<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------------
FORM 10-Q
(Mark one)
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 2000
------------------
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _______ to _______
Commission file number 1-8246
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas 71-0205415
(State of incorporation (I.R.S. Employer
or organization) Identification No.)
1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas 72702-1408
(Address of principal executive offices, including zip code)
(501) 521-1141
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year; if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding twelve months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes: X No:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding at November 1, 2000
---------------------------- -------------------------------
Common Stock, Par Value $.10 25,033,381
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<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- ------------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 727 $ 1,240
Accounts receivable 40,635 43,339
Inventories, at average cost 19,610 21,520
Under-recovered purchased gas costs 6,862 -
Other 3,080 4,073
--------- ---------
Total current assets 70,914 70,172
--------- ---------
Investments 14,201 14,180
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 856,270 816,199
Gas distribution systems 189,496 222,145
Gas in underground storage 30,884 28,712
Other 29,236 28,826
--------- ---------
1,105,886 1,095,882
Less: Accumulated depreciation,
depletion and amortization 544,704 519,927
--------- ---------
561,182 575,955
--------- ---------
Other Assets 12,610 11,139
--------- ---------
Total Assets $ 658,907 $ 671,446
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- ------------
($ in thousands)
<S> <C> <C>
Current Liabilities
Short-term debt $ 151,300 $ 7,500
Accounts payable 35,834 33,069
Taxes payable 2,462 3,506
Interest payable 7,086 2,483
Customer deposits 4,829 6,021
Other 6,325 3,767
--------- ---------
Total current liabilities 207,836 56,346
--------- ---------
Long-Term Debt, less current portion above 225,000 294,700
--------- ---------
Other Liabilities
Deferred income taxes 91,260 126,902
Other 2,772 3,142
--------- ---------
94,032 130,044
--------- ---------
Commitments and Contingencies
Shareholders' Equity
Common stock, $.10 par value; authorized
75,000,000 shares, issued 27,738,084
shares 2,774 2,774
Additional paid-in capital 20,749 20,732
Retained earnings 139,272 198,044
Less: Common stock in treasury, at cost,
2,704,143 shares in 2000 and
2,700,391 shares in 1999 30,125 30,083
Unamortized cost of 130,991
restricted shares in 2000
and 188,781 restricted shares
in 1999, issued under stock
incentive plan 631 1,111
--------- ---------
132,039 190,356
--------- ---------
Total Liabilities and Shareholders' Equity $ 658,907 $ 671,446
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues
Gas sales $ 32,421 $ 28,238 $ 130,399 $ 119,892
Gas marketing 38,109 27,915 103,497 62,720
Oil sales 3,683 2,556 11,060 6,529
Gas transportation and other 1,129 1,691 5,782 5,518
---------- ---------- ---------- ----------
75,342 60,400 250,738 194,659
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gas purchases - utility 3,275 5,994 30,501 34,068
Gas purchases - marketing 37,187 27,079 100,306 59,752
Operating expenses 8,238 8,123 25,580 24,888
General and administrative expenses 5,217 5,731 17,907 17,208
Unusual items 2,000 - 111,288 -
Depreciation, depletion and amortization 11,627 10,133 33,969 30,826
Taxes, other than income taxes 1,914 1,676 6,096 4,783
---------- ---------- ---------- ----------
69,458 58,736 325,647 171,525
---------- ---------- ---------- ----------
Operating Income (Loss) 5,884 1,664 (74,909) 23,134
---------- ---------- ---------- ----------
Interest Expense
Interest on long-term debt 7,039 4,916 17,184 14,429
Other interest charges 212 252 1,317 793
Interest capitalized (548) (814) (1,868) (2,480)
---------- ---------- ---------- ----------
6,703 4,354 16,633 12,742
---------- ---------- ---------- ----------
Other Income (Expense) (417) (482) 1,581 (1,387)
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes (1,236) (3,172) (89,961) 9,005
---------- ---------- ---------- ----------
Income Tax Provision (Benefit)
Current - (4,402) - (3,652)
Deferred (482) 3,165 (35,084) 7,164
---------- ---------- ---------- ----------
(482) (1,237) (35,084) 3,512
---------- ---------- ---------- ----------
Income (Loss) Before Extraordinary Item (754) (1,935) (54,877) 5,493
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) - - (890) -
---------- ---------- ---------- ----------
Net Income (Loss) $ (754) $ (1,935) $ (55,767) $ 5,493
========== ========== ========== ==========
Basic and Diluted Earnings (Loss) Per Share
Income (Loss) Before Extraordinary Item ($0.03) ($0.08) ($2.19) $0.22
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) - - (0.04) -
---------- ---------- ---------- ----------
Net Income (Loss) ($0.03) ($0.08) ($2.23) $0.22
========== ========== ========== ==========
Basic and Diluted Average Common
Shares Outstanding 25,034,306 24,938,229 25,035,626 24,935,402
========== ========== ========== ==========
Dividends Declared Per Share Payable 11/5/99 - $ .06 - $0.06
========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
--------------------
2000 1999
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income (loss) $(55,767) $ 5,493
Adjustments to reconcile net income (loss) to
net cash provided by (used in) operating
activities:
Depreciation, depletion and amortization 35,010 31,850
Deferred income taxes (35,084) 7,164
Equity in loss of partnership 1,510 1,620
Gain on sale of Missouri utility assets (3,209) -
Extraordinary loss due to early retirement
of debt (net of tax) 890 -
Change in assets and liabilities:
(Increase) decrease in accounts receivable (287) 12,173
Increase in inventories (319) (4,297)
Increase in under-recovered purchased
gas costs (8,025) (3,704)
Increase (decrease) in accounts payable 3,686 (1,020)
Increase in interest payable 4,613 4,546
Net change in other current assets
and liabilities 3,978 (3,633)
-------- --------
Net cash provided by (used in) operating activities (53,004) 50,192
-------- --------
Cash Flows From Investing Activities
Capital expenditures (57,422) (49,482)
Sale of Missouri utility assets 32,000 -
Sale of oil and gas properties 13,651 -
Investment in partnership (1,620) -
(Increase) decrease in gas stored underground (2,172) 621
Other items (132) 2,395
-------- --------
Net cash used in investing activities (15,695) (46,466)
-------- --------
Cash Flows From Financing Activities
Net change in revolving debt 103,600 700
Retirement of private placement notes and
prepayment penalty (24,910) -
Payment on revolving short-term note (7,500) -
Cash dividends (3,004) (4,488)
-------- --------
Net cash provided by (used in) financing activities 68,186 (3,788)
-------- --------
Decrease in cash (513) (62)
Cash at beginning of year 1,240 1,622
-------- --------
Cash at end of period $ 727 $ 1,560
======== ========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 6 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2000
1. BASIS OF PRESENTATION
The financial statements included herein are unaudited; however, such
information reflects all adjustments (consisting solely of normal
recurring adjustments) which are, in the opinion of management,
necessary for a fair presentation of the results for the interim
periods. The Company's accounting policies are summarized in the 1999
Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial
Statements.
2. EARNINGS PER SHARE
Basic earnings per common share is computed by dividing net income by
the weighted average number of common shares outstanding during each
year. The diluted earnings per share calculation adds to the weighted
average number of common shares outstanding the incremental shares that
would have been outstanding assuming the exercise of dilutive stock
options. The Company had options for 2,033,665 shares of common stock
with a weighted average exercise price of $10.53 per share at September
30, 2000, and options for 1,574,815 shares with an average exercise
price of $12.02 per share at September 30, 1999, that were not included
in the calculation of diluted shares because they would have had an
antidilutive effect.
3. UNUSUAL ITEMS
The Company incurred an unusual charge of $2.0 million related to
litigation in the third quarter of 2000. Additionally, in the second
quarter of 2000, the Company reported that the Arkansas Supreme Court
ruled to affirm the 1998 decision of the Sebastian County Circuit Court
awarding $109.3 million in a class action to royalty owners of SEECO,
Inc., a wholly-owned subsidiary of Southwestern Energy Company. The
Company has continuously reported on this matter and the details of the
related matter involving a similar claim by the United States Mineral
Management Service (MMS). The Company fully satisfied the judgment and
the Circuit Court in Sebastian County issued an order in complete
satisfaction of the judgment effective July 18, 2000. Since MMS is a
member of the class whose claim was satisfied by the Court's order on
July 18, 2000, the MMS claim is also extinguished. The Company has put
in place interim financing with its lead banks to satisfy the judgment
and meet its immediate financial obligations (see Note 4).
The Company is currently in the process of soliciting interest for the
sale of its gas distribution assets. The proceeds from the proposed
sale will be used to pay down borrowings, including borrowings incurred
related to the Hales judgment. The Company is currently unable to
estimate the timing of the completion of the proposed sale and can not
at this time estimate the proceeds that would be realized from such a
sale.
- 7 -
<PAGE>
4. DEBT
In July 2000, the Company replaced its existing revolving credit
facilities with a new revolving credit facility that has a capacity of
$180.0 million. This new facility was used to fund the Hales judgment
of $109.3 million, pay off the existing revolver balance, and retire
$22.0 million of private placement debt. The new credit facility is
also being used to fund normal working capital needs. The interest rate
on the new facility is 112.5 basis points over the LIBOR rate. The new
credit facility has a term of 364 days and will provide temporary
financing while the Company pursues the proposed sale of its gas
distribution assets (see Note 3).
In August 2000, the Company retired $22.0 million of 9.36% private
placement notes. Certain costs of the redemption were expensed during
the second quarter of 2000 and are classified as an extraordinary loss,
net of related income tax effects, in the accompanying financial
statements.
5. DIVIDEND PAYABLE
As a result of the financial impact of the Hales judgment as discussed
in Note 3, the Company has indefinitely suspended payment of quarterly
dividends on its common stock.
6. SEGMENT INFORMATION
The Company applies SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." The Company's reportable business
segments have been identified based on the differences in products or
services provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and crude oil.
Revenues for the gas distribution segment arise from the transportation
and sale of natural gas at retail. The marketing segment generates
revenue through the marketing of both Company and third party produced
gas volumes.
Summarized financial information for the Company's reportable segments
are shown in the following table. The "Other" column includes items
related to non-reportable segments (real estate and pipeline
operations) and corporate items.
<TABLE>
<CAPTION>
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- --------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C>
Three months ended September 30, 2000:
Revenues from external customers $ 21,180 $ 16,052 $ 38,110 $ - $ 75,342
Intersegment revenues 5,337 29 20,796 112 26,274
Depreciation, depletion and
amortization expense 10,092 1,494 18 23 11,627
Operating income 7,166(3) (1,745) 464 (1) 5,884
Interest expense(1) 5,570 859 - 274 6,703
Provision (benefit) for income taxes(1) 638 (1,008) 176 (288) (482)
Assets 452,167 154,716 18,674 33,350(2) 658,907
Capital expenditures 12,497 1,351 - 170 14,018
Three months ended September 30, 1999:
- 8 -
<PAGE>
Revenues from external customers $ 13,074 $ 19,411 $ 27,915 $ - $ 60,400
Intersegment revenues 3,782 59 11,423 112 15,376
Depreciation, depletion and
amortization expense 8,344 1,749 18 22 10,133
Operating income 2,667 (1,542) 469 70 1,664
Interest expense (1) 2,827 1,255 (15) 287 4,354
Provision (benefit) for income taxes(1) (84) (1,119) 189 (223) (1,237)
Assets 428,408 177,297 13,669 38,965(2) 658,339
Capital expenditures 19,398 1,536 - 14 20,948
Nine months ended September 30, 2000:
Revenues from external customers $ 54,694 $ 92,546 $ 103,498 $ - $ 250,738
Intersegment revenues 21,369 110 49,449 335 71,263
Depreciation, depletion and
amortization expense 28,854 4,991 53 71 33,969
Operating income (85,806)(3) 8,933 2,001 (37) (74,909)
Interest expense(1) 12,436 3,386 - 811 16,633
Provision (benefit) for income taxes(1) (38,553) 3,351 781 (663) (35,084)
Assets 452,167 154,716 18,674 33,350(2) 658,907
Capital expenditures 53,014 4,003 4 401 57,422
Nine months ended September 30, 1999:
Revenues from external customers $ 37,937 $ 94,002 $ 62,720 $ - $ 194,659
Intersegment revenues 15,337 131 29,770 304 45,542
Depreciation, depletion and
amortization expense 25,365 5,340 54 67 30,826
Operating income 10,260 10,785 1,924 165 23,134
Interest expense(1) 8,271 3,764 (3) 710 12,742
Provision (benefit) for income taxes(1) 707 2,679 752 (626) 3,512
Assets 428,408 177,297 13,669 38,965(2) 658,339
Capital expenditures 44,615 4,721 8 138 49,482
</TABLE>
[FN]
(1) Interest expense and the provision (benefit) for income taxes by
segment is an allocation of corporate amounts as debt and income
tax expense (benefit) are incurred at the corporate level.
(2) Other assets includes the Company's equity investment in the
operations of the NOARK Pipeline System, Limited Partnership,
corporate assets not allocated to segments, and assets for
non-reportable segments.
(3) Includes an unusual charge of $2.0 million related to litigation
recorded in the third quarter of 2000 and a loss of $109.3 million
for Hales judgment recorded in the second quarter of 2000.
Excluding these unusual items, operating income for the
Exploration and Production segment would have been $9.2 million
and $25.5 million for the three and nine months ended September
30, 2000, respectively.
</FN>
Intersegment sales by the exploration and production segment and
marketing segment to the gas distribution segment are priced in
accordance with terms of existing contracts and current market
conditions. Parent company assets include furniture and fixtures,
prepaid debt costs and prepaid pension costs. Parent company general
and administrative costs, depreciation expense and taxes other than
income are allocated to segments. All of the Company's operations are
located within the United States.
7. DERIVATIVE AND HEDGING ACTIVITIES
In June 1999, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" (SFAS No. 137). FASB
Statement No. 133 (SFAS No. 133) establishes accounting and reporting
- 9 -
<PAGE>
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the
balance sheet as either an asset or liability measured at its fair
value. SFAS No. 133 requires that changes in the derivative's fair
value be recognized currently in earnings unless specific hedge
accounting criteria are met. Special accounting for qualifying hedges
allows a derivative's gains and losses to offset related results on the
hedged item in the income statement, and requires that a company
formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133 is effective
for fiscal years beginning after June 15, 2000, as amended in SFAS 137,
and cannot be applied retroactively.
In June 2000, the FASB issued SFAS No. 138, an amendment of SFAS 133,
to address a limited number of application issues. Included in the
issues addressed was an expanded definition of normal purchases and
sales contracts. The new definition allows contracts that are probable
of physical delivery throughout the duration of the contract to be
excluded from the provisions of SFAS 133 even though they may contain
net settlement provisions. This amendment reduces the scope of SFAS No.
133 as it applies to the Company's operations.
The Company has not yet quantified the impacts of adopting SFAS No. 133
on its financial statements. However, it should be noted that SFAS No.
133 is expected to increase volatility in future reported earnings and
other comprehensive income. The Company has completed its review of
existing contracts for embedded derivatives and has found none. The
Company is currently completing its inventory of purchase and sale
contracts as required under the provisions of SFAS No. 138. All
contracts inventoried to date qualify under the normal purchase and
sale provision of SFAS No. 138 as physical delivery is expected to
occur.
8. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
<TABLE>
<CAPTION>
Three Months Nine Months
Periods Ended September 30 2000 1999 2000 1999
-----------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Interest payments $2,323 $322 $12,394 $9,746
Income tax payments $206 $ - $206 $641
</TABLE>
9. Contingencies and Commitments
In the Company's Form 8-K filed July 2, 1996, it previously disclosed
that a lawsuit relating to overriding royalty interests in certain
Arkansas oil and gas properties had been filed. The Company also
reported in its second quarter 2000 Form 10-Q that this matter had gone
to a non-jury trial as to liability in January 2000 and that the
Company was awaiting the court's findings. The court in this matter has
issued Findings of Fact and Conclusions of Law that find no fraud was
committed. The court also finds that any override royalty interests
that may ultimately be found to be subject to the plaintiff's claim for
additional override royalties accrued after March 1, 1990. All claims
prior to March
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<PAGE>
1, 1990 have been barred by the statute of limitations. The ultimate
measure of damages will be determined during the damages phase of the
non-jury proceedings that is scheduled to occur during the first
quarter of 2001. While the Company anticipates that it will owe some
additional override royalties to plaintiffs, it does not believe that
its liability will be material to its financial condition, but in any
one period it could be significant to its results of operations.
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on NOARK's 7.15% Notes
due 2018. At September 30, 2000 and December 31, 1999, the principal
outstanding for these Notes was $76.0 million and $77.0 million,
respectively. The Company's share of the several guarantee is 60%. The
Notes were issued in June 1998 and require semi-annual principal
payments of $1.0 million. The proceeds from the issuance of the Notes
were used to repay temporary financing provided by the other general
partner and outstanding amounts under an unsecured revolving credit
agreement. The temporary financing provided by the other general
partner was incurred in connection with the prepayment in early 1998 of
NOARK's 9.74% Senior Secured notes. Under the several guarantee, the
Company is required to fund its share of NOARK's debt service which is
not funded by operations of the pipeline. As a result of the
integration of NOARK Pipeline with the Ozark Gas Transmission System,
management of the Company believes that it will realize its investment
in NOARK over the life of the system. Therefore, no provision for any
loss has been made in the accompanying financial statements.
Additionally, the Company's gas distribution subsidiary has
transportation contracts for firm capacity of 82.3 MMcfd on NOARK's
integrated pipeline system. These contracts expire in 2002 and 2003,
and are renewable year-to-year thereafter until terminated by 180 days'
notice.
The Company is subject to laws and regulations relating to the
protection of the environment. The Company's policy is to accrue
environmental and cleanup related costs of a noncapital nature when it
is both probable that a liability has been incurred and when the amount
can be reasonably estimated. Management believes any future remediation
or other compliance related costs will not have a material effect on
the financial position or reported results of operations of the
Company.
The Company is subject to other litigation and claims that have arisen
in the ordinary course of business. The Company accrues for such items
when a liability is both probable and the amount can be reasonably
estimated. In the opinion of management, the results of such litigation
and claims will not have a material effect on the results of operations
or the financial position of the Company.
- 11 -
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to the Company's financial condition
provided in the Company's Form 10-K for the year ended December 31, 1999, and
analyzes the changes in the results of operations between the three and nine
month periods ended September 30, 2000, and the comparable periods of 1999.
RESULTS OF OPERATIONS
The Company reported a net loss for the three months ended September 30, 2000 of
$.8 million, or $.03 per share, compared to a net loss of $1.9 million, or $.08
per share, in 1999. Third quarter 2000 results included an unusual charge of
$2.0 million related to litigation against the Company. Excluding this unusual
charge, net income during the third quarter of 2000 would have been $0.5
million, or $.02 per share.
For the nine months ended September 30, 2000, the Company reported a net loss of
$55.8 million, or $2.23 per share, compared to net income of $5.5 million, or
$.22 per share for the same period in 1999. One-time charges during the nine
months ended September 30, 2000 included a negative $109.3 million judgment in
the Hales lawsuit ($66.7 million after-tax), an extraordinary loss on the early
retirement of debt, a $3.2 million gain from the sale of the Company's Missouri
utility properties, and a $2.0 million charge in the third quarter related to
litigation. Excluding these items, Southwestern would have reported net income
of $11.1 million, or $.44 per share, for the first nine months of 2000.
Exploration and Production
Overview
The Company's exploration and production segment's revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, which are dependent upon numerous factors beyond its
control, such as economic, political and regulatory developments and competition
from other sources of energy. The energy markets have historically been very
volatile, and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future.
<TABLE>
<CAPTION>
Three Months Nine Months
------------ -----------
2000 1999 2000 1999
--------------------- -----------------------
<S> <C> <C> <C> <C>
Revenues (in thousands) $ 26,517 $ 16,856 $ 76,063 $ 53,274
Operating income (loss) (in thousands) $ 7,166(1) $ 2,667 $ (85,806)(1) $ 10,260
Gas production (Bcf) 7.9 7.2 23.6 22.1
Oil production (MBbls) 171.0 133.0 495.0 423.0
- 12 -
<PAGE>
Total production (Bcfe) 9.0 8.0 26.6 24.6
Average gas price per Mcf $2.87 $1.99 $2.71 $2.13
Average oil price per Bbl $21.56 $19.21 $22.36 $15.44
Operating expenses per Mcfe
Production expenses $0.40 $0.34 $0.38 $0.34
Production taxes $0.15 $0.11 $0.14 $0.09
General & administrative expenses $0.26 $0.29 $0.29 $0.29
Full cost pool amortization $1.09 $1.01 $1.05 $1.00
</TABLE>
[FN]
(1) Includes an unusual charge of $2.0 million related to litigation recorded
in the third quarter of 2000 and a loss of $109.3 million for Hales
judgment recorded in the second quarter of 2000. Excluding these unusual
items, operating income for the Exploration and Production segment would
have been $9.2 million and $25.5 million for the three and nine months
ended September 30, 2000, respectively.
</FN>
Revenues and Operating Income
Revenues for the exploration and production segment were up 57% for the three
month period ended September 30, 2000 and up 43% for the nine month period ended
September 30, 2000, both as compared to the same periods in 1999. The increases
were due to both higher gas and oil prices and increased gas and oil production.
Operating income for the exploration and production segment was up $4.5 million
for the three months ended September 30, 2000, and, excluding the $111.3 of
unusual items, up $15.2 million for the nine months ended September 30, 2000
both as compared to the same periods in 1999. The improvements in operating
income were due to higher prices received and increased production.
Production
Gas and oil production during the third quarter of 2000 was 9.0 billion cubic
feet (Bcf) equivalent, up 13% from 8.0 Bcf equivalent for the same period in
1999. For the nine months ended September 30, 2000, gas and oil production was
26.6 Bcf equivalent, up 8% from 24.6 Bcf equivalent for the same period of 1999.
The increase in production resulted from new wells added in 1999 and 2000 in the
Company's Permian Basin and Gulf Coast operating areas. Gas production was 7.9
Bcf for the three months ended September 30, 2000, and 23.6 Bcf for the nine
months ended September 30, 2000, compared to 7.2 Bcf and 22.1 Bcf, respectively,
for the same periods in 1999. The Company's sales to its gas distribution
systems were 5.8 Bcf during the nine months ended September 30, 2000, compared
to 5.7 Bcf for the same period in 1999. The Company's oil production was 495
thousand barrels (MBbls) during the nine months ended September 30, 2000, up
from 423 MBbls for the same period of 1999.
During the third quarter of 2000, the Company sold at auction approximately 130
non-strategic Oklahoma properties located in the Anadarko Basin. These
properties produced approximately 1.5 Bcf equivalent per year and were sold for
approximately $12.3 million.
- 13 -
<PAGE>
Commodity Prices
The Company received an average price of $2.87 per thousand cubic feet (Mcf) for
its gas production for the three months ended September 30, 2000, up from $1.99
per Mcf for the same period of 1999. The Company received an average price of
$2.71 per Mcf for its gas production during the nine months ended September 30,
2000, up from $2.13 for the same period of 1999. The Company hedged 15.1 Bcf of
gas production in the first nine months of 2000 at $2.40 per Mcf which had the
effect of reducing the average gas price realized during the period by $.73 per
Mcf. On a comparative basis, the average price during the first nine months of
1999 included the negative effect of hedges that decreased the average price by
$.02 per Mcf. For the third quarter of 2000, hedges in place reduced the average
price realized by $1.36 per Mcf, compared to a negative effect of $.48 per Mcf
in the same period of 1999. Additionally, the Company receives monthly demand
charges related to the no-notice service it makes available to the utility
segment which increases the Company's average gas price received.
The Company has hedged 2.6 Bcf of gas production in the fourth quarter at an
average price of $2.38 per Mcf. Additionally, the Company has natural gas price
collars on 4.4 Bcf of its fourth quarter 2000 gas production that have an
average NYMEX price floor of $2.52 per Mcf and an average ceiling price of $3.62
per Mcf. For the year of 2001, the Company has 13.8 Bcf of gas production hedged
with collars having an average NYMEX floor price of $2.87 per Mcf and an average
NYMEX ceiling price of $3.73 per Mcf. The Company also has 1.2 Bcf of gas
production in 2001 hedged with fixed price swaps at an average NYMEX price of
$2.70 per Mcf.
The Company received an average price of $22.36 per barrel for its oil
production during the nine months ended September 30, 2000, up from $15.44 per
barrel for the same period of 1999. In the fourth quarter of 2000, the Company
has hedges in place for 159,000 barrels at an average price of $23.24 per
barrel. For 2001, the Company has a price floor of $18.00 per barrel on 325,000
barrels and a hedge on 72,000 barrels at an average NYMEX price of $17.49 per
barrel.
Operating Costs and Expenses
Operating costs and expenses for the exploration and production segment
increased in both the third quarter and the first nine months of 2000 due
primarily to higher production related expenses and increased depreciation,
depletion and amortization expense. The increase in operating and general
expenses was due to increased production volumes, a higher level of workover
expenses and increased severance and ad valorem taxes that resulted from both
increased production volumes and higher commodity prices. The Company is also
beginning to experience an inflationary increase in exploration and production
related costs due to an overall increase in the activity level of the domestic
oil and gas industry. The Company anticipates that these costs will continue to
increase in the near future. The increases in depreciation, depletion and
amortization expense were due to the increase in production and an increase in
the amortization rate per unit of production. The full cost pool amortization
rate for this segment averaged $1.05 per Mcf equivalent for the first nine
months of 2000, compared to $1.00 per Mcf equivalent in the first nine months of
1999.
The Company utilizes the full cost method of accounting for costs related to its
oil and natural gas properties. Under this method, all such costs (productive
and nonproductive) are capitalized and
- 14 -
<PAGE>
amortized on an aggregate basis over the estimated lives of the properties using
the units-of-production method. These capitalized costs are subject to a ceiling
test, however, which limits such pooled costs to the aggregate of the present
value of future net revenues attributable to proved gas and oil reserves
discounted at 10 percent plus the lower of cost or market value of unproved
properties. At September 30, 2000, the Company's unamortized costs of oil and
gas properties did not exceed this ceiling amount. The Company's full cost
ceiling is evaluated at the end of each quarter. A decline in gas and oil prices
from current levels, or other factors, without other mitigating circumstances,
could cause a future write-down of capitalized costs and a non-cash charge
against future earnings.
Gas Distribution
Overview
The operating results of the Company's gas distribution segment are highly
seasonal. This segment typically realizes operating losses in the second and
third quarters of the year and realizes operating income during the winter
heating season in the first and fourth quarters. The extent and duration of
heating weather also impacts the profitability of this segment, although the
Company has a weather normalization clause that lessens the impact of revenue
increases and decreases which might result from weather variations during the
winter heating season. The gas distribution segment's profitability is also
dependent upon the timing and amount of regulatory rate increases that are filed
with and approved by the Arkansas Public Service Commission. For periods
subsequent to allowed rate increases, the Company's profitability is impacted by
its ability to manage and control this segment's operating costs and expenses.
<TABLE>
<CAPTION>
Three Months Nine Months
---------------- ----------------
2000 1999 2000 1999
-------------------- --------------------
($ in thousands, except for Mcf amounts)
<S> <C> <C> <C> <C>
Revenues $ 16,081 $ 19,470 $ 92,656 $ 94,133
Gas purchases $ 8,611 $ 9,776 $ 51,869 $ 49,405
Operating costs and expenses $ 9,215 $ 11,236 $ 31,854 $ 33,943
Operating income (loss) $ (1,745) $ (1,542) $ 8,933 $ 10,785
Deliveries (Bcf)
Sales and end-use transportation 3.4 4.5 20.7 22.5
Off-system transportation 0.7 1.1 2.8 3.1
Average number of customers 131,082 174,448 159,109 177,067
Average sales rate per Mcf $8.40 $7.61 $6.18 $5.77
Heating weather - degree days 44 55 2,026 2,078
- percent of normal - - 81% 84%
</TABLE>
Note: Amounts and statistics for 1999 and the nine months ended September 30,
2000 include the operations of the Company's Missouri properties that
were sold in May 2000.
- 15 -
<PAGE>
On May 31, 2000, the Company completed the sale of its Missouri gas distribution
assets for $32.0 million. The sale resulted in a pre-tax gain of approximately
$3.2 million and proceeds from the sale were used to pay down debt. As a result
of the adverse Hales judgment, the Company's Board of Directors has authorized
management to pursue the sale of the Company's remaining gas distribution
operations. The Company is still in the process of soliciting interest for the
sale of its gas distribution assets. The proceeds from the proposed sale would
be used to pay down borrowings, including borrowings incurred related to the
Hales judgment. The Company is currently unable to estimate the timing of the
completion of the proposed sale and can not at this time estimate the proceeds
that would be realized from the sale.
Revenues and Operating Income
Revenues for the quarter and nine months ended September 30, 2000 are down from
the comparable periods of 1999 primarily due to the sale of Missouri assets, as
discussed above, partially offset by a higher average sales rate. The Company's
average rate for its utility sales increased during the first nine months of
2000 to $6.18 per Mcf, up from $5.77 per Mcf for the same period in 1999. The
increase reflected higher prices paid for purchases of natural gas which are
passed through to customers under automatic adjustment clauses.
Operating income of the gas distribution segment decreased 13% in the third
quarter of 2000 and 17% for the first nine months of 2000, as compared to the
same periods of 1999. The decreases in operating income were primarily due to a
reduction in rates that became effective December 1999, and weather which was
19% warmer than normal and 3% warmer than in the same period of 1999. The
decrease in rates was the result of an agreement with the Staff of the Arkansas
Public Service Commission during the third quarter of 1999 to close multiple
open dockets and to reduce annual rates by $1.4 million.
Deliveries
The utility systems delivered 20.7 Bcf to sales and end-use transportation
customers during the nine months ended September 30, 2000, down from 22.5 Bcf
for the same period in 1999. The decrease in deliveries was due to warmer
weather and the sale of the Missouri operations in May 2000. Excluding the
effect of the Missouri operations from both the nine months ended September 30,
2000 and 1999, deliveries to sales and end-use transportation customers were
16.9 Bcf and 17.3 Bcf, respectively.
Operating Costs and Expenses
The changes in purchased gas costs for the gas distribution segment reflect
volumes purchased, prices paid for supplies, the mix of purchases from
intercompany versus third party sources and the sale of Missouri assets as
discussed above. Other operating costs and expenses of the gas distribution
segment for the quarter and nine months ended September 30, 2000 were lower than
the comparable periods of the prior year due primarily to the sale of Missouri
assets.
Going forward, the Company's comparative operating results for its gas
distribution segment will be lower reflecting the Missouri asset divestiture.
However, the Company does not expect the sale
- 16 -
<PAGE>
to materially impact consolidated earnings as the loss in operating income
should be offset by a corresponding decrease in corporate interest expense.
Marketing and Other
<TABLE>
<CAPTION>
Three Months Nine Months
--------------- ---------------
2000 1999 2000 1999
------------------ -------------------
<S> <C> <C> <C> <C>
Marketing revenues (in thousands) $58,906 $39,338 $152,947 $92,490
Marketing operating income
(in thousands) $ 464 $ 469 $ 2,001 $ 1,924
Gas volumes marketed (Bcf) 14.6 16.2 48.5 44.6
</TABLE>
Marketing
The increase in gas marketing revenues for the three and nine month periods
ended September 30, 2000, primarily relates to a substantial increase in natural
gas commodity prices from the prior year, and was offset by a comparable
increase in purchased gas costs. Operating income for the marketing segment was
$2.0 million for the first nine months of 2000, compared to $1.9 million for the
same period in 1999. The Company marketed 48.5 Bcf of gas in the first nine
months of 2000, compared to 44.6 Bcf for the same period in 1999.
NOARK Pipeline
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK)
pre-tax loss included in other income was $.4 million for the third quarter and
$1.5 million for the first nine months of 2000, compared to $.5 million and $1.6
million, respectively, for the same periods in 1999.
Interest Expense
Interest expense increased 54% for the third quarter of 2000 and 31% for the
nine months ended September 30, 2000, compared to the same periods in 1999, due
to higher average borrowings caused primarily by the payment of the Hales
judgment and a lower level of capitalized interest. Interest is capitalized in
the exploration and production segment on costs that are unevaluated and
excluded from amortization. Interest expense for the first nine months of 2000
also includes one-time costs associated with the new revolving credit facility
discussed below in Financing Requirements.
Income Taxes
The changes in the provisions for current and deferred income taxes recorded in
the nine months ended September 30, 2000, as compared to the same period in
1999, resulted primarily from the Hales judgment which resulted in a deferred
tax benefit of $42.6 million. Other items impacting deferred taxes recorded in
the three and nine month periods ended September 30, 2000 include the level of
taxable income and the deduction of intangible drilling costs in the year
incurred for tax purposes, netted against the turnaround of intangible drilling
costs deducted for tax purposes
- 17 -
<PAGE>
in prior years. Intangible drilling costs are capitalized and amortized over
future years for financial reporting purposes under the full cost method of
accounting.
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at September 30, 2000, as compared
to December 31, 1999, primarily reflect the impact of the Hales judgment (see
Note 3 to Consolidated Financial Statements) and the seasonal nature of the gas
distribution segment of the Company's business combined with the sale of the
Company's Missouri gas distribution assets.
Routine capital expenditures, cash dividends and scheduled debt retirements have
predominantly been funded through cash provided by operations. For the nine
months ended September 30, 2000, cash used in operating activities was $53.0
million due to the third quarter funding of the Hales judgment. The Hales
judgment, as well as routine capital expenditures, cash dividends and debt
retirements for the nine months ended September 30, 2000, were funded through a
combination of cash provided by operating activities and additional borrowings,
as discussed in Financing Requirements. For the first nine months of 1999, net
cash provided by operating activities was $50.2 million and exceeded the total
of these routine requirements. In connection with the Hales judgment, the
Company indefinitely suspended the quarterly dividend on its common stock.
Financing Requirements
In July 2000, the Company replaced its existing revolving credit facilities that
had previously provided the Company access to $80.0 million of variable rate
capital with a new revolving credit facility that has a capacity of $180.0
million. This new facility was used to fund the Hales judgment of $109.3
million, pay off the existing revolver balance and retire $22.0 million of
private placement debt. The new credit facility is also being used to fund
normal working capital needs. The interest rate on the new facility is 112.5
basis points over the LIBOR rate. The new credit facility has a term of 364 days
and will provide financing while the Company pursues the proposed sale of its
gas distribution assets. At September 30, 2000, the revolving credit facility
had a balance of $151.3 million and was classified as a current liability in the
Company's balance sheet.
In August 2000, the Company retired $22.0 million of 9.36% private placement
notes. Certain costs of the redemption were expensed and are classified as an
extraordinary loss, net of related income tax effects.
During the first nine months of 2000, the Company's total debt increased by
$74.1 million, due to the payment of the Hales judgment, offset by operational
cash flow and the application of the proceeds from the sale of the Company's
Missouri gas distribution assets. Total debt at September 30, 2000, accounted
for 74% of the Company's capitalization, up from 61% at December 31, 1999. As a
result of seasonal working capital requirements, the Company expects its
borrowings to increase during the fourth quarter of 2000, while its total debt
as a percent of the Company's capitalization is expected to remain approximately
the same.
- 18 -
<PAGE>
The Company's capital expenditures for the first nine months of 2000 were $57.4
million, compared to $49.5 million for the same period in 1999. Planned capital
investments during calendar year 2000 are currently expected to be approximately
$75.0 million.
At September 30, 2000, the NOARK partnership had outstanding debt totaling $76.0
million. The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on the NOARK debt. The Company's
share of the several guarantee is 60%.
Working Capital
Accounts receivable has declined since December 31, 1999, due primarily to
seasonally lower gas deliveries of the gas distribution segment and the loss of
customers resulting from the sale of the Missouri gas distribution assets,
partially offset by increases in sales amounts by the marketing segment. The
decrease in inventories since December 31, 1999, is primarily the result of the
sale of the Missouri assets. At September 30, 2000, the Company had
under-recovered gas costs of $6.9 million recorded in current assets. Purchased
gas costs are recovered from the Company's utility customers in subsequent
months through automatic cost of gas adjustment clauses included in the
utility's filed rate tariffs. At December 31, 1999 the Company had
over-recovered gas costs of $1.2 million recorded in other current liabilities.
Accounts payable has increased slightly since December 31, 1999, due primarily
to increases in gas purchase costs in the marketing segment, offset by
seasonally lower third party gas purchases of the gas distribution segment and
the timing of expenditures. Short-term debt has increased since December 31,
1999 due to the revolving credit facility entered into during the third quarter
of 2000, as discussed above in Financing Requirements. The increase in other
current liabilities is primarily due to advances received from joint venture
partners for exploration and development projects where the Company is the
operator. Other changes in current assets and current liabilities between
periods resulted primarily from the timing of expenditures and receipts and the
sale of the Missouri gas distribution assets.
FORWARD LOOKING INFORMATION
All statements, other than historical financial information, included in this
discussion and analysis of financial condition and results of operations may be
deemed to be forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended. Although the Company believes the expectations
expressed in such forward-looking statements are based on reasonable
assumptions, such statements are not guarantees of future performance and actual
results or developments may differ materially from those in the forward-looking
statements. Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include, but are
not limited to, the timing and extent of changes in commodity prices for gas and
oil, the effects of commodity hedges and the timing of implementation and
volatility in earnings caused by new hedge accounting standards, the timing and
extent of the Company's success in discovering, developing, producing, and
estimating reserves, the effects of weather and regulation
- 19 -
<PAGE>
on the Company's gas distribution segment, the value that the Company's gas
distribution segment may bring in exploring sales opportunities for this segment
and the timing of any proposed sale, increased competition, legal and economic
factors, governmental regulation, changing market conditions, the comparative
cost of alternative fuels, conditions in capital markets and changes in interest
rates, availability of oil field services, drilling rigs, and other equipment,
as well as various other factors beyond the Company's control.
- 20 -
<PAGE>
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risks relating to the Company's operations result primarily from
changes in commodity prices and interest rates, as well as credit risk
concentrations. The Company uses natural gas and crude oil swap agreements and
options to reduce the volatility of earnings and cash flow due to fluctuations
in the prices of natural gas and oil. The Board of Directors has approved risk
management policies and procedures to utilize financial products for the
reduction of defined commodity price risks. These policies prohibit speculation
with derivatives and limit swap agreements to counterparties with acceptable
credit standings.
Credit Risks
The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of trade receivables and derivative contracts
associated with commodities trading. Concentrations of credit risk with respect
to receivables are limited due to the large number of customers and their
dispersion across geographic areas. No single customer accounts for greater than
11% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
Interest Rate Risk
The Company's short-term debt obligations are sensitive to changes in
interest rates. The Company's policy is to manage interest rates through use of
a combination of fixed and floating rate debt. Interest rate swaps may be used
to adjust interest rate exposures when appropriate. There were no interest rate
swaps outstanding at September 30, 2000. There have been no material changes in
the interest rate risk information that was presented in the Company's 1999
10-K.
Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production and marketing activity against
the inherent price risks of adverse price fluctuations or locational pricing
differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps and options include (1) transactions in
which one party will pay a fixed price (or variable price) for a notional
quantity in exchange for receiving a variable price (or fixed price) based on a
published index (referred to as price swaps), (2) transactions in which parties
agree to pay a price based on two different indices (referred to as basis
swaps), and (3) the purchase and sale of index-related puts and calls (collars)
that provide a "floor" price below which the counterparty pays the Company the
amount by which the price of the commodity is below the contracted floor and a
"ceiling" price above which the Company pays the counterparty the amount by
which the price of the commodity is above the contracted ceiling.
The primary market risk related to these derivative contracts is the
volatility in market prices for natural gas and crude oil. However, this market
risk is offset by the gain or loss recognized
- 21 -
<PAGE>
upon the related sale of the natural gas or oil that is hedged. Credit risk
relates to the risk of loss as a result of non-performance by the Company's
counterparties. The counterparties are primarily major investment and commercial
banks which management believes present minimal credit risks. The credit quality
of each counterparty and the level of financial exposure the Company has to each
counterparty are periodically reviewed to ensure limited credit risk exposure.
The following table provides information about the Company's financial
instruments that are sensitive to changes in commodity prices. The table
presents the notional amount in Bcf (billion cubic feet), the weighted average
contract prices, and the total dollar contract amount by expected maturity
dates. The "Carrying Amount" for the contract amounts are calculated as the
contractual payments for the quantity of gas or oil to be exchanged under
futures contracts and do not represent amounts recorded in the Company's
financial statements. The "Fair Value" represents values for the same contracts
using comparable market prices at September 30, 2000. At September 30, 2000, the
"Carrying Amount" of these financial instruments exceeded the "Fair Value" by
$37.6 million.
<TABLE>
<CAPTION>
Expected Maturity Date
-------------------------------------------------------------------------
2000 2001 2002 2003
---------------- ---------------- ---------------- ----------------
Carrying Fair Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- ----- -------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 2.8 1.2 1.0 .2
Weighted average price per Mcf $2.56 $2.70 $2.65 $2.75
Contract amount (in millions) $7.1 $(.4) $3.1 $.9 $2.6 $1.2 $.6 $.4
Swaps with a fixed price payment
Contract volume (Bcf) .6 - - -
Weighted average price per Mcf $4.84 - - -
Contract amount (in millions) $2.7 $2.7 - - - - - -
Price collar
Contract volume (Bcf) 4.4 13.8 - -
Weighted average floor price
per Mcf $2.52 $2.87 - -
Contract amount of floor
(in millions) $11.0 $11.0 $39.4 $40.2 - - - -
Weighted average ceiling price
per Mcf $3.62 $3.73 - -
Contract amount of ceiling
(in millions) $15.7 $8.2 $51.3 $33.9 - - - -
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 159 72 - -
Weighted average price per Bbl $23.24 $17.49 - -
Contract amount (in millions) $3.7 $2.3 $1.3 $.5 - - - -
Price floor
Contract volume (MBbls) - 325 - -
Weighted average price per Bbl - $18.00 - -
Contract amount (in millions) - - $5.9 $5.9 - - - -
</TABLE>
- 22 -
<PAGE>
PART II
OTHER INFORMATION
Item 1
In the Company's Form 8-K filed June 22, 2000, it reported that the Arkansas
Supreme Court ruled to affirm the 1998 decision of the Sebastian County Circuit
Court awarding $109.3 million in a class action to royalty owners of SEECO,
Inc., a wholly-owned subsidiary of Southwestern Energy Company. The Company has
continuously reported on this matter and the details of the related matter
involving a similar claim by the United States Minerals Management Service
(MMS). The Company fully satisfied the judgment and the Circuit Court in
Sebastian County issued an order in complete and final satisfaction of the
judgment effective July 18, 2000. Since MMS is a member of the class whose claim
was satisfied by the Court's order on July 18, 2000, the MMS claim is also
extinguished. The Company has put in place interim financing with its lead banks
to satisfy the judgment and meet its immediate financial obligations. This new
credit facility has a term of 364 days and will provide interim financing while
the Company pursues the proposed sale of its utility business.
In the Company's Form 8-K filed July 2, 1996, it previously disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed. The Company also reported in its second quarter 2000
Form 10-Q that this matter had gone to a non-jury trial as to liability in
January 2000 and that the Company was awaiting the court's findings. The court
in this matter has issued Findings of Fact and Conclusions of Law that find no
fraud was committed. The court also finds that any override royalty interests
that may ultimately be found to be subject to the plaintiff's claim for
additional override royalties accrued after March 1, 1990. All claims prior to
March 1, 1990 have been barred by the statute of limitations. The ultimate
measure of damages will be determined during the damages phase of the non-jury
proceedings that is scheduled to occur during the first quarter of 2001. While
the company anticipates that it will owe some additional override royalties to
plaintiffs, it does not believe that its liability will be material to its
financial condition, but in any one period it could be significant to its
results of operations.
Items 2 - 6(a)
No developments required to be reported under Items 2 - 6(a) occurred during the
quarter ended September 30, 2000.
Item 6(b)
On September 12, 2000, the Company filed a current report on Form 8-K responding
to a class action lawsuit filed against the Company alleging royalty and mineral
rights owners are owed damages as a result of the Company's operation of an
underground natural gas storage facility in Franklin County, Arkansas. The
Company believes that the Plaintiffs' allegations in this suit are not supported
by the facts or the law and that the Company's subsidiary acted in accordance
with the guidelines of the Arkansas Oil and Gas Commission.
- 23 -
<PAGE>
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: November 8, 2000 /s/ GREG D. KERLEY
----------------------- ---------------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
- 24 -
