SWN Q3 2010 Earnings Conference Call
[SWN] - Southwestern Energy
Company
Q3 2010 Earnings Conference Call
Friday, October 29, 2010
Officers
Steve Mueller; Southwestern Energy;
President and CEO
Greg Kerley; Southwestern Energy;
CFO
Brad Sylvester; Southwestern Energy;
VP, Investor Relations
Analysts
Scott Hanold; Royal Bank of Canada;
Analyst
Scott Wilmoth; Simmons & Company
International; Analyst
Amir Arif; Stifel Nicolaus;
Analyst
Brian Singer; Goldman Sachs;
Analyst
Rehan Rashid; FBR Capital Markets;
Analyst
Gil Yang; Bank of America Merrill
Lynch; Analyst
Thomas McNamara; Impala Asset
Management; Analyst
David Heikkinen; Tudor, Pickering, Holt
& Co.; Analyst
Nicholas Pope; Dahlman Rose & Co.;
Analyst
Dan McSpirit; BMO Capital Markets;
Analyst
Robert Christensen; Buckingham Research
Group; Analyst
Jack Aydin; KeyBanc; Analyst
Presentation
Operator:
Greetings, and welcome to the Southwestern Energy's Third Quarter Earnings
teleconference call.
At this time, all participants are in a
listen-only mode. A brief question-and-answer session will follow the
formal presentation. If anyone should require operator assistance during
the conference, please press star zero on your telephone keypad.
As a reminder, this conference is being
recorded.
It is now my pleasure to introduce your host,
Steve Mueller, President and Chief Executive Officer. Thank you, Mr.
Mueller. You may begin.
Steve Mueller:
Thank you, and good morning. Thank you for all of you joining us.
With me today are Greg Kerley, our CFO, and Brad Sylvester, our VP of
Investor Relations.
If you've not received a copy of yesterday's
press release regarding our third quarter results, you can call 281-618-4847 to
have a copy faxed to you.
Also, I'd like to point out that many of the
comments during this teleconference are forward-looking statements. They
involve risks and uncertainties affecting outcomes, many of which are beyond our
control, and are discussed in more detail in the Risk Factors and the
Forward-Looking Statements sections of our annual and quarterly filings with the
Securities and Exchange Commission.
Although we believe the expectations expressed are based on
reasonable assumptions, they are not guarantees of future performance, and
actual results or developments may vary -- may differ
materially.
Let me begin.
We had an excellent third quarter.
Despite lower gas prices, our earnings and cash flow were up significantly
compared to last year. This increase was primarily driven by our
production growth of 44% compared to last year and 7% sequentially.
We are also driving down well costs while
beginning to better understand the well spacing for the Fayetteville Shale play.
I'll speak more about these points in a few moments.
Now, to talk about each of our operating
areas.
During the third quarter, our gross operated
productions on the Fayetteville Shale reached over 1.5 Bcf per day, up from
approximately 1.2 Bcf per day a year ago and also surpassing the net production
mark of 1 Bcf per day.
During the third quarter of 2010, our
horizontal wells had an average completed well cost of $2.8 million per well.
That cost matches the lowest quarter we've ever had since beginning
drilling horizontally.
The average horizontal length was 4,503 feet,
almost 500 feet longer than the last time we had 2.8 million a day -- $2.8
million per well cost. And the average days to drill from reentry to
reentry was 11 days.
We continue to see faster drilling times, and
in the third quarter, we had eight wells placed on production which had average
times to drill to total depth of five days or less from reentry to reentry.
Our horizontal rig count stands at 13 rigs
compared to the 15 rigs we averaged during the first nine months of
2010.
The 145 Fayetteville wells placed on
production during the third quarter of 2010 averaged initial production rates of
nearly 3.3 million cubic foot per day, down 5% compared to the second quarter.
Results for the quarter include 58 wells, or 40%, placed on production,
which were the first wells in a new section, and 36 wells, or 25%, drilled to
test tighter well spacing.
We also set a new record during this quarter
by placing the play's highest-rated well, the Harlan 9-10 #1-12H, located in
Cleburne County, on production with an initial production rate of approximately
8.7 million cubic foot per day. This well had a completed lateral length
of 3,874 feet and a nine-stage fracture stimulation. After 34 days, it's
still producing 5.7 million cubic feet per day.
We continued to test tighter spacing and at
September 30, 2010 have placed over 520 wells on production that have well
spacing of 700 feet or less, representing approximately 65-acre spacing or
less.
Previously, we have stated that based on the
wells drilled to date, we'd expected a minimum of 10 to 12 wells per section to
effectively drain the reserves, which represent the 65-acre spacing.
However, early production performance from
recent well spacing test indicates there are areas of the field that may be
economically developed at tighter spacing.
At
this time, we have confirmed that approximately 20% of the roughly 600,000 net
acres drilled to date can be drilled at 30 to 40-acre spacing; approximately 40%
can be developed at 65-acre spacing, and the remaining 40% requires additional
results to determine if development on tighter spacing than 65 acres is
warranted.
We will continue with our well spacing
program to better define the areas of field that are suitable for tighter
spacing and expect to know more about the well spacing on the remainder of our
acreage in 2011.
Switching to East Texas, production from our
East Texas properties was 26.9 Bcf during the first nine months of 2010,
compared to 24.6 Bcf during the same period last year.
Approximately 2.1 Bcf of our 2010 production
was related to the Haynesville and Middle Bossier properties, which were sold in
June. We still have approximately 10,500 net acres with Haynesville and
Middle Bossier Shale potential and have drilled three wells on this acreage to
date. The Timberstar Blackstone A-1H, targeting the Haynesville Shale
formation, was placed on production in August at an initial production rate of
13.2 million cubic feet per day.
The other two wells, which are targeting the
Middle Bossier, will be completed in the first quarter of 2011.
In our Conventional Arkoma program,
production was 14.8 Bcf for the first nine months of 2010 compared to 16.9 Bcf
for the first nine months of 2009.
In Pennsylvania, we have drilled nine
horizontal wells, three of which are currently being completed, and we expect
results from those wells sometime next month. Approximately 15 wells are
expected to be drilled by year-end, seven of which are expected to be completed
by year-end.
You may remember that in July we placed our
first well in Pennsylvania on production, the Greenzweig #1-H, and at our second
quarter earnings release date, it was producing approximately 3.3 million cubic
feet per day without compression into a pipeline with just over 3,000 pounds of
flowing tubing pressure.
Since that time, we've cleaned out the well
bore, and post-cleanout, the well reached a peak rate of over 5 million cubic
feet per day in September and is currently producing 2.8 million cubic feet per
day with approximately 1,900 pounds of flowing tubing pressure.
The Greenzweig had 2,945 feet of completed
lateral and was fracture stimulated with slickwater in seven stages, so this is
very encouraging. The wells that are currently completing will have
average lateral lengths of approximately 4,500 feet and have several more frac
stages.
I will now turn it over to Greg Kerley, our
Chief Financial Officer, who will discuss our financial results.
Greg Kerley:
Thank you, Steve, and good morning.
As Steve noted earlier, our results for the
third quarter were excellent. Earnings for the quarter were up 36% to $161
million, or $0.46 a share, compared to $118 million, or $0.34 a share, for the
same period last year.
We also reported discretionary cash flow of
over $421 million, which was up 27% from last year and set a new record for the
company.
Operating income for our E&P segment was $217 million for the
third quarter, up from $172 million for the same period in 2009, as our strong
production growth more than offset the impact of lower realized gas prices and
increased operating costs and expenses.
Our average realized gas price fell 8% to
$4.67 per Mcf in the third quarter compared to $5.06 for the same period last
year.
We currently have approximately 44 Bcf of our
fourth quarter projected natural gas production hedged through fixed price swaps
and collars at a weighted average floor price of $6.26 in Mcf. This
represents approximately 40% of our expected production during the
quarter.
Our lease operating expenses per unit of
production were $0.85 per Mcfe during the quarter compared to $0.76 last year.
The increase was primarily due to higher gathering and compression costs
related to our Fayetteville Shale play.
Our general and administrative expenses per
unit of production declined to $0.28 per Mcfe in the third quarter, down from
$0.38 last year due to the impact of our increased production volumes, while our
taxes other than income taxes were $0.12 per Mcfe in the quarter compared to
$0.10 in the prior year.
Our full cost pool amortization rate
continues to decline, dropping to $1.31 per Mcf in the third quarter from $1.43
in the prior year, primarily due to our lower finding and development costs,
combined with the sale of certain East Texas oil and gas leases and wells in the
second quarter of 2010.
Our total per-unit operating costs and
expenses, including our LOE, G&A, taxes, and full cost pool amortization,
was $2.56 per Mcfe in the third quarter, down from $2.67 in the prior-year
period.
Operating income for our Midstream Services
segment more than doubled in the third quarter to $53 million compared to $25
million a year ago. The increase was primarily due to increased gathering
revenues, which were partially offset by increased operating costs and
expenses.
We currently forecast operating income for
this segment of approximately $180 million for the year and EBITDA of
approximately $210 million.
At October 25, our Midstream Services segment
was gathering over 1.7 billion cubic feet of natural gas a day through over
1,500 miles of gathering lines in the Fayetteville Shale play. This
compared to approximately 1.3 billion cubic feet a day a year ago, and included
in our gathered volumes is approximately 190 million cubic feet per day of
third-party gas.
To update you on the construction of the
Fayetteville Express Pipeline, we are very happy to report that interim service
began earlier this month and primary service will commence on or about December
1. Our initial firm capacity on the pipeline will be about 400 million
cubic feet per day on December 1, 2010, increasing to 1.2 Bcf per day by
November of 2011.
We invested approximately $1.5 billion in the
first nine months of 2010 compared to $1.4 billion in the same period last year
and expect our capital investments for the year to be at or below our original
capital budget of $2.1 billion.
At September 30, we had $617 million borrowed
on our $1 billion credit facility at an interest rate of less than 1% and had
total debt outstanding of $1.3 billion.
At
the end of the third quarter, our debt to book capital ratio was 31%; however,
we expect that to decline to about 28% by year-end.
In summary, we had a great quarter, and in
fact, we had one of the best quarters in the company's history. We're
uniquely positioned to weather the current low gas price environment as one of
the lowest-cost operators in our industry with one of the strongest balance
sheets.
That concludes my comments, so now we'll turn
it back to the Operator, who will explain the procedure for asking
questions.
Questions and
Answers
Operator: Thank
you. We'll now be conducting a question-and-answer session.
(Operator instructions)
Our first question is coming from the line of
Scott Hanold with Royal Bank of Canada. Please proceed with your
question.
Scott Hanold:
Yes, thanks. Good morning.
Unidentified Company
Representative: Good morning.
Unidentified Company
Representative: Morning.
Scott Hanold:
Steve or Greg, could you talk a little bit about the reduction in the rig
count in the Fayetteville from 16 horizontal to 13? Are you all seeing
more efficiency where you could do that and not really need to change your CapEx
or production guidance materially? And what are your thoughts going into
2011?
Steve Mueller:
Well, certainly, reducing the rigs to the 13, we haven't changed our
guidance for this year, so we think we can hit all of our numbers with the lower
rig count for this year.
And then as you look at 2011, we haven't put
a budget together yet, but we can see that it's going to be tough on the pricing
side so dropping the rigs now is starting to prepare us for 2011. I don't
know that I'd count that as being the right number of rigs that we'll run next
year, but it's not going to be certainly in the 15, 16 range; it'll be 13 or
less.
Scott Hanold:
Okay, so you could actually pull off some more rigs into next year and
that wouldn't really -- and that doesn't concern you as far as HBP-ing
that?
Steve Mueller:
No, from an HBP standpoint, this year, 2010, we're doing about 230 wells.
Next year, that drops significantly. It's in the 130 to 150 well
range on the high side, and that drops to around 100, a little less than 100 the
year after that, and we've pretty much got it all held.
Scott Hanold:
Okay, great. And then as a follow-up, on the Harlan well -- I think
it was the Harlan well, right?
Steve Mueller:
Right.
Scott Hanold:
Was there sort of a new cocktail there, or is it just in a good part of
the play?
Steve Mueller:
It wasn't a new cocktail, and we'll figure out if it's a new part of the
play. It was actually one of the wells that was the first well on a
section and is in one of the kind of newer areas.
For those who kind of know our acreage, as
you go off, we've been drilling in the far east. We've been drilling kind
of in the middle part of the map, and this is about halfway in between the far
east and the middle, where we've just been drilling new wells. So don't
know yet whether it's a good or better part of the play, but we're certainly
excited about having it.
Scott Hanold:
Yes, I mean the depth was sort of an average depth well there, is that
correct?
Greg Kerley:
Yes.
Steve Mueller:
Yes, it was. It was on -- as you think about that, the hole we need
to fill on in the eastern side of our play, it's on the southern end of that
hole.
Scott Hanold:
Right. Okay, great. Thanks, guys.
Operator: Your next
question is from the line of Scott Wilmoth with Simmons & Company
International.
Scott Wilmoth: Hey
Steve, just following up with your comment about the 130 to 150 wells needed,
the HPP acreage next year and I'm just trying to tie that to the 10-K. It kind
of says you guys have maybe 34,000-35,000 acres expiring in 2011. If I just
divide that by 640 or so that implies about 50 wells. Where am I off on that?
Steve Mueller: Well,
we're not going to just do the ones that are in 2011; we'll get ahead on the
other ones. For instance right now we've got rigs in that eastern part of the
play kind of filling in that hole; we really don't care if it's 11, 12 or 13, it
makes sense to catch as many as you can in that area while you're there.
Scott Wilmoth: Okay,
so that 130 to 150 is not for only 2011 expiring--?
Steve Mueller: No.
Like I say, by the time we get to somewhere around mid 2012, we'll have all the
acreage captured with the exception -- and we talked about this in the past,
156,000 acres of federal, we need to drill 11 wells between now and the end of
2011 basically to hold that acreage and we've already drilled a couple of them
this quarter, you'll see us drill about five total this year. And that kind of
keeps that 156,000 acres under a different track but it holds all of that.
Scott Wilmoth: Okay
and the when I think about 2011 activity can you kind of give us an allocation
in terms of we already knew 130-150 will be going towards holding acreage;
how much will be testing downspacing and how much will be kind of interior
development mode?
Steve Mueller: We will
be slowing down on downspacing. We hope with the patterns we're doing this year
we'll have 90% of our answers, but there could be a small part of the field
where we have to go back in and do a little bit of testing, but right now I
wouldn't expect a lot on the downspacing testing part of it. As I say, we'll
have something over 100 wells to do from the standpoint of holding acreage or
first wells in section. And then the rest of that we'll actually start going in
and drilling pad work to start to do that pad work.
Scott Wilmoth: Great
and then just following up on your comment that you could be running 13 or less
rigs next year, what rigs do you have currently on contract and when are those
expected to roll off, any in the near future? And then what are your thoughts on
laying down company owned rigs if prices are low enough?
Steve Mueller: Well,
11 of the 13 big rigs we own, the other two have relatively short-term
contracts. I think right now I'd have to go back and make sure, but I think
they're working month to month right now. But, we're talking about signing a
year contract with those rigs. As far as laying down ours, if the gas price
isn't there to support it, we don't have any problems laying down our rigs.
Scott Wilmoth: Okay
and last question for me. Can you update us on thoughts or plans for additional
hedges in 2011?
Steve Mueller: Well,
we'd love to hedge more; we just need the right price.
Operator: Your next
question is from the line of Amir Arif with Stifel Nicolaus.
Amir Arif: First
question on the IP rates for the wells drilled in this quarter, even if you
ignore the five wells, the older wells, just given that the laterals were
relatively similar to last quarter, can you just tell us what was causing the IP
rates to be down a little bit from last quarter?
Steve Mueller: I can
give you a little bit of color and for those who like details; I'm going to hit
some numbers here, so get out your pencils. We said that we had 36 wells that
were spacing tests; those 36 wells averaged 3148 Mcf a day. We had 58 wells.
They were first wells on sections. They averaged 3004 and then we had the other
51 wells or 35% that were basically 600-foot typical 65-acre spacings; those
were 3596 or almost 3.6 million cubic foot a day or 3.6 million a day.
And then we talked about in the past how much
percent are in the shallower north, which also kind of makes that overall number
down a little bit; 24% of the wells this quarter were in the shallow north area
part of the field. So what you're seeing is just what we've had in the past. We
will have a different mix each quarter. That mix in the quarter is going to have
an effect but what's really interesting about these numbers, the downspacing
tests are looking very good for the ones we did, because remember, these weren't
40-acres; there's a bunch of stuff at 20-acres that goes into that 3148. And so
I'm very excited about the fact we could just average 3.3 for the quarter.
Amir Arif: Just a
follow-up. On the first well in every section, generally that should be average
pressures but shouldn't that be as good or if not higher rates or is that--?
Steve Mueller: Well,
that goes back to the 24% being up in the shallower north. I'll just remind
everyone: In that shallow area, you're going to have a little bit shorter
laterals there, which means if we average higher for the quarter or average last
quarter, there's some other places we're drilling deeper. But they're going to
have a little shorter laterals but they certainly are going to have less
pressure and that gives you less IPs.
Amir Arif: Then a
second question just on the drilling time, 11 days but some wells coming in at
five; how long of a time do you need to sort of shift all the wells rolling
count towards the five or six or seven days or wherever it's going to average?
Steve Mueller: The
days will come down as we do more and more pad drilling. This year we're between
1.5 and 1.8 wells per pad average for the year; next year that will go up above
two and then by the time you get to sometime 2012 we'll be doing in the six plus
range, so over the next 18 months you're going to see that go up quickly and
that will drive those days down. And we're very comfortable because the pad work
we've done this year with the downspacing, we've averaged about eight days on
the pad, a little less than eight. We're comfortable we can go from the 11 to
eight.
And then these five days, if you remember,
this is where last year it took us two bit runs on average to drill our wells
and these five-day wells is one bit run to do it with some kind of new bit
technology. We don't know how much of the field yet that's going to work in and
whether we can do it across 80%, 50%, whatever that number, but the extent that
we can do a large part of the field at that four to five day range, that eight
drives down from there. But that's all going to happen over the next 18 months.
Operator: Your next
question is from Brian Singer with Goldman Sachs.
Brian Singer: On the
balance sheet, can you talk to what level of additional debt you're willing to
take on in 2011 and how aggressively you'd consider assets sales, which I guess
would then help us in thinking about how you would respond from a drilling
perspective at various gas prices?
Greg Kerley: We are
pretty committed, just like we were this year to live within a certain level of
cash flow. We had a delta that we were willing to go above in our new ventures
area and as we started drilling in the Marcellus but everything else has stayed
in the cash flow neutral range. And as we end the year basically with the asset
sales that we've had this year, we'll be borrowing just a couple of hundred
million dollars for the full balance sheet year. As we go into next year, while
our debt to capital will be down to about 28%, we don't quite know obviously
what gas prices are going to be next year and we're definitely going to plan a
balance sheet and a budget that stays within a cash flow level that we're
comfortable being within. That will be pretty close to whatever we believe the
cash flow level is going to be.
Steve Mueller: Let me
add one thing to that. We haven't got our 2011 budget done by any means and so I
don't have exact numbers, but I would expect with what I know today with the gas
price that's out there, expect that 2011 is going to have a smaller capital
budget than 2010. So we are dedicated to work within the environment we have and
build our budget to whatever we can work with and win in that environment. So
we're not going to push too much. We may sell some other assets but we're not
building a program to sell a bunch of assets so we can invest a bunch of capital
and go that direction. That's not the way we're looking at the future.
Brian Singer: And so
should we expect then that you still will be comfortable with the same kind of
couple of hundred million dollars of additional debt next year as this year or
are you thinking ultimately you plan to keep debt flat next year versus this
year?
Steve Mueller: We
haven't got that far but certainly for us, $100 million to $200 million is
basically flat, so that's kind of cutting hairs right now; we'll know more here
once we get the budget done.
Brian Singer: Thanks
and lastly, how should we think about your activity levels and where you want to
take the Bossier drilling and the Marcellus drilling from here?
Steve Mueller: We have
to drill some wells just to hold some of our acreage and so we'll do that. When
you think about what we're doing -- and we said the first well we've done is a
Haynesville well, the next two that we drilled have been Bossier. The Bossier is
actually thicker than the Haynesville and in core, because we've cored one of
those wells, it looks better and so we need to get some tests on the Bossier
itself and then we can make a decision on how fast we want to go. But certainly
in the fourth quarter and in the first quarter of next year you're going to see
us drill some wells just to hold some acreage.
Operator: Your next
question is from Rehan Rashid with FBR Capital Markets.
Rehan Rashid: On the Canadian front, real quick, any
update, you've had some time to do some more work geologically speaking at
least?
Steve Mueller: To give
everyone kind of an update where we're at in Canada, we got that awarded to us
where we could actually start doing some work last May. We've gone out and flown
gravity and magnetics and are just now getting the data in and starting to do
the interpretation. That'll probably be done later this year or going to early
2011.
We also have done what they call surface
geochem where they actually go sample the surface. We put samples out there in
September and have just finished a week ago getting those all back. You leave
them in the ground, you sample for about a month to month and a half. Those are
all in. You have to do an analysis on that and then you'll interpret that;
that's early next year as well.
The other thing that we've done is we started
preparing to shoot 2D seismic on original grid in early 2011 and one of the ways
you prepare is you go out there and test various kinds of sources to see what
the signal will be and whether you need to use dynamite or vibrators or other
kinds of sources and we've done that in two spots in the areas that we thought
would probably be the deeper parts of the basins that are there and are getting
good reflections, with relatively low loads on a dynamite type source.
And that tells you two things; one, we can
get good seismic and secondly, getting good reflections and we're getting good
reflections down about 15,000 feet, says that there's some basins out there. And
that was one of the key things. So, that's probably the newest news is that we
are getting a little bit of reflections on some seismic. But again, those were
point sources, just testing to see what the source would look like.
Rehan Rashid: Thank
you. One more quick question going back to the five days. I know one kind of bit
run helped it down to that level but geologically speaking maybe, what helped?
Steve Mueller: There's
really not anything from a geologic standpoint. Certainly if you're in a faulted
area or you're in an area that's got a lot of changes in dip, you probably
aren't going to be able to do it in five days because you're having to do a
little bit more control. But really, these wells we've tried now in several
different spots and it's not so much geology related, it's just the fact you
didn't have to come out of the hole.
Rehan Rashid: Got it.
Last one, on the recovery factor front, whatever work you've done so far, the
downspacing results, are we comfortable that we are at 50 percentile recovery
factor of gas in play or we're not quite there yet?
Steve Mueller: We are
striving to get to that point. I don't know if we're quite there yet, but I know
a lot of plays that talk about 30% or 35%; we think we've got evidence of
certainly well above 40 and heading towards 50.
Operator: Your next
question is from Gil Yang with Bank of America.
Gil Yang: You said
that your rate for the Fayetteville, the growth rate was 1.5 Bs per day, I
think. Can you tell us what your third quarter exit rate is and what your
full-year exit rate is anticipated to be?
Steve Mueller: I
really don't have that right now, to tell you the truth. The third quarter exit
rate is a little bit above what our average was at year-end. It's easy enough to
back-calculate from our guidance but I don't have it sitting right here.
Gil Yang: All right.
In terms of the well count obligations for 2011; 130 to 150, how many wells
would you have to drill to stay flat at your exit rate for 2011?
Steve Mueller: I don't
know. Again, I don't know about the exit rate, but I can tell you how many
it would take right now. It takes about eight to nine
rigs.
Gil Yang: Eight to
nine rigs to stay flat from current production rate?
Steve Mueller: Yes,
probably.
Gil Yang: Or to stay
flat for the year versus 2010?
Steve Mueller: To stay
flat for the year at today's rates. And the reason I say eight to nine, it
depends on how fast you want to assume you're going to drill the wells.
But--.
Gil Yang: --Okay.
And then, last question, about the pads. You said that you're sort
of eight days per well per pad--on a pad. What's the average days per well
off the pad?
Steve Mueller: Well,
you're looking at it basically with our previous quarter numbers. Last
quarter, it was over 70% of our wells were single wells being drilled and that
was about 12 days per well. So that's kind of your
bookends.
Gil Yang: Okay, great.
Thank you.
Operator: Our next
question is from the line of Thomas McNamara of Impala Asset Management.
Please proceed with your question.
Thomas McNamara: Good
morning, gentlemen. Just a couple ones. Steve, could you tell us
when you think your mix, so to speak, of the well detail bottoms? You had 24% to
the north and shallower and a higher percentage this year of total
production?
Steve Mueller: I can
give you some general feeling and there's kind of--the near term we're going to
continue to fill in that hole that we have in kind of the eastern part of our
acreage. And as you go into the fourth quarter and the first quarter,
we're going to be moving up north of the lake some more. So I would expect
the next couple of quarters--and originally we had a plan that was kind of
straddled between third and--between fourth and first and it may get a little
bit more in fourth than first. But you'll see us going up in the real
shallow north of the lake and kind of filling that in towards the end of this
year, early next year. I think if you look out in the future and say,
okay, when you're on pad drilling where will you be drilling at? We'll
really be drilling across the entire play, and then you'll get kind of a
constant average. And the reason we'll be drilling across the entire play
is the thing that drives the system is your pipelines. And if you put all
your rigs in one spot, you'll overload on the pipeline system and you'll be
backed up from whatever it's doing. So we'll be moving the rigs around
basically to keep the system full and consistent and by that very nature it
makes it go across the play. So we've got probably three quarters of, as I
said, drilling this 150 wells next year and filling in the holes and getting
those first wells in section, and then you're going to see us start moderating
across the area. And by 2012--mid 2012 when we're doing that pad work, it
will get a little lumpier because today, remember, we're drilling less than two
wells per pad, so you can put them on fairly consistently - one to two wells at
a time. You'll be drilling eight--six to eight wells, 10 wells per pad.
It will get a little lumpier and it will be spread across the
play.
Thomas McNamara:
Right. And just with the 2.8 million average cost per well, could you
speak to the variability and some of the reason behind if it's a
widespread?
Steve Mueller: Yes.
In general, the shallow part of the play is 2,000 foot or less in depth.
Those wells actually cost 2.5--actually about $2.4 to $2.5 million.
The very southern end of the play today is about $3.5 million and it's
about 6,500-foot depth. And so, you get a little bit of swing on that
portion as you go through. The other thing that you're seeing a $2.8
million number today though is the full effect of the sand and some of the other
things we've done from vertical integration. So that portion of it, if you
compare us to say others in the industry who aren't integrated in the
Fayetteville Shale, our well is running about $300,000 less than whatever
they're doing in the industry. So I think we've got that moderator in
there that helps control our costs going forward, and then we do have the
geology that will swing across the area. Again, as we go shallower
you might see that cost a little bit less next quarter or first quarter because
we're a little shallower with more of our wells, and then it may go up a little
bit once we get that average across the field.
Thomas McNamara:
Right. And just to follow up on that, could you remind us when your
framework fracing agreement is due for pricing changes or however we should
think about it?
Steve Mueller:
Yes. Usually right after the first of the year is when we do our
next round of bidding for fracing in the Fayetteville Shale. And to tell
you the truth, we're talking to vendors right now. But our current
contract goes through I think it's March 1 of next year.
Thomas McNamara: Okay,
great. Thank you.
Operator: Thank you.
(Operator Instructions.) Our next question is from the line of David
Heikkinen with Tudor, Pickering. Please state your question,
sir.
David Heikkinen: Good
morning, guys. As I think about the play and kind of evolution of the
play, one of the questions we get is are you kind of achieving your terminal
rate of peak production, lowest cost, and how do things trend over time and what
is the continued evolution. As you think about that across the average two
years from now, drilling on a pad, I mean, how should we think about where you
think well costs will be, the pace, and all those kind of longer term
perspective of where the Fayetteville is going?
Steve Mueller: Well,
certainly, if you look at us today, and I'll start with the kind of days to
drill, we're averaging 11. We said that's going to go down to eight.
Certainly, you can't get much faster than five. That's almost your
technical limit. So we know we're going to have a step jump on there, but
then how much can you drive it down from that eight towards six or five?
That's still to be learned over the next two years. On the pad
drilling, we know we can take the days out and that's simply by the fact that
rather than having to take the rig apart and move it a mile, and then put it
back up every time, you move it 10 feet with everything in the derrick, that's
where you're getting the three to four days out of your time. But we
haven't put any factor in for the cost efficiencies when you are able to work on
different wells while you're fracing, while you're able to set up different
wells. We haven't put any factor in there for the fact that by this time
next year we have all the pads built that we're going to have to build.
And so, our cost in the past had those pads in the cost and in the future
it won't have those pads. The tie-ins on our midstream, again, you'll have
lines to every one of those pads by this time next year and you'll see the
midstream go down.
So
those costs and those cost savings, I can't tell you exactly how much that is,
but that's all coming up over the next year as we go through the process.
And then, on the fracing portion of it, most of this year, we've been
trying to do test work on spacing. When you do the test work on spacing,
you keep your fracs constant. You don't have the chance to really play
with the fracs and make them better and try to see how much cost you can get out
of that. We started doing that now in some of these other wells that are
not part of the testing. And it looks like just preliminarily that we can
cut back on the amount of water we've been using and we're back--we're in about
a 10% cutback on our water right now, and it looks like we're getting very
similar frac characteristics and very similar EURs and IPs. And we'll play
with that, we'll play with the sand and the sand content. But if we could
take 10% out of the water, that's $50,000 to $70,000 a well. So those are
all--as we get to the pure development mode, there's still those things that are
coming up, and that's why we're kind of excited about the next 12 to 18 months,
because that's all going to unfold as we go through and make the play even
better than it was.
Your basic big question is how far have you
come and where you're at. We've come a long way. You think about
2007 - 17 days, 2,100-foot laterals or a little over 2,000-foot laterals, $2
million a day - can we double our production rates in the future and keep the
well cost at $3 million? Probably not. But we can still go a long
way towards making the wells better and more economic.
David Heikkinen: Just
on the fracing side and other shale plays we've seen improvements in recovery
and production benefits from fracing adjacent wells or kind of doing the zipper
frac type design, are those the type of things that you'd also do, I mean, just
kind of those little nuances that could potentially improve
recoveries?
Steve Mueller: On all
of these wells that we're drilling now, where we're doing the test work and
we're drilling maybe three wells from a pad or four wells from a pad doing the
downspacing test, we are doing zipper fracs on those. We're trying--we've
been gathering data. I can tell you that with the data we have to date,
and we don't have that much obviously, we're not seeing a huge effect.
We're seeing cost effects, but we're not seeing a huge effect on the IP or
the EUR, but it's early on that one. We'll certainly do
that.
You certainly have the opportunity to test
where you frac them all together and kind of build energy and get more fracing
done and we have hardly done any of that to date. So there will be some of
that we can do in the future.
David Heikkinen: I
think that was my two questions. Thanks, guys.
Operator: Thank you.
Our next question is from the line of Nicholas Pope of Dahlman Rose.
Please proceed with your question.
Nicholas Pope: Good
morning.
Greg Kerley: Good
morning.
Nicholas Pope: Hey,
just looking at the midstream properties, any thoughts there on maybe bringing
in a partner to monetize a piece of that or just taking any part of that at some
point and spinning any of that out?
Greg Kerley: Well, the
midstream we're very focused on that we have a lot of optionality with it.
We have probably--from an operations standpoint we're 18 months, two years
away from kind of having the backbone of the system built out, as Steve said,
and then really in full development mode. Really as we look at 2011, it
looks like the midstream will be cash--should be or very close to cash flow
neutral, and then start becoming cash flow positive after that. So it is
a--it's an asset that we believe is very valuable. It's an asset that we
also look at and believe that our shareholders don't really fully appreciate the
value that we have created in that asset. We'll have about--at the end of
this year about 800 million of total capital in all the lines and compression
and everything else to date, similar to close to that, 750 to 800. And an
EBITDA that's going to be a little over 200 million and growing with our
production stream over the next several years, too, obviously. So a very
valuable asset and it's something that we are looking at and conscious of that
right now the multiples in the market for MLP assets, other assets, are higher
than what we're trading at. And we need to figure out exactly how to get
the full value of that reflected in our stock.
Nicholas Pope: Yes,
appreciate it. And then, just back to the Fayetteville and downspacing,
whenever you talk about the 30, 40-acre spacing, the 20% being you think can be
developed, like what do you all--I know you went through it a little bit, but
what are the assumptions there in terms of like how much cannibalization you
have on like a percentage basis to get to those lower spacing?
Steve Mueller: Yes.
On the 65-acre spacing, we talked about this last quarter, we're between
five and 8% interference. I can tell you that some of the places where the
300-foot spacing would work, which would be basically half that 65 acres,
somewhere around 30-acre spacing, that number is approaching 20% interference,
but the--it's--they're still very good wells and very economic. But that's
the range, somewhere between eight and 20.
Nicholas Pope: Okay.
That's real helpful. Thank you. That's all I
had.
Operator: Our next
question is from the line of Dan McSpirit with BMO Capital Markets. Please
state your question.
Dan McSpirit:
Gentlemen, good morning, and thank you for taking my questions. Turning to
new ventures, year-to-date investments and new ventures total approximately $111
million. What will the total budget be for 2010 and what could that look
like for 2011? And then, second to that, if the 2011 strip continues to
feel pressure, should we expect funds allocated away from East Texas and to
Appalachia and even to Fayetteville Shale with new ventures being the
beneficiary?
Steve Mueller: Well,
let me answer the second part of that question first. As you look at 2011
today, East Texas is going to slow down even more than it has. And again,
we--if you think about what we've done this year from original budget, we sold
some assets and we've cut about $100 million out of that capital. And so,
what it leaves you with on the kind of development drilling side is Pennsylvania
and Fayetteville will obviously be the things that we key on, at least early in
next year. And we'll kind of figure out what the right amount is as we get
closer to 2011.
As far as new ventures goes, we would like--I
won't tell you--I can't tell you exactly what our capital budget is going to end
up with the year. If you remember, we have a 1031 exchange from that sale
that we did of East Texas and anything we pick up in new ventures, as long as we
identify that general area beforehand, we can use to defer some taxes
potentially in this 1031 account.
So if we can accelerate, which we've been
trying to do, and get--save some taxes, our number may be another $50 million
higher than this number. I don't know if we can do that or not. But
that's part of the reason you're seeing the new ventures a little higher than we
had in the past because we've been trying to do that 1031 exchange.
As we look out in the future, next year -- we
have been picking up acreage in some other plays. We'll talk more about
that when we get the plays put together and get ready to do something with them.
But next year I think you'll see us invest at least as much money on land.
As we go forward we'll need some seismic and other sciences like we've
done in New Brunswick. And then you'll see us drill a couple wells next
year. And that will not be in New Brunswick. New Brunswick's a 2012
drilling program.
So the -- I don't know the exact number but
we'll have some actual well drilling and new ventures and we'll have certainly a
significant piece of land as well.
Dan McSpirit:
Okay. And then one follow-up if I could. Any estimate on what
percentage of the acreage in Fayetteville Shale today doesn't meet your hurdle
rate or your present value index at current strip pricing?
Steve Mueller:
Let me answer that a little -- I don't know the exact answer there.
But I can tell you that we've tested about 75% of our acreage to date.
And the current -- with the current strip almost all of that looks pretty
good. But there's about 25% of the acreage we haven't even put a well bore
in yet, and a large piece of that's up in the unit that we have, the federal
unit we've got, and there's some other acreage off to the west that we haven't
done anything with. And we've done very little with our conventional as
well. So we need to get some more tests in there to even figure out if its
economic at all at any price, so.
Dan McSpirit:
Okay. Thank you. I'll get back in line. Thank
you.
Operator: Our
next question is from the line of Robert Christensen of Buckingham Research
Group. Please proceed with your question.
Robert Christensen:
Yes. I'd like to know why you didn't hedge more. Curious.
Steve Mueller:
Because we've been trying to get $5 hedges and you couldn't.
Robert Christensen:
All right. But your program works at sub-$5 gas?
Steve Mueller:
Yes, it does. Yes, it does.
Robert Christensen:
Okay. So moving on. Marcellus Shale, when are we going to see
or when do you need to make a decision to go a little more active
there?
Steve Mueller:
Marcellus is, in our minds, kind of a swing area right now. We need
to do what we need to do at the Fayetteville Shale and then as it -- we had in a
previous call, we've got certain things that we want to do in new ventures.
And then the Marcellus is what can you do after you've done those two
things. And with the low gas price, next year I would expect that we're
going to have more drilling than this year. We'll probably exit the year
with at least a second rig. But ultimately we're going to have to have
about five rigs running, and that really is driven on gas price. And we're
working on those numbers right now and we'll just see what happens as we put
2011 budget together and what we think about 2011-2012.
Robert Christensen:
But is there sort of a break point on the Marcellus just following on with
that? I mean, is there a -- some time frame where you won't get it all
done on your leasehold? Is there some sort of decision hurdle of --
related to leasing and how fast you can drill the hole at all? I mean, is
there --
Steve Mueller:
Well, we certainly have some lease dates coming up. Probably the
critical year for leasing is towards the end of 2012.
Robert Christensen:
Okay.
Steve Mueller:
So we've got some time to worry about that. But that's -- there is
that. And running one rig -- and that's what I said, we have to exit next
year with two rigs running. That gets us a long way towards holding all
that acreage we need to hold.
Robert Christensen:
Thank you.
Operator: Our
next question is from Jack Aydin from KeyBanc. Please proceed with your
question.
Jack Aydin: Hi,
Steve.
Steve Mueller:
How's it going?
Jack Aydin:
Good. Most of my questions were answered. But is it fair to
think this way? I know you mentioned about drilling days and all that.
Is it fair to say that you need north of 500 wells in 2011 to hold your
production flat and incremental is more or less is going to be growth?
Steve Mueller:
No, that's-- if you're running -- I said before running eight to nine
rigs, that's somewhere around 400 wells, a little less than 400 wells.
Those are production flat. And we will drill roughly this year,
2010, 500 wells operated and there will be another, oh, I don't know, 100 wells,
outside operated. Those outside operated wells are 25% working interest.
So what really drives your production growth is that wells we operate and
- -- so that's really, when I'm saying 400 and 500, those are the kind of numbers.
You drill 500 wells next year, you'll have significant growth.
Jack Aydin:
Okay. Thanks a lot.
Operator: Our
next question is a follow-up from the line of Dan McSpirit with BMO Capital
Markets. Please state your questions.
Dan McSpirit:
Gentlemen, one more if I could. Does it make sense once you enter a
positive free cash flow state in the Fayetteville Shale or when development is
more mature to move the assets into maybe a different corporate vehicle like a
partnership that better supports distributions?
Steve Mueller:
We've talked about that. I don't -- I don't know because we're not
quite there yet. But that kind of goes hand-in-hand when you talk about
the midstream. Part of midstream -- the right time for midstream is when
you start to see a decrease in capital and you've kind of built out the system
and so that you can actually do these other vehicles. And to the extent
that you could drill a portion of the Fayetteville and get it almost all into a
PDP status, there might be some vehicle you want to put it into.
The reason I say kind of talk about that
jointly is, I was talking about before the fact that you're going to have to
drill across the entire field, otherwise you overload your midstream system, so
that they kind of go tandem. But to the extent that you could do it in the
midstream and you start seeing a similar decrease in midstream, you might be
able to do something like that on the E&P assets as well.
Dan McSpirit:
Very good. Thank you again.
Steve Mueller:
Thank you.
Operator: Thank
you. Our next question is a follow-up from Scott Wilmoth of Simmons and
Company. Please proceed with your question.
Scott Wilmoth:
Hey, guys. Just following along with that last question. Can
you give us an update on potential long-term contracts with utilities and what
the outlook is for that?
Steve Mueller:
To give everyone kind of a history and -- we've been working for the last,
well over a year, with the utilities and working with them on what a contract
would look like and whether they'd want a contract and how long that contract
would be. A year ago this time, all the questions had to do with how are
you going to take volatility out in any kind of contract you have and is there
really enough gas there.
Today we're past all
that and we're talking to several different utilities and various organizations
about here's the actual form of a contract that we could use and would this work
with your Public Utility Commission. And then if it would work with your
Public Utility Commission, let's figure out how to go towards that Public
Utility Commission and get their approval.
So we've made that much progress to date.
You still have a three corner deal. You've got the utility.
You've got the E&P business that's supplying the gas. And then
you have to have the Public Utility Commission agree to all that. And so I
think it's -- I think in 2011, you're going to see some movement on that.
But it's not fast movement along the way just because of that. But
we are making progress.
Scott Wilmoth:
Can you give us any details in terms of what current negotiations are or
the utilities in terms of time horizon, contract length? Are we talking
three to five or five to 10? And then how they think about how to -- are
you guys looking at collared prices? Or how are they indexing those
prices?
Steve Mueller:
Yes. Probably the best way to answer that is each utility and each
area of the country's a little bit different. I think ultimately you're
going to have more what I'll call index prices range -- range of prices that
somehow switch with the commodity. But that's not necessarily the case
everywhere.
The length of contract, there are some
utilities that want very short contracts. And when I say short, five-year,
three-year type contracts. There are some that want something longer than
10-year. All the ones we've been talking about that have been longer than
10 years have had some kind of outs on them besides just being some kind of
index price as well.
But again, it depends on the part of the
country, the utility commission, their rules, and then the way that the
utility's going to supply their gas. So there's not a standard one out
there. But I will say it ranges from three years to 20. And there
are some that want a locked, fixed price and there are some that want an index
price.
Scott Wilmoth:
Okay. Thanks, guys. That's all I had.
Steve Mueller:
Yes.
Operator: Thank
you. We have reached the end of our allotted time for question-and-answer
session. I would now like to turn the floor back over to management for
closing comments.
Steve Mueller:
Thank you. As you can tell, I'm excited about what we've done this
quarter. This is very challenging times. It's challenging in a lot
of different ways. And we had a great quarter in these challenging times.
And I think there's going to be some challenging times in the future.
But I think we can have a lot more great quarters as a company.
And when you think about why that would be
the case, we're already, as Greg said earlier, one of the lowest cost operators
that are out there. And you hear a lot of operators talk about, well,
tough times, we're going to watch our costs. Well, we're not watching our
costs. We're trying to drive our costs out. And that's what we've
done by vertically integrating. That's what we're doing by decreasing the
well days. And then you kind of say, well, there are other challenges out
there, that we are in what are very difficult regulatory times almost everywhere
in the country. And sometimes they almost become stifling.
But again, we're dedicated. We're going
to do the right things as a company. And we watch as various states look
at transparency and we welcome transparency. And especially if you
followed Arkansas, they've got some pending regulations where they want to have
complete transparency on fracture of stimulation fluids, and we look forward to
that. I think by the beginning of the year that will be in place and we're
excited about that. And we hope those kinds of things happen in all the
states.
And then when you look at our learning, we've
got challenging times. But with our testing program that we've done and
downspacing, we've learned a lot in the Fayetteville Shale. It's going to
set us up over the next couple years. We're going to be able to get to
that pad drilling and be able to drive more cost out of the system. But
the other thing it's done for us, it's setting us up to better do Pennsylvania.
And one of the comments we had, earlier question was, well, why aren't you
going faster? One of the reasons we're not going faster are some of the
regulations. Another reason is we can take the learnings in the
Fayetteville and quickly apply them in Pennsylvania. And we want to do
that.
And those same learnings are going to be
applied to our new ventures, too. And part of what we're doing in new
ventures and the kind of projects we're looking for is based on our learnings
there. So that's important. And whether it's challenging times or
not, that's something that we just want to do as a company and is important I
think for our success in any price environment.
And then the last thing -- we talked about
this too -- is that when you look at our company, we set ourselves up to manage
for low price, high price. We are going to keep a balance sheet that is
clean. We are going to manage within the price environments there.
You're not going to see us say, well, yes, I know it's $4 gas, but we're
going to go borrow a bunch of money and drill into that environment. On
the other side of it you're going to see us drill economic wells. And as
long as we can drill economic wells, we'll drill those economic wells.
So as you look towards the future, we are
dedicated to give our shareholders value no matter what the system has out there
that they're going to throw at us.
And with that, I'd like to thank you for
listening to us this conference call. And I look forward to reporting more
about this in the next quarters ahead. Thank you.
Operator: This
concludes today's teleconference. You may disconnect your lines at this
time. Thank you for your participation.
Explanation and Reconciliation of Non-GAAP Financial
Measures
We
report our financial results in accordance with accounting principles generally
accepted in the United States of America (GAAP). However, management believes
certain non-GAAP performance measures may provide users of this financial
information with additional meaningful comparisons between current results and
the results of our peers and of prior periods.
One such non-GAAP financial measure
is net cash provided by operating activities before changes in operating assets
and liabilities. Management presents this measure because (i) it is accepted as
an indicator of an oil and gas exploration and production companys ability to
internally fund exploration and development activities and to service or incur
additional debt, (ii) changes in operating assets and liabilities relate to the
timing of cash receipts and disbursements which the company may not control and
(iii) changes in operating assets and liabilities may not relate to the period
in which the operating activities occurred.
See the reconciliation below of GAAP
financial measures to non-GAAP financial measures for the three months ended
September 30, 2010 and September 30, 2009. Non-GAAP financial measures should
not be considered in isolation or as a substitute for the Company's reported
results prepared in accordance with GAAP.
|
|
|
|
|
3 Months Ended
Sept. 30, |
|
2010 |
|
2009 |
|
(in
thousands) |
Cash
flow from operating activities: |
|
|
|
Net
cash provided by operating activities |
$
406,009 |
|
$
315,795 |
Add
back (deduct): |
|
|
|
Change
in operating assets and liabilities |
15,051 |
|
15,978 |
Net
cash provided by operating activities before changes
in
operating assets and liabilities |
$
421,060 |
|
$
331,773 |