deeper in the Three Forks first bench.
In the first 90 days on 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 continued to see.
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The Three Forks well produced 31,000 barrels in the first 30 days at an average of over
1,000 barrels a day. We have just completed an interference test of these three wells and the
results are currently being analyzed, but as you might imagine, we are very encouraged with the
performance we have seen to date.
The other well brought on-stream in Q1 was a short Bakken well. This well produced
32,000 barrels of oil in the first 30 days at an average of almost 1,100 barrels a day, our best short
well to date and was our best well per lateral foot.
I say was because in early April, we brought on two long horizontal wells from the Snakes
Pad located on our northernmost acreage up near the Antelope extension that are now our best
wells to date. We knew this was a good area, and one of the objectives from drilling these wells was
to test the lower bench of the 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 2,500 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 (sic) [2,300] barrels a day.
These cumulative production rates make them the top-performing wells we have drilled
from an IP30 perspective and also are some of the best wells ever drilled in North Dakota.
We are excited about these results. We know this area is very productive based not only
on our own well results, but also the results from other producers in the area. However, we know
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the lower benches of the Three Forks are not productive across their 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 increased intensity of our
fracs, which is delivering higher production rates. We're 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're seeing in North Dakota, frac optimization is driving improved well
performance. The amount of sand per foot has increased from 1,500 pounds to between 2,500 and
4,000 pounds, and the number of frac stages has doubled.
On-streams 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 their first
30 days.
Our Marcellus production now accounts for over 50 percent of our corporate gas volumes.
Our realized price increased to US $4.06 per Mcf in the quarter, and our netback was CDN $2.86 per
Mcf. With the increase in NYMEX pricing and production volumes, the Marcellus generated about
$46 million of net operating income in the first quarter, resulting in approximately $15 million of
cash flow in excess of our capital spending.
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We continue to see the effects of supply growth in the region. We have long-term
contracts and a transportation to market points on approximately 80 million cubic feet a day, which
is helping to mitigate our exposure to these widening differentials. However, roughly 55 percent of
our volumes are not contracted.
We saw 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 our waterflood portfolio during the
quarter, with activity at our Medicine Hat Glauc C and Pouce Coupe/Boundary Lake properties in
Alberta and in Southeast Saskatchewan where we targeted the Midale 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 is a
commercial success. We're preparing for our second polymer injection project, which we expect to
implement in 2015.
In our Canadian deep gas assets, we continued to advance our program in the Wilrich, and
we've 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 around our type
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curve, and we will complete the fourth well after breakup. We're letting the Duvernay wells soak a
few months, and expect to bring them on-stream in Q2 and Q3. We'll 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
full year plans before any currency adjustments, and we are well positioned to deliver
approximately 10 percent 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
expect to deliver on our plans throughout 2014 with a focus on capital discipline and strong
execution.
Natural gas volumes are performing ahead of expectations, driven by 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 expect it to track to the high end of the range,
given the strong start to the year. With the Marcellus outperformance, it's driving our natural gas
weighting higher to 56 percent.
In total, we continue to expect we will deliver about 10 percent growth in production year
over year. Reported capital spending is increasing slightly due to the weakening Canadian dollar and
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some modest increases in our non-operated spending. If you recall, approximately 60 percent of our
capital is allocated to our US assets, and it's denominated in US 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 cash and general 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 price has
appreciated approximately 25 percent.
On the people side, I want to take a moment to discuss Board and executive changes. You
may have noticed we also announced this morning that Doug Martin, our Chairman, is planning to
retire at the end of 2014 after serving the shareholders of Enerplus for 14 years. Mr. David O'Brien is
also retiring from our Board and will not be standing for re-election.
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
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 a geologist. He has extensive experience within the
oil and gas industry, particularly in the shales. He was EVP at Newfield Exploration, leading the
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company's exploration program, and was a co-founder of Common Resources. He currently sits on
the board of Common Resources II. He has a deep technical and commercial background that will
serve Enerplus well.
In planning for these changes we added two new Board members last quarter: Ms. Hillary
Foulkes and Mr. Mike Culbert. Both of these individuals are well known in industry, and they each
bring 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 of Human
Resources. Lisa also brings a wealth of experience to the table and has held similar positions in a
number of companies.
I welcome our new Board members and Lisa, and look forward to their contributions in
helping shape our future.
On a final note, 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 10:00 a.m. to 11:30 a.m. Mountain Standard Time, and is open to anyone who is
interested. We hope it will make for an enlightening 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 to the Operator, and we will open it up for questions.
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Q&A
Operator
Certainly. At this time, if you'd like to ask a question please press *, then the number 1 on
your telephone keypad.
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.
Ian Dundas
How many wells did we drill?
Greg Pardy
Yeah. In the—of the 30.5 net horizontals that you drilled, how many of those would have
been in the Bakken? Or sorry, just in North Dakota?
Ian Dundas
That's five net wells, which would effectively be five gross wells as well.
Greg Pardy
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Okay. And then, Ian, what does the tie-in—so drilling and just tie-in schedule look like
through the second, third, and fourth quarters? I'm just trying—I know you've gotten off to a slower
start, but assuming you're going to gather momentum as the year goes on.
Ian Dundas
Sure. As you can imagine, there's always moving parts around that, but I'll turn that over
to Ray to give you a little bit of colour.
Ray Daniels
Yeah. Greg, thanks for the question. So we have got seven tie-ins in Q2.
Greg Pardy
Yeah.
Ray Daniels
We have got five tie-ins in Q2; there was two in July that I was counting there. And then in
Q3 we have—sorry, we have seven tie-ins in Q2 and we have seven tie-ins in Q4.
Greg Pardy
Okay.
Ian Dundas
I think—Greg, as you think about this, I'd anticipate a reasonable build in 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, so steady-ish kind of growth.
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Greg Pardy
Okay. So seven in Q2; nothing in Q3?
Ray Daniels
Not as planned right now.
Greg Pardy
Not as planned. Okay. And then seven in Q4. Okay. That's fine. And then these will be
predominantly long-reach, and then Bakken and first bench at the Three Forks?
Ray Daniels
Yeah.
Greg Pardy
Okay. Okay. That's fine. And then just with the Marcellus now. I typically ask you guys, how
many wells do you have drilled—net wells that you’ve drilled—completed but not yet tied in?
Ray Daniels
Thirteen-point-six.
Greg Pardy
Okay. Good precision rate. Thanks for that. And then what are you thinking in terms of exit
rates in the Marcellus? I mean I know obviously it's non-op so you can't predict per se, but like your
numbers are really, really strong, so I'm trying to get a sense as to what do you look like going into
next year?
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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've grown it. So you can see the well results
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're growing. My expectation is we're growing as you think about leaving the
year relative to the Marcellus. That can move around a lot, though.
Or if you step back, Greg, we're targeting corporate growth in that 5 to 10 percent kind of
range. And the last couple years it's been gravitating to 10 percent, 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
Okay. Okay. Great. And then last question is just with respect to Marcellus egress. You're
going to be—so you'll be able to—no issues, I guess, in terms of moving your gas physically;
recognize that a good chunk of it is uncontracted, so we're really just looking at an ongoing fairly
wide basis, but physically you're still going to be able to move it. Is that a fair assessment?
Ian Dundas
That's a fair assessment. But let me turn it over to Eric Le Dain to give you maybe just a
little bit more colour on this, though.
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Eric Le Dain — Senior Vice-President, Corporate Development, Commercial, Enerplus Corporation
Yeah. Greg, it's Eric here. We don't see any issues with the physical movement at this time,
but we do see, as you know, a price difference between the spot sales and our contracted volumes.
But we're obviously watching it all the time with our partners on both the gathering side and linked
in to the interstate pipelines, and we haven't seen any issues at this point.
Greg Pardy
Okay. Great. No, thanks for that. And the last question is just on the capital. I understand
that most of it then was FX-related, but you're going to hold the line, right? Like you guys have
exercised great capital discipline in the last few years; you're going to hold the line this year, right,
on that kind of a number? On the…
Ian Dundas
We're not changing our guidance, and at this moment we don't have plans to.
Greg Pardy
Okay.
Ian Dundas
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'll—I don't know what your numbers will be, but depending upon how you think
about the gas price and the oil price, you can create some pretty stout cash flows over the course of
the year. So we'll see how that unfolds.
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If the gas price stays in there'll be more cash in the system. We've got a lot of
opportunities, and we want a plan that makes sense, and so at this moment I'm very comfortable
with where we are and very comfortable holding the line. Things can obviously move around a little
bit based upon non-op, but at this point I'm really comfortable with the program we have, and I
think it's going to give us pretty attractive growth.
Greg Pardy
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'll start with a general one; how much
production in Q1 do you estimate was shut in due to weather?
Ian Dundas
Probably several thousand. I mean we would have had days where there was more than
8,000, 2,000 to 3,000 gas and oil on some instances through third party outages and trucking issues.
Then you had a little bit of a delay issue on top of that as well.
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Aaron Bilkoski
Okay. And if I moved on to the Marcellus, Greg touched on this, but do you guys have a
revised full year average Marcellus target? Like 120 to 140 seems pretty unrealistic now if you're
going to talk about year-over-year growth.
Ian Dundas
We’ve said 180.
Aaron Bilkoski
And on a gross basis in the Marcellus, how many wells did you tie in in 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.
Jo-Anne Caza
Gross wells, right. So we had 2.3 net wells that were tied in in the Marcellus, and I'd tell
you that 2.2 of them were in Bradford-Susquehanna.
Aaron Bilkoski
Okay. And on the pricing side in the Marcellus, what price discount to NYMEX are you
receiving on the volumes that aren’t being shipped under a long-term contract?
Ian Dundas
In what time period?
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Aaron Bilkoski
Q1. Like it was $0.88 back on average, but I'm just trying to get a split between the
discount between what was shipped on contract and what was shipped not on contract.
Eric Le Dain
Yeah. Probably Q1 was a bit unusual because the volatility, as you know, at the market
points was 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're seeing that in, for example, April, all
the market data's out there now; Dominion South and other contracted market points is roughly
that same relationship, half of the spot.
Aaron Bilkoski
Sure. Would you guys have the opportunity to lock in more long-term takeaway contracts?
And what price would you be looking at doing that at? Would it be still sort of $0.40 back?
Eric Le Dain
We're always looking at our contracting strategy there, including long-term takeaway,
which can have quite long terms of 10 years and so on. But it really depends—where you’re
contracting out at this point depends on the full tolls, if it's a transport physical-related deal.
On the financial side we can still contract out at a few years on the Dominion South-type
points, but it's not a very liquid market for past a year on the spot sale points of Marcellus Zone 4 or
lighty.
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And we just don't—we're 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 representative of what see in terms of the
supply/demand picture. So we just don't see any real value in term financial contracting.
But on the physical side we're always looking at that, and we're always talking to our
customers in the area and looking at arrangements that might move out more than one year or part
of a year.
Aaron Bilkoski
Okay. Perfect. Thanks. Two more questions; these are both in North Dakota. Am I correct
to assume that there's no second bench Three Forks locations booked in the 2P or the 2C reports?
Ian Dundas
You are.
Aaron Bilkoski
And the final question is, I realize it's kind of early and I'm asking you to speculate, but
what proportion of your North Dakota acreage do you think is prospective for second bench? Just
orders of magnitude, 10 percent, 20 percent, 30 percent?
Ian Dundas
I might have written the TD note slightly different this morning.
Aaron Bilkoski
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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 sort of takes about a quarter of our acreage.
There's a possibility you could see a quarter of the acreage, but we don't know yet. There is some
more data coming to us, some third party actually non-operated that we're participating in that we
would anticipate gives us some data; we're drilling right now actually. So this is encouraging, and it's
difficult to say exactly how meaningful it is.
Aaron Bilkoski
Okay. Fair enough. That's it for me. Thank you, guys.
Ian Dundas
Thanks, Aaron.
Operator
Again, if you'd like to ask a question please press *, then the number 1 on your telephone
keypad.
Your next question comes from the line of Kyle Preston from National Bank. Please go
ahead.
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Kyle Preston — National Bank
Yeah. Thanks. Good morning, guys. Just one general question here somewhat related to
the last question Aaron asked, but more relating to your downspacing initiatives in the Bakken and
North Dakota there with the high-density well pads you’ve done to date and the success you’ve had
there. Can you give an indication on how much more confidence you have in those 150 potential
downspacing locations you've identified in the past?
Ian Dundas
We have an extreme—sorry, so let's just make sure we're 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's
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 a high degree of confidence they are going up.
The number of locations is going up. And we’ll give people some flavour and hopefully
some quantification of that as we talk to people in June with maps and details and the like.
Kyle Preston
Okay. And if and when would you look at accelerating that program, just given the success
you’ve seen?
Ian Dundas
I think acceleration, if it happens, is probably a 2015 kind of thing. Right now we’re running
two rigs. Actually, at this red-hot minute we’re running three because we’re transitioning out of one
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May 9, 2014 — 10:30 a.m. E.T.
into another. We’re able to get all the information we want with the pace of this program. It
provides a financial picture that makes sense to us; it’s affordable, those sorts of things.
Yeah. As we are able to sort of talk about a broader inventory and quantify the scope of
that, I think that then sort of lends you into a conversation about how much inventory do you have?
Should you be accelerating that obviously with the added benefit of present value acceleration?
Does that financial plan make sense? What are the other alternatives we have as well?
We’ve got a lot of interesting things going on in the Company, but I think from a timing
perspective it’s really a 2015 budget kind of conversation.
Kyle Preston
Okay. Sounds good. Thanks a lot, guys.
Ian Dundas
Thanks, Kyle.
Operator
And we have no further questions in the queue. I’ll 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
25
FINAL TRANSCRIPT
May 9, 2014 — 10:30 a.m. E.T.
This concludes today’s conference call. You may now disconnect.
*****
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