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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 June 30, 2001
-------------
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.)
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)
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 August 7, 2001
---------------------------- -----------------------------
Common Stock, Par Value $.10 25,189,255
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- 1 -
PART I
FINANCIAL INFORMATION
- 2 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
June 30, December 31,
2001 2000
------------- ------------
($ in thousands)
Current Assets
Cash $ 1,492 $ 2,386
Accounts receivable 37,942 77,041
Inventories, at average cost 24,127 17,000
Under-recovered purchased gas costs 4,631 12,942
Hedging asset - SFAS No.133 6,504 -
Other 2,712 3,486
--------- ---------
Total current assets 77,408 112,855
--------- ---------
Investments 16,233 15,574
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 917,487 872,023
Gas distribution systems 190,965 190,893
Gas in underground storage 30,103 27,867
Other 28,338 27,940
--------- ---------
1,166,893 1,118,723
Less: Accumulated depreciation,
depletion and amortization 578,142 554,616
--------- ---------
588,751 564,107
--------- ---------
Other Assets 13,423 12,842
--------- ---------
Total Assets $ 695,815 $ 705,378
========= =========
The accompanying notes are an integral part
of the financial statements.
- 3 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
June 30, December 31,
2001 2000
------------- ------------
($ in thousands)
Current Liabilities
Short-term debt $ - $ 171,000
Accounts payable 34,885 54,304
Taxes payable 2,920 4,346
Interest payable 2,632 2,806
Customer deposits 4,517 4,799
Deferred income tax payable 2,537 -
Other 3,558 2,629
--------- ---------
Total current liabilities 51,049 239,884
--------- ---------
Long-Term Debt, less current portion above 357,000 225,000
--------- ---------
Other Liabilities
Deferred income taxes 112,457 97,431
Other 1,836 1,772
--------- ---------
114,293 99,203
--------- ---------
Commitments and Contingencies
Minority Interest in Partnership 4,284 -
--------- ---------
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 20,210 20,220
Retained earnings 171,235 148,353
Accumulated other comprehensive income 4,601 -
--------- ---------
198,820 171,347
Less: Common stock in treasury, at cost,
2,547,723 shares in 2001 and
2,556,908 shares in 2000 28,445 28,485
Unamortized cost of 227,226
restricted shares in 2001
and 241,452 restricted shares
in 2000, issued under stock
incentive plan 1,186 1,571
--------- ---------
169,189 141,291
--------- ---------
Total Liabilities and Shareholders' Equity $ 695,815 $ 705,378
========= =========
The accompanying notes are an integral part
of the financial statements.
- 4 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
Operating Revenues
Gas sales $ 52,173 $ 37,686 $ 147,558 $ 97,978
Gas marketing 17,523 35,384 52,712 65,388
Oil sales 4,682 3,798 8,844 7,377
Gas transportation and other 1,645 1,615 4,038 4,653
---------- ---------- ---------- ----------
76,023 78,483 213,152 175,396
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gas purchases - utility 9,370 7,963 50,498 27,226
Gas purchases - marketing 16,845 34,456 50,580 63,119
Operating expenses 9,215 8,476 19,678 17,342
General and administrative expenses 7,580 6,770 12,407 12,690
Unusual item - 109,288 - 109,288
Depreciation, depletion and amortization 12,637 11,251 24,274 22,342
Taxes, other than income taxes 2,361 2,128 5,101 4,182
---------- ---------- ---------- ----------
58,008 180,332 162,538 256,189
---------- ---------- ---------- ----------
Operating Income (Loss) 18,015 (101,849) 50,614 (80,793)
---------- ---------- ---------- ----------
Interest Expense
Interest on long-term debt 5,904 4,944 12,771 10,145
Other interest charges 538 913 829 1,105
Interest capitalized (424) (683) (860) (1,320)
---------- ---------- ---------- ----------
6,018 5,174 12,740 9,930
---------- ---------- ---------- ----------
Other Income (Expense) (358) 3,239 22 1,998
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes &
Minority Interest 11,639 (103,784) 37,896 (88,725)
---------- ---------- ---------- ----------
Minority Interest in Partnership (384) - (384) -
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes 11,255 (103,784) 37,512 (88,725)
---------- ---------- ---------- ----------
Income Tax Provision (Benefit)
Current - (872) - -
Deferred 4,386 (39,603) 14,630 (34,602)
---------- ---------- ---------- ----------
4,386 (40,475) 14,630 (34,602)
---------- ---------- ---------- ----------
Income (Loss) Before Extraordinary Item 6,869 (63,309) 22,882 (54,123)
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) - (890) - (890)
---------- ---------- ---------- ----------
Net Income (Loss) $ 6,869 $ (64,199) $ 22,882 $ (55,013)
========== ========== ========== ==========
Basic Earnings Per Share $0.27 ($2.57) $0.91 ($2.20)
========== ========== ========== ==========
Basic Average Common Shares Outstanding 25,189,623 25,035,079 25,188,370 25,036,294
========== ========== ========== ==========
Diluted Earnings Per Share $0.27 ($2.57) $0.89 ($2.20)
========== ========== ========== ==========
Diluted Average Common Shares Outstanding 25,657,842 25,035,079 25,576,721 25,036,294
========== ========== ========== ==========
Dividends Declared Per Share Payable 5/5/00 - - - $0.06
========== ========== ========== ==========
The accompanying notes are an integral part
of the financial statements.
- 5 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
--------------------
2001 2000
-------- --------
($ in thousands)
Cash Flows From Operating Activities
Net income (loss) $ 22,882 $(55,013)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 25,017 23,049
Deferred income taxes 14,630 (34,602)
Equity in loss of NOARK partnership 789 1,057
Gain on sale of Missouri utility assets - (3,209)
Extraordinary loss due to early retirement
of debt (net of tax) - 890
Minority interest in partnership 384 -
Change in assets and liabilities:
Accounts receivable 39,099 3,563
Inventories (7,127) 3,577
Under recovered purchased gas costs 8,311 (4,750)
Accounts payable (19,419) 7,441
Accrual for Hales judgment - 109,288
Other current assets and liabilities (178) (690)
-------- --------
Net cash provided by operating activities 84,388 50,601
-------- --------
Cash Flows From Investing Activities
Capital expenditures (47,990) (43,404)
Sale of Missouri utility assets - 32,000
Investment in NOARK partnership (1,449) (1,620)
Change in gas stored underground (2,236) 944
Other items 1,493 (354)
-------- --------
Net cash used in investing activities (50,182) (12,434)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt (39,000) (27,700)
Contributions from minority interest partner 3,900 -
Payment on revolving short-term debt - (7,500)
Cash dividends - (3,005)
-------- --------
Net cash used in financing activities (35,100) (38,205)
-------- --------
Decrease in cash (894) (38)
Cash at beginning of year 2,386 1,240
-------- --------
Cash at end of period $ 1,492 $ 1,202
======== ========
The accompanying notes are an integral part
of the financial statements.
- 6 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
($ in thousands) ($ in thousands)
Net income (loss) $ 6,869 $(64,199) $ 22,882 $(55,013)
Other comprehensive income:
Unrealized gain on derivative instruments 14,942 - 19,186 -
-------- -------- -------- --------
Comprehensive Income (Loss) $ 21,811 $(64,199) $ 42,068 $(55,013)
======== ======== ======== ========
Reconciliation of Accumulated Other Comprehensive
Income (Loss):
Balance, Beginning of Period $(12,173) $ - $ - $ -
Cumulative effect of adoption of SFAS No. 133 - - (36,963) -
Current period reclassification to earnings 1,832 - 22,378 -
Current period change in derivative instruments 14,942 - 19,186 -
-------- -------- -------- --------
Balance, End of Period $ 4,601 $ - 4,601 $ -
======== ======== ======== ========
The accompanying notes are an integral part
of the financial statements.
- 7 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2001
1. BASIS OF PRESENTATION
The financial statements included herein are unaudited; however, such
financial statements reflect 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 2000
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 896,015 shares of common stock
with a weighted average exercise price of $14.08 per share at June 30,
2001, and options for 2,052,933 shares with an average exercise price
of $10.51 per share at June 30, 2000, that were not included in the
calculation of diluted shares because they would have had an
antidilutive effect.
3. UNUSUAL ITEMS
In the second quarter of 2000, the Company recorded an unusual charge
of $109.3 million for the adverse Hales judgment.
4. DIVIDEND PAYABLE
As a result of the financial impact of the Hales judgment in the second
quarter of 2000, the Company has indefinitely suspended payment of
quarterly dividends on its common stock.
5. DERIVATIVE AND HEDGING ACTIVITIES
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No.
137 and SFAS No. 138, was adopted by the Company on January 1, 2001.
SFAS No. 133 requires that each derivative be recognized in the balance
sheet as either an asset or liability measured at its
-8-
fair value. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged
item in the income statement.
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded
a transition obligation of $60.6 million related to cash flow hedges
that are intended to reduce the volatility in commodity prices for the
Company's forecasted oil and gas production. At June 30, 2001, the
Company recorded assets of $7.5 million related to its commodity cash
flow hedges. Additionally, at June 30, 2001, the Company recorded net
of tax cumulative income to other comprehensive income (equity section
of the balance sheet) of $4.6 million. The amount recorded in other
comprehensive income will be taken to the income statement as the
physical transactions being hedged occur. Additional volatility in
earnings and other comprehensive income may occur in the future as a
result of the adoption of SFAS No. 133.
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.
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- ------- --------
(in thousands)
Three months ended June 30, 2001:
Revenues from external customers $ 38,914 $ 19,586 $ 17,523 $ -- $ 76,023
Intersegment revenues 1,797 20 37,105 112 39,034
Operating income (loss) 18,272 (768) 444 67 18,015
Depreciation, depletion and
amortization expense 11,039 1,557 16 25 12,637
Interest expense(1) 5,255 380 128 255 6,018
Provision (benefit) for income taxes(1) 4,921 (403) 123 (255) 4,386
Assets 498,862 151,300 13,415 32,238(2) 695,815(2)
Capital expenditures 31,334(4) 1,260 17 65 32,676(4)
-9-
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- ------- --------
(in thousands)
Three months ended June 30, 2000:
Revenues from external customers $ 19,799 $ 23,300 $ 35,384 $ -- $ 78,483
Intersegment revenues 4,986 26 15,412 112 20,536
Unusual items (109,288)(3) -- -- -- (109,288)(3)
Operating income (loss) (101,660)(3) (692) 572 (69) (101,849)(3)
Depreciation, depletion and
amortization expense 9,522 1,687 17 25 11,251
Interest expense(1) 3,628 1,274 -- 272 5,174
Provision (benefit) for income taxes(1) (41,093) 429 226 (37) (40,475)
Assets 455,957 148,275 18,319 34,681(2) 657,232(2)
Capital expenditures 27,406 1,372 4 65 28,847
Six months ended June 30, 2001:
Revenues from external customers $ 59,491 $100,949 $ 52,712 $ -- $213,152
Intersegment revenues 21,960 149 72,948 224 95,281
Operating income 40,260 8,630 1,587 137 50,614
Depreciation, depletion and
amortization expense 21,085 3,108 33 48 24,274
Interest expense(1) 10,577 1,471 162 530 12,740
Provision (benefit) for income taxes(1) 11,422 3,000 556 (348) 14,630
Assets 498,862 151,300 13,415 32,238(2) 695,815(2)
Capital expenditures 45,633(4) 2,169 17 171 47,990(4)
Six months ended June 30, 2000:
Revenues from external customers $ 33,514 $ 76,494 $ 65,388 $ -- $175,396
Intersegment revenues 16,032 80 28,653 224 44,989
Unusual items (109,288)(3) -- -- -- (109,288)(3)
Operating income (loss) (92,972)(3) 10,678 1,537 (36) (80,793)(3)
Depreciation, depletion and
amortization expense 18,762 3,497 35 48 22,342
Interest expense(1) 6,866 2,527 -- 537 9,930
Provision (benefit) for income taxes(1) (39,191) 4,359 605 (375) (34,602)
Assets 455,957 148,275 18,319 34,681(2) 657,232(2)
Capital expenditures 40,517 2,652 4 231 43,404
<FN>
(1) Interest expense and the provision (benefit) for income taxes by
segment reflect an allocation of corporate amounts as debt and the
provision (benefit) for income taxes 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 a charge of $109.3 million in 2000 for the Hales
judgment. Excluding this item, operating income for the
exploration and production segment would have been $7.6 million
and $16.3 million for the three and six month periods ended June
30, 2000, respectively.
(4) Capital expenditures for the exploration and production segment
for the three and six month periods ended June 30, 2001, include
$3.9 million of expenditures funded by a minority interest
partner.
</FN>
-10-
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. The exploration and production
segment includes the consolidated amounts for a limited partnership in
which the Company is the controlling partner. All of the Company's
operations are located within the United States.
7. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
Three Months Six Months
Ended June 30, Ended June 30,
----------------- -----------------
2001 2000 2001 2000
----------------- -----------------
(in thousands)
Interest payments $9,617 $9,465 $16,847 $10,071
Income tax payments $ -- $ 270 $ -- $ 270
8. MINORITY INTEREST IN PARTNERSHIP
In the second quarter of 2001, the Company formed a limited partnership
with an investor to drill and complete the first 14 development wells
in the Company's Overton Field located in Smith County, Texas. Because
Southwestern is the sole general partner and controls the partnership,
the operating and financial results are included in the Company's
exploration and production results and the investor's share of the
partnership activity is reported as a minority interest item in the
Company's financial statements. The Company will contribute 50% of the
capital required to drill the first 14 wells. Revenues and expenses are
allocated 65% to the Company prior to payout of the initial investment
and 85% to the Company thereafter.
9. CONTINGENCIES AND COMMITMENTS
The Company recently settled litigation in a case filed in a state
court in Franklin County, Arkansas in 1996 against the Company and two
of its subsidiaries related to overriding royalty interests on certain
Arkansas oil and gas properties. In a Form 8-K filed in July 1996, the
Company disclosed the lawsuit and that the plaintiff was seeking
several million dollars in damages for failure to attach overrides
dating back to 1939 to certain gas producing properties. The plaintiff
subsequently expanded its claim alleging the underpayment of overriding
royalties arising from contractual arrangements for the purchase and
sale of natural gas between subsidiaries of the Company dating back to
1978.
-11-
This matter went to a non-jury trial as to the issue of liability in
January 2000. The court issued Findings of Fact and Conclusions of Law
that found no fraud was committed and that any overriding royalty
interests subject to the plaintiff's claim for additional overriding
royalties accrued after March 1, 1990. All claims prior to March 1,
1990 were barred by the statute of limitations. The damages phase of
the trial was scheduled for June 2001 and the Company recently settled
all outstanding issues in the case through mediation. The Company
recorded a $2.0 million charge in the second quarter of 2001 related to
the settlement. Also, in connection with the settlement, the Company
purchased the plaintiff's overriding royalty interest in a group of the
Company's Arkansas gas producing properties.
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 June 30, 2001 and December 31, 2000, the principal
outstanding for these Notes was $74.0 million and $75.0 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. Under the several guarantee, the Company is
required to fund its proportionate share of NOARK's debt service
obligations if such obligations cannot be 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 integrated
pipeline system. Therefore, no provision for any loss relating to the
NOARK investment has been made in the accompanying financial
statements. Additionally, the Company's gas distribution subsidiary has
transportation contracts for firm capacity of 66.9 MMcfd on NOARK's
integrated pipeline system. These contracts expire in 2002 and 2003,
and are renewable on an annual basis thereafter unless terminated after
180 days' prior 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 the amount of
such liability 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 financial position or
reported results of operations of the Company.
-12-
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, 2000, and
analyzes the changes in the results of operations between the three and six
month periods ended June 30, 2001, and the comparable periods of 2000.
RESULTS OF OPERATIONS
Net income for the three months ended June 30, 2001 was $6.9 million, or $.27
per share, compared to a net loss of $64.2 million, or $2.57 per share, in 2000.
The Company's results for the three months ended June 30, 2000, included an
unusual charge of $109.3 million for the adverse judgment in the Hales royalty
lawsuit ($66.7 million after-tax), an extraordinary loss on the early retirement
of debt, and a $3.2 million gain from the sale of the Company's Missouri utility
properties. Excluding these unusual and extraordinary items, Southwestern would
have reported net income of $1.4 million, or $.05 per share, for the second
quarter of 2000.
Net income for the six months ended June 30, 2001, was $22.9 million, or $.91 of
basic earnings per share ($.89 per share on a fully diluted basis), compared to
a net loss for the six months ended June 30, 2000, of $55.0 million, or $2.20
per share. Excluding the unusual and extraordinary items discussed above, net
income for the first six months of 2000 would have been $10.6 million, or $.42
per share. The increases in quarterly and year-to-date net income were due to
improved operating results experienced by the exploration and production
segment. This segment benefited from both increased production and higher
commodity prices.
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.
-13-
Three Months Six Months
Ended June 30, Ended June 30,
-------------------- -------------------
2001 2000 2001 2000
-------------------- -------------------
Revenues (in thousands) $40,711 $ 24,785 $81,451 $ 49,546
Operating income (loss) (in thousands) $18,272 $(101,660)(1) $40,260 $(92,972)(1)
Gas production (MMcf) 8,653 7,924 16,678 15,700
Oil production (MBbls) 191 169 352 324
Total production (MMcfe) 9,799 8,938 18,790 17,644
Average gas price per Mcf $4.16 $2.64 $4.31 $2.63
Average oil price per Bbl $24.59 $22.54 $25.15 $22.78
Operating expenses per Mcfe
Production expenses $0.44 $0.35 $0.48 $0.37
Production taxes $0.18 $0.15 $0.20 $0.14
General & administrative expenses $0.54(2) $0.35 $0.39(2) $0.31
Full cost pool amortization $1.10 $1.03 $1.09 $1.03
<FN>
(1) Includes a charge of $109.3 million for the Hales judgment. Excluding
this item, operating income for the exploration and production segment
would have been $7.6 million and $16.3 million for the three and six
month periods ended June 30, 2000, respectively.
(2) Includes $2.0 million, or $.20 per Mcfe for the three months ended
June 30, 2001 and $.11 per Mcfe for the six months ended June 30, 2001,
for settled litigation.
</FN>
Revenues and Operating Income
Revenues for the exploration and production segment were up 64% for both the
three and six month periods ended June 30, 2001, compared to the same periods in
2000. The increases were due to both higher gas and oil prices and increased gas
and oil production.
Operating income, excluding unusual items, for the exploration and production
segment was up $10.6 million for the three months ended June 30, 2001, and up
$23.9 million for the first six months of 2001, both as compared to the same
periods in 2000. The improvements in operating income were due to the higher
segment revenues.
Production
Gas and oil production during the second quarter of 2001 was 9.8 billion cubic
feet (Bcf) equivalent, up 10% from 8.9 Bcf equivalent for the same period in
2000. The increase in production primarily resulted from new wells added in 2000
and 2001 in the Company's Arkoma Basin and Gulf Coast operating areas. Gas
production was 8.7 Bcf for the second quarter of 2001, compared to 7.9 Bcf for
the same period in 2000. For the six months ended June 30, 2001, gas and oil
production was 18.8 Bcf equivalent compared to 17.6 Bcf equivalent for the same
period in 2000. Gas production was 16.7 Bcf for the first six months of 2001
compared to 15.7 in 2000. The Company's sales to its gas distribution systems
were 3.1 Bcf during the six months ended
-14-
June 30, 2001, compared to 4.8 Bcf for the same period in 2000. The Company's
oil production was 352 thousand barrels (MBbls) during the first six months of
2001, up from 324 MBbls for the same period of 2000.
Commodity Prices
The Company realized an average price of $4.16 per thousand cubic feet (Mcf) for
its natural gas production for the three months ended June 30, 2001, up from
$2.64 per Mcf for the same period of 2000. The average realized price for the
six months ended June 30, 2001 was $4.31 compared to $2.63 for the same period
in 2000. The Company hedged 14.1 Bcf of gas production in the first six months
of 2001 primarily through zero-cost collars, which had the effect of reducing
the average gas price by $.49 per Mcf in the second quarter of 2001 and by $1.57
per Mcf in the first half of 2001. On a comparative basis, the average realized
price during the second quarter of 2000 was reduced by $.75 per Mcf and was
reduced by $.41 per Mcf in the first half of 2000, due to the effect of
commodity price hedges. Additionally, the Company receives monthly demand
charges related to the no-notice service it makes available to the utility
segment which increase the Company's average gas price.
For the remainder of 2001, the Company has 12.7 Bcf of gas production hedged
with collars having an average NYMEX floor price of $3.85 per Mcf and an average
NYMEX ceiling price of $4.73 per Mcf. The Company also has 1.1 Bcf of gas
production for the remainder of 2001 hedged with fixed price swaps at an average
NYMEX price of $3.55 per Mcf. For the years 2002 and 2003 combined, the Company
has 7.2 Bcf hedged under zero-cost collars and fixed-price swaps. See Part I,
Item 3 of this Form 10-Q for additional information regarding the Company's
commodity price risk hedging activities.
The Company received an average price of $24.59 per barrel for its oil
production during the three months ended June 30, 2001, up from $22.54 per
barrel for the same period of 2000. For the six months ended June 30, 2001, the
Company received an average price of $25.15 per barrel for its oil production,
up from $22.78 per barrel for the same period of 2000. For the remainder of
2001, the Company has a collar on 150,000 barrels with an average floor of
$27.40 per barrel, and an average ceiling of $29.95 per barrel, and a hedge on
36,000 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 the second quarter and first six months of 2001 due to higher
production related expenses, increased depreciation, depletion and amortization
expense, and a $2.0 million charge included in general and administrative
expense related to the settlement of litigation. The increase in operating
expenses was due to increased production volumes, a higher level of workover
expenses and an industry-wide increase in costs related to normal production
activities. Additionally, increased severance and ad valorem taxes resulted from
both increased production volumes and higher commodity prices. The Company
anticipates that the inflationary increases in exploration and production
related costs that have resulted from an overall increase in the activity level
of the domestic oil and gas industry will continue in the near future. The
increases in depreciation,
-15-
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 $1.10 per Mcf equivalent for the
second quarter of 2001 and $1.09 for the first six months of 2001, compared to
$1.03 per Mcf equivalent for the comparable periods of 2000.
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 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 June 30, 2001, 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.
In the second quarter of 2001, the Company formed a limited partnership with an
investor to drill and complete the first 14 development wells in the Company's
Overton Field located in Smith County, Texas. This partnership was created to
provide the capital necessary to accelerate the field's development. The Overton
properties were acquired by the Company in April 2000 and have multiple
development locations through the downspacing of the existing units. Because
Southwestern is the sole general partner and controls the partnership, operating
and financial results for the partnership are consolidated with the other
operations of the Company and the investor's share of the partnership activity
is reported as a minority interest item in the financial statements.
During the second quarter of 2000, the Company recorded an unusual charge of
$109.3 million resulting from the adverse judgment in the Hales litigation.
Gas Distribution
Overview
The operating results of the Company's gas distribution segment are highly
seasonal. This segment typically realizes operating losses in the second and
third quarters of the year and realizes operating income during the winter
heating season in the first and fourth quarters. The extent and duration of
heating weather also impacts the profitability of this segment, although the
Company has a weather normalization clause in its filed rate tariffs that
lessens the impact of revenue increases and decreases which might result from
weather variations during the winter heating season. The gas distribution
segment's profitability is also dependent upon the timing and amount of
regulatory rate increases that are filed with and approved by the Arkansas
Public Service Commission. For periods subsequent to allowed rate increases, the
Company's profitability is impacted by its ability to manage and control this
segment's operating costs and expenses.
-16-
Three Months Six Months
Ended June 30, Ended June 30,
--------------------- --------------------
2001 2000 2001 2000
--------------------- --------------------
($ in thousands, except for per Mcf amounts)
Revenues $ 19,606 $ 23,326 $101,098 $ 76,574
Gas purchases $ 11,148 $ 12,948 $ 72,437 $ 43,258
Operating costs and expenses $ 9,226 $ 11,070 $ 20,031 $ 22,638
Operating income (loss) $ (768) $ (692) $ 8,630 $ 10,678
Deliveries (Bcf)
Sales and end-use transportation 3.6 5.2 14.1 17.3
Off-system transportation 1.0 .5 1.0 2.1
Average number of customers 133,733 164,197 135,177 173,122
Average sales rate per Mcf $9.39 $6.85 $9.33 $5.84
Heating weather - degree days 166 293 2,327 1,982
- percent of normal 55% 96% 95% 81%
Note: Amounts and statistics for the three and six month periods ended June
30, 2000, include the operations of the Company's Missouri properties
that were sold in May 2000.
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 had authorized
management to pursue the sale of the Company's remaining gas distribution
operations. The Company has suspended the sale process as it did not result in
an acceptable bid. Although the Company may decide to sell its gas distribution
segment in the future, it currently plans to operate these assets as a
continuing part of its business.
Revenues and Operating Income
Revenues for the three and six month periods ended June 30, 2001 are up from the
comparable periods of 2000 primarily due to the cost of gas supply which has
more than doubled when compared to the prior year periods. The high cost of gas
supply is reflected in the Company's average rate for its utility sales which
increased during the first six months of 2001 to $9.33 per Mcf, up from $5.84
per Mcf for the same period in 2000. The average sales rate for the second
quarter of 2001 was $9.39 compared to $6.85 for the same period of 2000. The
higher prices paid for purchases of natural gas are passed through to customers
under automatic adjustment clauses.
Operating income of the gas distribution segment decreased 11% in the second
quarter of 2001 and decreased 19% in the first six months of 2001, as compared
to the same periods of 2000. The
-17-
decreases in operating income were due to the impact of the sale of the
Company's Missouri gas distribution assets in May 2000. Excluding the effects of
the Missouri operations from 2000, operating results for the first six months of
2001 were approximately even with 2000 despite weather which was 5% warmer than
normal and 17% colder than in the same period of 2000. This was primarily due to
the Company's weather normalization clause in its rate tariffs. The weather
normalization clause lessens the impacts of revenue increases and decreases that
might result from weather variations during the winter heating season.
Deliveries
The utility systems delivered 3.6 Bcf to sales and end-use transportation
customers during the second quarter of 2001, down from 5.2 Bcf for the same
period in 2000. For the six months ended June 30, 2001, the utility systems
delivered 14.1 Bcf to sales and end-use transportation customers, compared to
17.3 Bcf for the same period in 2000. The decrease in deliveries in the second
quarter was due to warmer weather and the sale of the Missouri operations in May
2000. The decrease in deliveries for the first six months of 2001 was due to the
sale of the Missouri properties, offset by increased deliveries due to colder
weather. Excluding the effect of the Missouri operations from the three and six
month periods ended June 30, 2000, deliveries to sales and end-use
transportation customers were 4.4 Bcf and 13.7 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 the Missouri assets as
discussed above. Other operating costs and expenses of the gas distribution
segment for the three and six month periods ended June 30, 2001 were lower than
the comparable periods of the prior year due primarily to the sale of the
Missouri assets.
Marketing and Other
Three Months Six Months
Ended June 30, Ended June 30,
------------------ -------------------
2001 2000 2001 2000
------------------ -------------------
Marketing revenues (in thousands) $54,628 $50,796 $125,660 $94,041
Marketing operating income (in thousands) $444 $572 $1,587 $1,537
Gas volumes marketed (Bcf) 12.4 15.7 23.4 33.9
Marketing
The increases in gas marketing revenues for the three and six month periods
ended June 30, 2001, relate to a substantial increase in natural gas commodity
prices from the prior year, and was largely offset by a comparable increase in
purchased gas costs. Operating income for the marketing segment was $.4 million
for the second quarter of 2001 and $1.6 million for the first six months of
2001, compared to $.6 million and $1.5 million for the comparable periods in
2000.
-18-
The Company marketed 12.4 Bcf of gas in the second quarter of 2001 and 23.4 Bcf
in the first six months of 2001, compared to 15.7 Bcf and 33.9 Bcf for the same
periods in 2000. The decreases in volumes marketed resulted from a planned
decrease in volumes marketed for unaffiliated third parties.
NOARK Pipeline
The Company's share of the NOARK pre-tax loss included in other income was $.8
million for the first six months of 2001, compared to $1.1 million for the same
period in 2000.
Interest Expense
Interest expense increased 16% for the second quarter of 2001 and 28% for the
first six months of 2001, both as compared to the same periods in 2000, due to
higher average borrowings caused by the payment of the Hales judgment in July
2000, 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.
Income Taxes
The changes in the provisions for current and deferred income taxes recorded in
the three and six month periods ended June 30, 2001, as compared to the same
periods in 2000, resulted primarily from the increase in the level of taxable
income in 2001. Also impacting deferred taxes is 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 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 June 30, 2001, as compared to
December 31, 2000, primarily reflect the seasonal nature of the Company's gas
distribution segment and the effects of the adoption of SFAS No. 133 (See Note 5
to Consolidated Financial Statements in this Form 10-Q).
Routine capital expenditures and scheduled debt retirements have predominantly
been funded through cash provided by operations. For the first six months of
2001 and 2000, cash provided by operating activities was $84.4 and $50.6
million, respectively, and exceeded the total of these routine requirements.
Financing Requirements
In July 2001, the Company arranged a new unsecured revolving credit facility
with a group of banks to replace the existing short-term credit facility. The
short-term facility was put in place in July 2000 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 revolving credit facility has a capacity of
$160 million and a three-year term. The interest rate on the new facility is
137.5 basis points over the current London Interbank Offered Rate (LIBOR), and
was 5.2% at June 30, 2001. The
-19-
new credit facility contains covenants which impose certain restrictions on the
Company. Under the credit agreement, the Company may not issue total debt in
excess of 75% of its total capital, must maintain a certain level of
shareholders' equity, and the Company must maintain a ratio of earnings before
interest, taxes, depreciation and amortization (EBITDA) to fixed charges of at
least 3.75 or higher through March 30, 2002. These covenants change over the
term of the credit facility and generally become more restrictive. At June 30,
2001, the Company's revolving credit facility had a balance of $132.0 million
and was classified as long-term debt in the Company's balance sheet.
During the first six months of 2001, the Company's total debt decreased by $39.0
million, as increased cash flow generated from operations exceeded the Company's
capital requirements. Total debt at June 30, 2001, accounted for 68% of the
Company's capitalization, down from 74% at December 31, 2000. Excluding the
effects of SFAS No. 133, the percentage of debt to total capitalization would
have been 69% at June 30, 2001.
The Company's capital expenditures for the first six months of 2001 were $48.0
million, compared to $43.4 million for the same period in 2000. The Company's
reported capital investments include the gross expenditures of the Overton
partnership. The minority interest partner in Overton funded $3.9 million of the
Company's reported expenditures during the period. Additionally, the Company's
capital expenditures during the second quarter of 2001 included $5.8 million to
purchase overriding royalty interests in a group of the Company's Arkoma Basin
properties. This acquisition was made in connection with the settlement of
litigation. Planned capital investments during calendar year 2001 are currently
expected to be approximately $100 million, including approximately $12 million
which will be funded by the minority interest partner in Overton.
At June 30, 2001, NOARK had outstanding debt totaling $74.0 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 have declined since December 31, 2000, due to the seasonal
nature of the Company's gas distribution segment and a decrease in the amounts
owed to the Company's exploration and production segment for oil and gas
production due to lower commodity prices. Under-recovered purchased gas costs
for the Company's gas distribution segment were $4.6 million at June 30, 2001,
compared to $12.9 million at December 31, 2000. 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. Inventories have increased due to the injection of gas into the
Company's gas storage facilities. At June 30, 2001, the Company recorded a
current hedging asset of $6.5 million and a current deferred income tax payable
of $2.5 million under the provisions of SFAS No. 133.
Accounts payable has decreased since December 31, 2000, due primarily to
decreases in gas purchase costs in the gas distribution and marketing segments
and to the timing of expenditures.
-20-
Other changes in current assets and current liabilities between periods resulted
primarily from the timing of expenditures and receipts, and the sale of the
Company's Missouri gas distribution assets in 2000.
FORWARD LOOKING INFORMATION
All statements, other than historical financial information, 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 timing and extent
of the Company's success in discovering, developing, producing, and estimating
reserves, property acquisition or divestiture activities that may occur, the
effects of weather and regulation on the Company's gas distribution segment,
increased competition, legal and economic factors, governmental regulation, the
financial impact of accounting regulations for derivative instruments, 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. A discussion of these and other factors affecting
the Company's performance is included in the Company's periodic reports filed
with the Securities and Exchange Commission including its Annual Report on Form
10-K for the year ended December 31, 2000.
-21-
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 and
interest rate swaps to reduce the volatility of earnings, cash flow and the cost
of purchased gas due to fluctuations in the prices of natural gas and oil and
fluctuations in interest rates. 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
4% of accounts receivable. See the discussion of commodities risk below.
Interest Rate Risk
The Company's revolving 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 June 30, 2001. Subsequent to June 30, 2001, the Company
entered into an interest rate swap for calendar year 2002 that allows the
Company to pay a fixed interest rate of 5.7% on $50 million of its outstanding
revolving debt. The Company's revolving debt was $171.0 million at December 31,
2000, and had an average interest rate of 7.8%. At June 30, 2001, the Company's
revolving debt was $132.0 million with an average interest rate of 5.2%. Other
than the Company's revolving debt, there have been no material changes in the
interest rate risk information that was presented in the Company's 2000 Form
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, activity in its marketing segment,
and gas purchases in the utility segment 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
-22-
the counterparty pays (production hedge) or receives (gas purchase hedge) funds
equal to the amount by which the price of the commodity is below the contracted
floor, and a "ceiling" price above which the Company pays to (production hedge)
or receives from (gas purchase hedge) 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 upon the related sale or purchase 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) and MBbls (thousand
barrels), 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 June 30, 2001.
At June 30, 2001, the "Fair Value" exceeded the "Carrying Amount" of these
financial instruments by $7.5 million.
Expected Maturity Date
--------------------------------------------------------
2001 2002 2003
---------------- ---------------- ----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Production and Marketing
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 1.0 1.0 .2
Weighted average price per Mcf $3.48 $2.65 $2.75
Contract amount (in millions) $3.4 $3.6 $2.6 $1.7 $.6 $.4
Swaps with a fixed price payment
Contract volume (Bcf) .1 - -
Weighted average price per Mcf $4.41 - -
Contract amount (in millions) $.6 $.4 - - - -
-23-
Expected Maturity Date
--------------------------------------------------------
2001 2002 2003
---------------- ---------------- ----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Price collar
Contract volume (Bcf) 12.7 6.0 -
Weighted average floor price
per Mcf $3.85 $4.00 -
Contract amount of floor
(in millions) $48.9 $58.9 $24.0 $29.1 - -
Weighted average ceiling price
per Mcf $4.73 $4.72 -
Contract amount of ceiling
(in millions) $60.1 $58.2 $28.3 $26.6 - -
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 36 - -
Weighted average price per Bbl $17.49 - -
Contract amount (in millions) $.6 $.3 - - - -
Price collar
Contract volume (MBbls) 150 - -
Weighted average floor price
Per Bbl $27.40 - -
Contract amount of floor
(in millions) $4.1 $4.5 - - - -
Weighted average ceiling price
Per Bbl $29.95 - -
Contract amount of ceiling
(in millions) $4.5 $4.4 - - - -
Natural Gas Purchases
Swaps with a fixed price payment
Contract volume (Bcf) 1.1 2.4 -
Weighted average price per Mcf $4.43 $4.49 -
Contract amount (in millions) $4.7 $3.8 $10.9 $8.9 - -
-24-
PART II
OTHER INFORMATION
Item 1
The Company recently settled litigation in a case filed in a state court in
Franklin County, Arkansas in 1996 against the Company and two of its
subsidiaries related to overriding royalty interests on certain Arkansas oil and
gas properties. In a Form 8-K filed in July 1996, the Company disclosed the
lawsuit and that the plaintiff was seeking several million dollars in damages
for failure to attach overrides dating back to 1939 to certain gas producing
properties. The plaintiff subsequently expanded its claim alleging the
underpayment of overriding royalties arising from contractual arrangements for
the purchase and sale of natural gas between subsidiaries of the Company dating
back to 1978.
This matter went to a non-jury trial as to the issue of liability in January
2000. The court issued Findings of Fact and Conclusions of Law that found no
fraud was committed and that any overriding royalty interests subject to the
plaintiff's claim for additional overriding royalties accrued after March 1,
1990. All claims prior to March 1, 1990 were barred by the statute of
limitations. The damages phase of the trial was scheduled for June 2001 and the
Company recently settled all outstanding issues in the case through mediation.
The Company recorded a $2.0 million charge in the second quarter of 2001 related
to the settlement. Also, in connection with the settlement, the Company
purchased the plaintiff's overriding royalty interest in a group of the
Company's Arkansas gas producing properties.
Items 2 - 6(a)
No developments required to be reported under Items 2 - 6(a) occurred during the
quarter ended June 30, 2001.
Item 6(b)
On July 5, 2001, the Company filed a Form 8-K discussing the settlement of
litigation involving overriding royalty interests.
All other filings on Form 8-K during the quarter ended June 30, 2001 have been
previously disclosed in the Company's Form 10-Q for the first quarter of 2001.
-25-
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: August 10, 2001 /s/ GREG D. KERLEY
-------------------- -----------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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Southwestern Energy Company
P.O. Box 1408
Fayetteville, AR 72702-1408
August 10, 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
the Quarterly Report on Form 10-Q for the quarter ended June 30, 2001.
This filing is being effected by direct transmission to the Commission's
EDGAR System.
Very truly yours,
Stan Wilson
Controller