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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported) May 1, 2001
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SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas 1 - 8246 71-0205415
(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.)
2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
(281) 618-4700
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year; if changed
since last report)
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-1-
Item 7.(c)
Exhibits Reference
(99.1) Conference Call Summary dated May 1, 2001. p. 3 - 12
Item 9.
Regulation FD Disclosures
Southwestern Energy Company is furnishing under Item 9 of this Current
Report on Form 8-K the information included as exhibit 99.1 to this report.
Note: The information in this report (including the exhibit) is furnished
pursuant to Item 9 and shall not be deemed to be "filed" for the purposes of
Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the
liabilities of that section. This report will not be deemed an admission as to
the materiality of any information in the report that is required to be
disclosed solely by Regulation FD.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
---------------------------
Registrant
DATE: May 2, 2001 BY: /s/ GREG D. KERLEY
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Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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Southwestern Energy Conference Call
Company Summary
2001 First Quarter Results Conference Call
Tuesday, May 1, 2001
Chaired by
Harold Korell
President and Chief Executive Officer
Korell:
Good morning and thank you for joining us today. With me are Richard
Lane, our Senior Vice President of Exploration and Production, and Greg Kerley,
our Chief Financial Officer. After some preliminary comments, I'll turn the
floor over to Richard for an update on our E&P operations and then to Greg for
comments on our financial results. After that, we'll be available for questions.
If you've not received a copy of the press release announcing
our first quarter results, you can call Carole Anne at 281-618-4710 and she'll
fax a copy to you. Also, our attorneys have asked that I point out that some of
the comments during this teleconference may be regarded as forward-looking
statements that involve risks and uncertainties which are detailed in the
Company's Securities and Exchange Commission filings. While we believe they are
a reasonable representation of the Company's expected performance, actual
results could differ materially.
Now to a discussion of the first quarter. 2001 has started off
with very good results. I'm pleased with the continued progress of our E&P
program and, in this commodity price environment we're anticipating strong
results for the rest of the year.
Financially, we had a tremendous quarter. Our earnings in the
first quarter alone represented over 75 percent of our total earnings in all of
2000. Pricing has helped the entire industry, of course, but we're also
executing our strategy with the drill bit, which is resulting in higher earnings
and cash flow. In fact, our cash flow in the first quarter has allowed us to pay
down a good portion of the debt we incurred last summer.
We'll continue to focus on reducing our debt level and, at
current prices, are positioned to pay down approximately $70 million in
long-term debt by year end. Overall, I'm very pleased with the first quarter
results and I urge you to keep an eye on our results for the rest of the year.
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This is not the old Southwestern Energy that some people
remember. We're focused on continuing the momentum we've gained with our E&P
strategy and we're very serious about adding value for our shareholders.
That concludes my comments and I'll now turn the
teleconference over to Richard Lane for an update on our E&P operations.
Lane:
Thank you, Harold, and good morning. In the first quarter of
2001, we continued to build on our success from last year with active drilling
programs in the Arkoma Basin, Gulf Coast area, and our Overton field.
Additionally, we have drilled several successful wells in our Permian Basin
program and are currently drilling on our first of several South Louisiana
prospects planned for this year.
Production for the quarter was 9.0 Bcfe, up from 8.7 Bcfe in
the first quarter of last year and our production rate at the end of the first
quarter was 105 million cubic feet equivalent per day and this is our highest in
over two years. In total, we participated in 30 wells that were spud in the
first quarter. Of these, 15 were successful and 10 were in progress at the end
of the quarter.
We continue to create value with our Arkoma Basin drilling
program. In the first quarter, we spudded 13 wells. Six of these were
productive, three were dry and four were still in progress at the end of the
quarter.
At our Haileyville prospect in Pittsburg County, Oklahoma, we
continue to be successful. Last quarter, you'll remember, I mentioned that we
had just logged our Agnes #1 well in this trend, and I'm pleased to report this
well is now on production and flowing over 20 million cubic feet per day. Our
working interest in this well is 37 percent.
This brings our Haileyville area production to approximately
31 million cubic feet per day from these Atokan age sands reservoirs we're
targeting. Our interest in these wells range from 32 to 49 percent and our
latest well in the area, the Cope #3, was spud last week.
In addition to our drilling program, we've expanded our
workover program in the Arkoma Basin to capitalize on the current high gas
prices. Two recent successes here have been our Ozark Townsite and our Goznell
wells. We fracture stimulated these old wells and have seen production increases
of 2.2 and 1.8 million cubic feet per day. These projects are delivering five to
10 fold production increases for us and rapid project payouts. We anticipate
performing 10 to 15 additional workovers in the Arkoma region during the second
quarter.
Going to the Permian Basin, we were successful in discovering
new reserves in four out of the five exploration wells that we drilled and we
completed five out of 10 wells overall in the first quarter, with three still in
progress. Our exploration focus continues to be primarily in the Delaware Basin,
targeting Devonian oil and Atokan-Morrow gas objectives.
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Acreage from our previously announced exploration joint
ventures with Phillips Petroleum and Energen Resources in Lea and Eddy Counties,
New Mexico, continues to be a key exploration asset and a valuable resource for
us for generating new drilling opportunities. In the Permian, we anticipate
drilling and evaluating three to four additional wells in the second quarter.
At our Overton field in Smith County, Texas, the first two
wells drilled and completed in our in-fill drilling program are very
encouraging. The Arnold Gas Unit #1-2, which has been on production since March
15th, is producing currently at about 1.8 million cubic feet per day. The
Kickapoo Gas Unit #1-2 has been on production approximately 15 days and it is
producing about 2.7 million cubic feet a day. Now, while these two wells are
early in their productive life, their performance is currently exceeding our
pre-drill expectations. Utilizing a two-rig program, we're currently drilling on
additional wells at the Ware 1-2 and Allred 1-2 locations.
As we stated at the time we acquired this property, we see the
immediate potential for 15 development locations, with future potential for up
to 25 to 30 additional wells. We've also expanded our position in the Overton
area through a farm-in of approximately 5,800 adjacent acres that includes a
drilling commitment for this year and the potential for five to 10 locations on
that acreage. In addition, we're negotiating with a potential partner that would
allow for a more accelerated development plan than originally budgeted for this
year.
In South Louisiana, development operations have progressed on
our earlier discoveries. The State Lease 16625 #1 development well on our Malone
discovery was successfully completed in the Marg A sand at a depth of
approximately 12,500 feet. This well is currently on production at a rate of
15.1 million cubic feet a day and 175 barrels of condensate per day, with a
flowing tubing pressure of 4,000 psi. Southwestern operates the Malone wells
with a 33 percent working interest.
Additionally, we spud our first development well on our North
Groesbec discovery. The Norman Breaux #1 is currently drilling at approximately
7,500 feet on its way to a total depth of 20,900 feet. This well will further
develop the P-10 sand currently producing in our discovery well, which was the
Brownell-Kidd #1, and that well's producing 16.4 million cubic feet a day and
583 barrels of condensate per day. The Norman Breaux well will also test some
shallower additional objectives not seen in the Brownell-Kidd well.
Exploration drilling is in progress at our Mahone prospect,
located in Vermilion Parish. This well is currently drilling at approximately
13,000 feet. The Mahone prospect, with over 100 Bcfe of gross unrisked potential
is targeting Miocene Age Discorbis and Cib Jeff sands and is planned to be
drilled to a total depth of 16,100 feet. We operate this well and have a 50
percent working interest.
Our next exploration well will be our White Horse prospect
located in Cameron Parish. We also operate the Whitehorse prospect well and have
a 57-1/2 percent after-casing-point interest. Total depth of this well is
projected to be 13,100 feet and will be targeting Planulina Age P-2 and P-3
sands, which have proven to be quite prolific around the trend. We anticipate
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spudding Whitehorse in approximately 30 days. Finally, in the South Louisiana
area, we expect to spud an exploratory well on our Horeb prospect in Acadia
Parish late in the second quarter.
Overall, we're pleased with the start to our 2001 E&P program.
We continue to experience increase in drilling, completion and production
operation costs, as are other operators. We can, however, continue to help
offset these inflationary costs and reach our production reserve targets by
optimizing the selection and the timing of our capital investments and also
leveraging off the advantage we have in our ability to internally generate
desirable prospects.
The success of our drilling program is critical to growing our
production rates and to that end, we continue to maintain a strong inventory of
drilling prospects in our core areas to meet these needs. Our overall results so
far this year are in line with our original projections and we believe that our
production target of 38 Bcfe for the year is attainable.
I will now turn it over to Greg Kerley, who will discuss the Company's
financials.
Kerley:
Thank you, Richard, and good morning. As Harold indicated, we
had a very strong first quarter and made good progress on improving our balance
sheet.
We reported net income of $16 million or 64 cents of basic
earnings per share for the quarter, up 74 percent over the same period last
year. Cash flow from operating activities before working capital changes was
$38.6 million during the quarter, up 47 percent from the first quarter of 2000.
Our improved results were driven by both higher commodity
prices and increased production. Operating income for our exploration and
production segment was $22 million, up from $8.7 million for the same period in
2000. Commodity prices were very strong in the quarter, as we realized an
average gas price of $4.48 per Mcf, nearly $2 per Mcf higher than our realized
price for the same period in 2000.
We continue to be about 80 percent hedged for our 2001 gas
production target and there has been no change in our hedge position since our
press release on December 7th.
Operating expenses for the E&P segment rose during the quarter
due to the industry-wide increase in costs related to normal production
activities. Lifting costs on an equivalent unit of production basis were 51
cents an Mcfe in the first quarter compared to 38 cents an Mcfe the first
quarter of last year. Higher oil and gas prices also affected our production
taxes as they increased to 23 cents an Mcfe compared to 13 cents an Mcfe for the
same period in 2000. We anticipate that our operating costs per equivalent unit
of production will remain close to their current levels for the remainder of
2001.
Depreciation, depletion and amortization expense for the E&P
segment was also up in the first quarter due to our higher production volumes
and a slightly higher amortization rate.
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Amortization rate for the full cost pool in the first quarter averaged $1.08
per Mcfe compared to $1.03 in the prior year first quarter.
Our gas distribution segment continued its steady performance
with operating income of $9.4 million in the first quarter, which was equal to
the level of operating income in the first quarter of 2000, when you exclude the
impact of our Missouri utility properties that were sold in May of last year.
Our energy marketing efforts also provided $1.1 million in
operating income during the first quarter of 2001, compared to $1.0 million for
the same period last year.
Interest expense in the first quarter of 2001 is up about 41
percent from the first quarter of 2000 due to our increased debt level related
to funding the Hales judgment last year. We are, however, extremely pleased with
the amount of debt we've been able to pay down since the end of last year. In
fact, as of April 30th, we've reduced our debt by approximately $46 million and,
as Harold indicated, based upon the current level of gas prices, we are
positioned to pay down as much as $70 million of debt during 2001, which in turn
should have a positive effect on our stock price.
That concludes my comments, so now we'll turn back to the
operator, who will explain the procedure for asking questions.
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Questions and Answers
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1. Can you talk about the size of the Haileyville prospect and how
much you had booked at year end in that prospect?
Lane: The Haileyville prospect is really a trend for us that we're
developing. We developed a good part of it last year and then this
activity we're talking about in the first quarter of this year.
You know, on a gross basis out there, we've booked somewhere
around 23 to 24 Bcf for all the wells. That's net of about 6 to 7
Bcf for us.
2. What is your expectation of the size of that prospect?
Lane: Well, we have more drilling that we have planned for this year in
the trend, two to four wells and the higher rate wells that we're
seeing here are certainly anomalous. But you know, we need to get
a little bit more productive life to them before we really state
anything higher than what we've got recorded right now.
3. Greg mentioned the guidance for LOE and production taxes going
forward, G&A was down pretty nicely, at least on a unit basis.
What kind of level of G&A do you expect going forward? Is it still
the guidance you gave in December or do you expect it to be lower?
Kerley: I think the guidance we gave in December is still fairly
reasonable. Some of the G&A is probably just timing, but we have
started the year on a favorable note for that area and with the
other costs we have that are increasing, just inflationary
pressures, it's nice that we're able to hold the line pretty good
there. But I would still go with our targets.
4. When would you expect the Malone well to be on production?
Lane: It currently is on production at the rate of 15.1 million cubic
feet a day and 175 barrels of condensate.
Korell: You might have thought that was the rate of the first well, but
that's the second well.
5. When do you expect the first one to come on, then?
Lane: It's also on production. It's producing a little over 3 million
cubic feet a day, about 50 barrels of condensate and some
associated water, six to seven hundred barrels of water. That well
is producing from the first of five zones. You'll recall that we
discovered out there, a center zone-- the first completion at the
base of the well, a center zone and don't have a lot of reserves
booked to that zone, but we're trying to eke out all the
production we can out of that zone before we move up the hole.
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6. Is that producing as expected?
Lane: I would say on the order of what we expected. It was a Bcf or
less of gross reserves here that we were looking at, so I think
for now it's within the range of our expectations. The real
reserves and rates are to be had in the next zone up hole.
7. Have you've taken the excess cash flow that you've been able to
generate because of higher gas prices and oil prices and committed
those funds to debt paydown as opposed to letting Richard have a
few extra dollars to continue to show good results? How are you
working internally with these excess funds?
Separately from the cap ex standpoint, where would you max out,
assuming no capital constraints? What would be the maximum cap ex
you think you could spend efficiently or effectively for this
year?
Kerley: We are trying very hard to reduce our debt this year, but right
now what we're looking at and very hopeful of is that we'll be
able to meet our debt reduction targets and have additional
capital. We work very closely together to look at different
projects and, obviously, there are several of those. Just as
examples, our workover projects, that are paying back very
quickly, we're increasing our capital allocated to those.
We're looking at other areas, too, that make sense, that have a
very quick payback while trying to balance the two. We do believe
we need to reduce our debt. We're well on our way of meeting our
targets that we have and we hope that our prices will stay in a
range that enables us to commit capital to fulfill any other needs
that Richard has and to accomplish our debt reduction target.
Korell: It's an interesting and good question, but, against a backdrop of
having started the year with a discipline in mind to pay down debt
and to this point that's been what we have done with surplus cash
flow.
Sometimes when you have rig availability and all that being no
problem you can put your foot on the accelerator with additional
cash and do programs. To fully answer a question about spending
more capital this year, one would logically, rather than just off
the top of your head, have to sit down and go through what rigs
one could get in order to, for example, accelerate things like
Overton drilling out of cash flow or other projects.
We can always put capital into land and seismic data which
generates more activity for future years, but, that's if we decide
if it looked like we were going to have additional cash flow,
above and beyond where we are, above and beyond what we think we
do. In other words, and that could happen, possibly or it could
not happen, through performance on things we drill and put on
production during the year we could accelerate some. It's a little
bit of a hard question to answer, but I'm going to let
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Richard take a cut at what he thinks is laying in front of him
that he might be able to do.
Lane: I would say that if we were going to employ more capital that we
could look to add, as Harold mentioned, it's somewhat rig
dependent, but we could look to add a third rig to our program at
Overton, which seems to be off to a good start and deploy some
more capital there, and possibly deploy some more capital in our
Arkoma drilling program where we have quite a few ideas to pursue
there.
In South Louisiana, we have just operationally and logistically
been looking at doing eight to nine wells there, which is pretty
much a full plate. If we have some early discoveries there, we
could look to deploy some additional capital on development wells
in that area. Those would be the areas I think we would look to
spend more.
8. Please follow-up on the 5,800 acres you picked up as an offset in
Overton. What has been drilled to date, spacing wise?
Lane: There are nine units, 640 acre units there. Like Overton, a few of
the units have been drilled with a second well to 320. I believe
there are a total of 12 wells on nine units, much the same kind of
circumstances we see going forward here at Overton.
9. This really needs to be developed on 80 acres, isn't that the
case? Or is it 160s?
Lane: Well, certainly, we think 160s will be an achievable target, given
the performance of the wells historically and the wells we've
drilled and the drainage patterns that we see for these wells. We
should be able to get to 160 acres and, perhaps, like you say, go
down even further to 80s.
Korell: We need to work our way down on that, incrementally, because we're
doing a different sort of frac job on these than was done on the
original 16 wells that were out there and it appears we're getting
better rates. It appears that way in the early production data
from the new wells. And then question is, how does that affect the
radius of drainage?
When you're on 640s, there's no doubt we need to get to 320s and
probably little doubt that we need to get to 160s, but we'll learn
that as we go along, also. We'll be able to see through the
performance how that is changing the radius of drainage. Because
the old original wells are not draining and appear to not be
draining a very large area at all.
10. On the new fracs, is that the Bossier type of fracture you're
using up there now or-
Korell: The slick water, high-rate, smaller profit type of fracs that
Anadarko has been using in the Bossier.
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11. Regarding Haileyville, you mentioned two to four more wells this
year. How many potential locations does that play have to run
beyond that or is that pretty much it?
Lane: Well, you'll recall how these trends lay out, John. They're the
further you move along on them, they get more exploratory and more
speculative. Now we've bought acreage along the trend that would
support doing more than two to four, possibly five to 10 more
wells, given the acreage position we have, but the two to four I'm
talking about are in the immediate vicinity of the existing wells.
12. You said that these were anomalous flow rates. Do you think you've
found something here, an over-pressured zone? In other words, do
you have a new frac technique and is this repeatable elsewhere?
Are you actively leasing to expand this play? And I appreciate
it's speculative, don't misunderstand me, but I'm trying to
understand, is this just typical Atokan and you found a good spot,
or do you think you know something and you want to expand it? Help
me.
Lane: I think we know how to explore for these sands. We do a lot of
that and we're doing a good job of it. From a reservoir pressure
standpoint, I don't think there's anything anomalous there. I
think we have found a sweet spot, if you will, where these sands
are better developed, better processes and permeability and we're
seeing the results of that in the flow rates and, yes, we are
aggressively trying to carry what we've learned here and pursue
other acreage.
Korell: When we make the comment or someone makes the comment these are
not typical of the Arkoma, I guess these are not average wells.
But it is typical that every now and then in this part of the
Arkoma Basin, particularly on the Oklahoma side, you will drill
into areas that have thicker pay and you will have just a better
reservoir there and more reserves, and it looks like we've hit one
of these sweet spots as we've chased a particular sand channel
along trend.
Statistically they come along, probably every so often, and we
have just hit a nice area in this one sand channel. It's hard to
speculate about whether or not the thickness and quality extend
further or don't extend further and I wouldn't want anyone to plan
we've got 10 wells that you can do these kind of multiples on.
But we just have to drill our way along into it and it's a just
good thing that's happened to us right now.
13. So it's a case of rather be lucky than smart. Although you're
smart by drilling them, but you don't expect to be able to see
anything like this in seismic and maybe identify better areas?
Korell: No, you won't see it on seismic because of the sand thickness, but
you have to follow the sand trends and recognize that you could
get into one of these and it's no different
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than what we've been telling people we're doing in the Arkoma, and
we've just found one of the nice areas there and it's working
good.
14. My memories of the second well on North Groesbec is simply an
acceleration well, it's not going to add new reserves. Is that
right?
Korell: Well, it's really two things. One is that it will test the same
interval that we're currently producing from, but it will also
have an opportunity to test a shallower sand on the right side of
the fault where it could be productive. So we could see some
reserve adds there.
15. Just quickly stepping through the areas in Arkoma. You talked
about 10 to 15 workover potential in the second quarter, average
rates on those 1 to 2 million a day. Is that a fair assumption?
Lane: Well the examples I gave were re-frac workovers. Those tend to be
where we get the most bang for our buck and achieve the most
increased rate. The 10 to 15 refers to a whole variety of
workovers where we're cleaning out wellbores, changing out tubing,
reperforating and those kinds of things.
16. You're going to get a lot lower rate. So how do those 10 to 15,
how many wells do you think we'll be re-fracing? Are there any
more of those bigger potential workovers?
Lane: Yes. I think we have three to five that are re-fractype
candidates planned for the second quarter.
17. In the Overton area, people have asked a lot of questions. You
talked about a partner for accelerating development of the field.
Is that just purely for access to capital or what's driving that?
Korell: Well, two things, and it goes back to when we started the year,
looking at our capital program and we would like to accelerate the
drilling there. We 'd like to drill more wells there than we had
originally in our plan . We've had various people come to us
wanting to get involved in that project and we've been working on
an arrangement that would bring in some capital that would improve
the results for us, in other words, improve our rate of return and
our PVI, which is the thing that we have our focus on, on
value-add.
And Richard mentioned that we are working on that and it's
something that is out there. We're not ready to, we haven't got
the deal done, but it would be to enhance our return.
18. On the balance sheet, just looking at the $20 million of FAS-133
charges, any of those actually out-of-pocket cash expenditures in
the quarter? Or is it all just balance sheet items?
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Kerley: Those are really just balance sheet items. I mean nothing ran
through the quarter related to FAS-33 in the first quarter.
There's about-- and you're correct, there's about $20 million all
together, about $17 million related to the current the future 12
months and then about $3 million that relates to 2002.
19. Regarding the hedging program, I understood the comment, there had
been no changes since the last update. I was curious with regard
to '02 as to what you were looking at from an implementation of
strategy, either price movements up or down to ratchet that up and
will you continue to make use of the collars? Is that how we would
expect to see the next hedges appear?
Kerley: We are looking at '02 quite a bit. We, right now, have a pretty
small portion of our production that we would forecast for '02
that we've got a collar around. About 1-1/2 Bcf a quarter or 6 Bcf
for all of next year is collared at a collar that is $4 to $4.72.
Current '02 prices, I think, are just a little shy of $4.70, about
$4.68 and we are looking at that very heavily and would expect to
see us sometime, probably during this summer period, to increase
our hedge position in '02, maybe toward more, at least, to 50
percent of our volume and we would be looking at whatever the best
collar we could get at the time and try to keep it protected that
way.
Kerley: This is Greg Kerley. Thank you for joining us today and please
feel free to call me or Brad Sylvester with any other questions
that you have or for any other information that you may need. That
concludes our teleconference.
Operator:
Thank you. Ladies and gentlemen, that does conclude the conference call for
today. We thank you for your participation and ask that you please disconnect
your lines.
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Southwestern Energy Company
P.O. Box 1408
Fayetteville, AR 72702-1408
May 2, 2001
Securities and Exchange Commission
ATTN: Filing Desk, Stop 1-4
450 Fifth Street, N.W.
Washington, DC 20549-1004
Gentlemen:
Pursuant to regulations of the Securities and Exchange Commission, submitted
herewith for filing on behalf of Southwestern Energy Company is Form 8-K dated
May 1, 2001.
This filing is being effected by direct transmission to the Commission's EDGAR
System.
Very truly yours,
Stan Wilson
Controller