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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) February 15, 2002
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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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Item 7.(c)
Exhibits Reference
(99.1) Conference Call Summary dated February 15, 2002. p. 3 - 10
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
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Registrant
DATE: February 19, 2002 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 Company Conference Call Summary
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2001 Fourth Quarter, Year-End Results Conference Call
Friday, February 15, 2002
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 Executive Vice President of our Exploration and Production company and Greg
Kerley, our Chief Financial Officer. After some preliminary comments, I'll turn
the floor over to Richard for an update on our operations in E&P 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
year-end results, you can call Carol 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 that are detailed in the
Company's Securities and Exchange Commission filings. While we believe they are
reasonable representations of the Company's expected performance, actual results
could differ materially.
First of all, I'm happy and proud to report on the successful year we had in
2001. Our outstanding drilling results generated double-digit production growth
and 224% reserve replacement at a finding cost for the capital invested during
the year of $1.11 per Mcfe. Financially, we had a tremendous year as well, and
posted the highest level of earnings and cash flow in the Company's history.
These are great results, but the real driver behind our performance in 2001 and
for the last three years, for that matter, is having the right team of people in
place and creating an environment that fosters the generation of ideas. Our
overall Company strategy emphasizes the balance of risk in our capital program.
The combination of the dependability of the cash flow and earnings from the gas
distribution business and our low-risk drilling projects in the Arkoma Basin and
East Texas allow us to take a swing at the fence in South Louisiana exploration
projects. We like the mix of this activity and will continue to exploit our
competitive advantage in these strategy areas.
I believe that our performance is starting to stand out and investors have
started to look at us as a Company that is different from the pack due to our
focus on present value added per dollar invested. Although we're entering 2002
with uncertain product prices, we have the ability to flex our capital program.
We will continue to build on the base that we've established over the past three
years. Now I'd like to turn the teleconference over to Richard for an update on
the E&P operations.
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Southwestern Energy Company 2001 Fourth Quarter Results Conference Call
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Lane:
Thank you, Harold. 2001 was a very successful year for the Company's E&P
segment. We were able to replace 224% of our production with over 89 Bcfe of new
reserve additions, derived almost entirely through our drilling program.
Production for the full year was 39.8 Bcfe, an 11% increase over the 35.7 Bcfe
produced in the year 2000. Production was 10.5 Bcfe for the fourth quarter, up
from 9.1 Bcfe for that same period in 2000. In total, we participated in 101
wells in 2001, of which 80 were successful. We maintained our risk-balanced
drilling approach in 2001 by continuing to focus in our core areas: the Arkoma
Basin; Permian Basin; South Louisiana; and East Texas. We achieved a
Company-wide finding and development cost of $1.11 per Mcfe, exclusive of
revisions.
In the Arkoma Basin, we had an 81% success rate with 42 producers out of the 52
wells drilled. We achieved strong drilling results in both the Fairway area in
Arkansas, as well as on the Oklahoma side of the basin. For one project, our
Haileyville area delivered particularly outstanding results, with six of ten
wells completed and net production rates reaching a high of 15 million cubic
feet per day in July. Additionally in the Arkoma Basin, our workover program for
2001 grew into a significant part of our strategy. We completed 55 workovers,
which added 4.4 million cubic feet a day of net production at a net cost of $1.4
million. In 2001, we also built an inventory of projects that we have already
begun to develop in 2002.
In the Permian Basin, we drilled 26 wells and completed 19 of them, including a
discovery at our Cowden Ranch, where we have additional development plans for
this year. We continue to pursue our joint venture acreage in the basin, which
provides us low cost access to exploration lands. Although we have grown our
proven reserve base significantly in the Permian Basin over the last four years,
our finding costs have increased. In light of the decreased capital plan we have
for 2002, we will be reducing our investing in this area.
At our Overton Field, in Smith County, Texas, we had 15 successful wells out of
15 drilled in 2001. As a result of our drilling program, we have increased the
field's gross production to approximately 16 million cubic feet per day. Our
engineering and drilling efficiencies in the field have allowed us to reduce the
days required to drill and complete an Overton well to approximately 30 days,
and this represents a 25% reduction in drilling time.
Moving to South Louisiana, we continued to achieve significant exploration
success. In 2001, we had three discoveries at our Malone, Horeb and Crowne
prospects. These discoveries bring our total successful well count to six out of
the last nine exploratory wells drilled, and eight out of the last 11
exploration and development wells overall. We recently reached TD and completed
the Norman Breaux #1 well, which is the development well on our North Grosbec
discovery. After overcoming significant mechanical problems and cost overruns
during the drilling of this well, the Norman Breaux was online and producing at
approximately 20 million cubic feet per day and 800 barrels of condensate. Our
discovery well, the Brownell Kidd #1, continues to be a high deliverability
well, currently producing 16 million cubic feet per day and 580 barrels of oil
per day.
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At our last teleconference in late October, we had just spud our Crowne prospect
in Cameron Parish. We announced in December that the Miami Corporation #27-1,
which is the test well for the prospect, encountered 75 feet of pay in the
targeted Planulina objective section. We anticipate first production within 30
days for this well. Also on the Crowne prospect, a development well, the Miami
Corporation #34-2 has been spud and should reach total depth in March.
Southwestern operates the Crowne project and we have a 40% working interest in
both of these wells.
Additionally, at our last teleconference, I discussed that we had made a
discovery at our Horeb prospect in Acadia Parish. Since that time, we have
placed the Mire #1 well on production and it is currently producing 12.6 million
cubic feet per day and 159 barrels of oil per day. We operate this well, as
well, and have a 21.5% working interest.
In summary, we are very pleased with the results of our 2001 program. Across the
board, we achieved strong operating results with excellent finding and
development costs, high reserve replacement ratios and significant production
increases through drilling. Additionally, although we started the year with
higher lifting costs per unit of production, we've made progress driving those
costs down during the year. Our strategy of risk balanced drilling is working
and allowing us to create value. I'll now turn the teleconference over to Greg
Kerley, who will discuss the Company's financials.
Kerley:
Thank you, Richard, and good morning. In 2001, we set new records for net
income and cash flow. For the year, we reported net income of $35.3 million or
$1.38 per share, up over 70% from the $20.5 million or 82 cents per share we
reported in 2000, before unusual items. Cash flow from operating activities
before changes in working capital rose 37% to $112.7 million during 2001, up
from $82.4 million in 2000, excluding unusual items. Growth in production
volumes and higher gas prices led to the record financial results.
For the fourth quarter of 2001, we reported net income of $7.4 million or $.29
per share, compared to $9.1 million or $.36 per share for the same period last
year. Cash flow from operating activities was $26.3 million during the fourth
quarter, slightly lower than the $27.7 million from the fourth quarter of 2000.
Lower operating income from the Company's utility system due to warm weather and
higher depreciation and depletion expense led to the drop in earnings in the
fourth quarter. Operating income in 2001 from our E&P segment increased 70% to
$69.3 million, due to the record production levels that Richard discussed, and
higher realized gas prices.
In 2001 we realized an average gas price of $3.85 per Mcf, including the affect
of our hedges, up from $2.88 in 2000. To limit the impact of declining oil and
gas prices on our cash flow, we've hedged about 50 percent of our expected 2002
oil and gas production. The Company has 19 Bcf hedged in 2002, at a weighted
average NYMEX price of $3.23 per Mcf, and approximately 280,000 barrels of oil
hedged at about $20 a barrel.
Our production and operating expenses for the E&P segment, while still some of
the lowest in the industry, rose during 2001 due to increases in service costs
and the increased level of
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workovers that Richard discussed that we made to take advantage of the higher
commodity prices. Lifting costs on an equivalent unit of production basis were
45 cents per Mcf in 2001, compared to 40 cents last year. Depreciation,
depletion and amortization expense for the E&P segment was also up in 2001 due
to higher production volumes and a higher amortization rate. The amortization
rate for the full cost pool in 2001 averaged $1.14 per Mcf, as compared to the
prior year rate of $1.06.
Operating income for our gas distribution segment was $10.3 million in 2001,
down from $12.6 million in 2000, excluding income from our Missouri utility
properties that were sold in May of 2000. The lower results were due to
significantly warmer weather experienced during the fourth quarter of 2001 and
increased bad debt expense caused by higher natural gas prices. Finally, our
energy marketing efforts provided about $2.7 million of additional operating
income in 2001, compared to $2.5 million in 2000.
Our strong financial results also allowed us to reduce our long-term debt by $46
million during the year. Our debt continues to carry a favorable interest rate,
which currently averages about 5.8%. At year-end, our capital structure was
about 66% debt-to-total capital, down from 74% debt-to-total capital at the end
of 2000. Our capital investments totaled $106 million during 2001, with our
E&P segment accounting for $99 million of that amount. Our minority interest
partner in Overton funded $13.5 million of our Exploration and Production
expenditures in 2001.
As we announced in our press release yesterday, we are revising our guidance
regarding our capital investment program and production outlook for 2002. As a
result of current lower natural gas prices, we reduced our E&P capital
investment program by $9 million, bringing the total planned capital investments
in Exploration and Production down to $61 million, compared to the $70 million
previously announced on December 21st. As a result of the reduced expenditures,
we are lowering our production target in 2002 to a range of 41.5 to 42.5 Bcfe,
down from our previous guidance of 43 to 44 Bcfe. That concludes my comments.
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. Would you give me the split of reserves in East Texas and then the
Permian Basin?
Lane: At year-end, of the 402 Bcf that we have as a Company, Overton is about
55 to 60 Bcf of that total; the Arkoma is about 186 Bcf of that total;
and the Permian is about 60 Bcf of that total.
2. How much was booked at Overton when you purchased it?
Korell: 7.5 Bcfe in 2000.
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3. I know you've already hedged 9.2 Bcf of gas in 2003. Have you
subsequently hedged any more in 2003?
Kerley: No, we haven't. The only changes that we've had to our hedge position
we discussed in our press release. We did put the 280,000 barrels of
oil hedge in place for 2002. We haven't changed any position in 2003 at
all, so we still have the same position there.
4. Your decreased budget for 2002, if I read the press release correctly,
is targeting Arkoma and East Texas where the decline will be. Why are
you targeting those two areas for the decline?
Lane: We're looking at a number of variables when we try to re-shape that.
What we have to look at is where do we have lost opportunity and where
do we control the projects, that if we don't do them, they're still
there for us at another day. We try to shape that all up and get the
best program out of it. We have about $4 million lower than previously
talked about for the Arkoma. We participate in a lot of non-operated
wells and we think that will be off a little. So there will be a
natural decline in that part of our investing there. At Overton, about
$5 million less than we previously talked about. Again, that's an asset
that we control. We don't have to do those and we can still maintain
our position out there.
5. So a lot of it has to do with lease requirements and just whether you
control it or not?
Lane: Yes. That's one significant part of it.
6. Are you planning a partnership similar to the one you had over the past
year or so in Overton for 2002 and 2003?
Lane: We haven't looked at anything out into 2003. We have had some
discussions for this year and we're not certain where that will turn
out right now.
7. G&A seemed to go up some in the fourth quarter. Can you give some color
on that? I know it's choppy, quarter to quarter.
Kerley: Yes, it typically is. It was up about $.5 million dollars in the fourth
quarter. I would say that a good part of that probably is related to
some of the balance of write-offs in the utility and their increased
expenses for the year. Things that are choppy year-to-year. So there's
nothing significant there.
8. Many companies are reporting very high finding costs, so your $1.11 is
indeed impressive in comparison. Hopefully, you can give us some sort
of range of estimates of finding costs in the various regions,
particularly in South Louisiana. As you know, Gulf Coast drilling, and
offshore drilling is much more expensive, and that's where we're seeing
the costs rise pretty dramatically. Your great spate of success, it
looks like, is in South Louisiana. Can you give us guidance of the
finding costs there, and how you're able to achieve the string of
successes?
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Lane: If you look at three-year numbers, which might be more meaningful, in
the Arkoma Basin, we've achieved about a $1.05 per Mcfe over that
period. In the Permian Basin, about $1.33 per Mcfe and in Louisiana,
$1.65 per Mcfe, all costs considered. That's a three-year breakout of
that.
9. Looking forward to your exploration slate in Louisiana, could you focus
or articulate where you think the key projects are, that we should be
watching the reserve potential in those areas?
Lane: The Gulf Coast remains our highest potential area, in particular, in
Louisiana. We plan to drill five to six wells in that area this year.
One development well, and the rest plan to be exploratory wells. The
Crowne well I mentioned that is currently drilling, is an important
well for us to further develop that discovery. A series of other
exploration wells in South Louisiana will take us through the year.
10. We'd like to gain a sense of future inventory for East Texas. I know
there's some down-spacing issues there. Could you bring us up to date
on the down spacing and what type of potential locations you would
receive because of that?
Lane: Sure, on finding costs, I would just add that we didn't discuss Overton
because we were talking about three-year numbers. But if you look at a
one-year number, we're down around $.80 per Mcfe for that property. So,
that helps significantly there. In terms of the future development of
the field would be the ability to drill the field down to certainly
160-acre spacing. All of our data says that 80-acre spacing is
achievable also. But on 160-acre spacing basis, which we have the
regulatory issues filed to be able to do that efficiently, we see
approximately another 30 wells just to get down to that 160-acre
spacing.
11. Isn't there some sort of south acreage that you've farmed into at
Overton?
Lane: Yes, there's about six thousand acres south of Overton Field, I believe
it's 5,800 acres that we call our MAP acreage or South Overton area. We
have additional development potential down there, as well.
12. If I look at your revised capital, just under $70 million and if you
look at very low gas prices -- you'll get cash flow above that. Is the
thought to try to reduce that by a certain dollar amount? Is that
what's driving Cap Ex coming down despite your cash flow being in
excess of $70 or $80 million on $2.25 - $2.50 gas?
Korell: The capital program that we've planned right now is conservatively
natured. As you look at the forward strip, you see a price that's maybe
more in the $2.40 to $2.50 per Mcf range. We made the decision to plan
our capital program around a $2.25 NYMEX price, basically. We decided,
at the outset here, to plan for a reduced program with the assumption
that we might see lower gas prices, but knowing that we could flex our
program up if we want to. The flex in our
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program pretty much is that we can choose when to drill Overton. One
might ask why be aggressively drilling out there while prices are low
if those wells come on at fairly high rates in their first year. So we
control that. We're seeing less AFE's from outside parties in the
Arkoma Basin. If we're not getting the normal stream of AFE's from our
partners in the Arkoma, then we won't be spending those dollars.
Then, in South Louisiana, as you know, when you've made the investments
in 3-D seismic, you've traded positions, you have lease options, you
have programs that are ongoing. We have an additional 3-D project
that's ongoing there. All these things have time clocks that are
running on them. The economics are still very good if we continue to
have the kind of success we've had in South Louisiana, or even less
successful than we've had, would still be good.
So we want to keep that going. It's our view that, hopefully, we'll see
prices strengthening later in the year or into next year. I think the
way we've got this plan put together we'll get a combination of us
coming out of the year at some pretty high producing rates, hopefully,
to take advantage of higher prices, then take a whack at paying down
more debt again.
13. What I'm getting at is whether Greg has your arm twisted, and Richard's
arm twisted in paying down a certain dollar amount, or is it more just
play it by ear and let's see what gas prices do during the course of
the year?
Korell: Well, it's the latter and I think it is just the way we ought to play
the game. We've got inventory we could drill, certainly. But why should
we extend ourselves not knowing where prices are going to be? We need
to be careful that we match our program up with our cash flow and not
be incurring more debt.
14. Obviously you had some downward reserve revisions because of prices.
Could you tell us what areas those were from, primarily? What prices
were used to determine this? And I guess it's the same as your PV-10.
And finally, what are the development costs in your reserve report
required to fully develop your reserve base?
Lane: The year-end price that we utilized for 2001 was $2.65 per Mcf for gas
and $19.84 per barrel for oil. We had downward revisions of about 27 to
28 Bcfe, mostly attributable to price. About half of that price
revision was from the Arkoma and the rest spread between our other
areas. In terms of future required development capital that we have
recorded, that amount is about $57 million.
15. Can you give us any color as to whether you've had conversations with
the rating agencies? We've had certainly an excellent year. Our total
debt we're paying, as Greg said, about 5.8%. There's really not any
urgency to pay down much more debt. But I'm curious as to whether or
not the rating agencies have paid attention to what we've done in the
last year and where we stand.
Kerley: We do stay in contact with the rating agencies, typically
quarterly. We also meet with them annually and present a presentation
and plan where we go into a lot of detail about our next
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12 months and where we see things beyond that. One thing that has
helped us significantly in the last several years, is we've done what
we told the rating agencies we were going to do. And exactly what we
ended up this year is really well within the parameters of what we
told them our expectations were. I think they'll be very pleased.
They've indicated that as we've gone along through the year.
We haven't had any recent discussions with them except that I think
that with some of the things that have been going on with Enron, etc.,
they sent out some basic surveys to all companies regarding if they had
any triggers in their debt instruments that caused immediate payment or
anything else. We don't have any of those. We just responded, as I'm
sure all the rest of the inquiries that they had, I think they sent
almost three thousand inquiries, probably just a blanket inquiry. We
have, I think, good relationships with them. They want to know what's
going on all the time. We try to keep them up to date.
16. In Harold's opening statements, he implied the status quo on the
utility side. Certainly the utility has helped us with our cash flow.
Can I take it to mean that the utility is not being actively marketed
at this time?
Kerley: That's correct. We're still exactly where we were a full year ago,
when we made the decision to pull the utility off the market
because of the hedge position that we put in place more than a year and
a half ago. It put us in a position to get our capital structure
started back well on a road of significant improvement. There are a lot
of benefits that the utility provides to us as we talked about in the
past, that helps us significantly in our debt position. The utility
also adds a continuing stable base of our cash flow and earnings, that
I think the market looks at, especially in the time that we're in right
now -- a downturn in prices, compared to what they've been. Although
these are still pretty attractive prices historically. It's a plus for
us and we can plan to continue to operate it.
Kerley: This is Greg Kerley, again. Thank you for joining us and please feel
free to call me with any questions you may have or other information.
This concludes our teleconference.
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Southwestern Energy Company
P.O. Box 1408
Fayetteville, AR 72702-1408
February 19, 2002
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
February 15, 2002.
This filing is being effected by direct transmission to the Commission's EDGAR
System.
Very truly yours,
Stan Wilson
Controller