<PAGE>
===========================================================================
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, 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 August 4, 2000
---------------------------- -----------------------------
Common Stock, Par Value $.10 25,033,281
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- 1 -
<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
------------- ------------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 1,202 $ 1,240
Accounts receivable 36,785 43,339
Inventories, at average cost 15,714 21,520
Under-recovered purchased gas costs 3,588 -
Other 4,901 4,073
--------- ---------
Total current assets 62,190 70,172
--------- ---------
Investments 14,742 14,180
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 855,392 816,199
Gas distribution systems 188,538 222,145
Gas in underground storage 27,769 28,712
Other 29,167 28,826
--------- ---------
1,100,866 1,095,882
Less: Accumulated depreciation,
depletion and amortization 533,181 519,927
--------- ---------
567,685 575,955
--------- ---------
Other Assets 12,615 11,139
--------- ---------
Total Assets $ 657,232 $ 671,446
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 3 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
June 30, December 31,
2000 1999
------------- ------------
($ in thousands)
<S> <C> <C>
Current Liabilities
Short-term debt $ 42,000 $ 7,500
Accounts payable 40,479 33,069
Accrual for Hales judgment (Note 3) 109,288 -
Taxes payable 2,639 3,506
Interest payable 2,383 2,483
Customer deposits 4,778 6,021
Other 3,441 3,767
--------- ---------
Total current liabilities 205,008 56,346
--------- ---------
Long-Term Debt, less current portion above 225,000 294,700
--------- ---------
Other Liabilities
Deferred income taxes 91,748 126,902
Other 2,832 3,142
--------- ---------
94,580 130,044
--------- ---------
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 20,747 20,732
Retained earnings 140,026 198,044
Less: Common stock in treasury, at cost,
2,703,963 shares in 2000 and
2,700,391 shares in 1999 30,123 30,083
Unamortized cost of 152,113
restricted shares in 2000
and 188,781 restricted shares
in 1999, issued under stock
incentive plan 780 1,111
--------- ---------
132,644 190,356
--------- ---------
Total Liabilities and Shareholders' Equity $ 657,232 $ 671,446
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 4 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
------------------------- -------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues
Gas sales $ 37,686 $ 30,715 $ 97,978 $ 91,654
Gas marketing 35,384 21,330 65,388 34,805
Oil sales 3,798 2,312 7,377 3,973
Gas transportation and other 1,615 1,682 4,653 3,827
---------- ---------- ---------- ----------
78,483 56,039 175,396 134,259
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gas purchases - utility 7,963 7,714 27,226 28,074
Gas purchases - marketing 34,456 20,585 63,119 32,673
Operating and general 15,246 14,319 30,032 28,242
Unusual item - Hales judgment (Note 3) 109,288 - 109,288 -
Depreciation, depletion and amortization 11,251 10,321 22,342 20,693
Taxes, other than income taxes 2,128 1,559 4,182 3,107
---------- ---------- ---------- ----------
180,332 54,498 256,189 112,789
---------- ---------- ---------- ----------
Operating Income (101,849) 1,541 (80,793) 21,470
---------- ---------- ---------- ----------
Interest Expense
Interest on long-term debt 4,944 4,679 10,145 9,513
Other interest charges 913 258 1,105 541
Interest capitalized (683) (827) (1,320) (1,666)
---------- ---------- ---------- ----------
5,174 4,110 9,930 8,388
---------- ---------- ---------- ----------
Other Income (Expense) 3,239 (225) 1,998 (905)
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes (103,784) (2,794) (88,725) 12,177
---------- ---------- ---------- ----------
Income Tax Provision (Benefit)
Current (872) (4,620) - 750
Deferred (39,603) 3,530 (34,602) 3,999
---------- ---------- ---------- ----------
(40,475) (1,090) (34,602) 4,749
---------- ---------- ---------- ----------
Income (Loss) Before Extraordinary Item (63,309) (1,704) (54,123) 7,428
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) (890) - (890) -
---------- ---------- ---------- ----------
Net Income (Loss) $ (64,199) $ (1,704) $ (55,013) $ 7,428
========== ========== ========== ==========
Basic and Diluted Earnings (Loss) Per Share
Income (Loss) Before Extraordinary Item ($2.53) ($0.07) ($2.16) $0.30
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) (0.04) - (0.04) -
---------- ---------- ---------- ----------
Net Income (Loss) ($2.57) ($0.07) ($2.20) $0.30
========== ========== ========== ==========
Basic and Diluted Average Common
Shares Outstanding 25,035,079 24,934,012 25,036,294 24,933,966
========== ========== ========== ==========
Dividends Declared Per Share Payable 8/5/99 - $ .06 - $0.06
===== ===== ===== =====
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 5 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
--------------------
2000 1999
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income (loss) $(55,013) $ 7,428
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 23,049 21,382
Deferred income taxes (34,602) 3,999
Equity in loss of partnership 1,057 1,055
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:
Decrease in accounts receivable 3,563 18,462
Decrease in inventories 3,577 364
Increase in under-recovered purchased
gas costs (4,750) (270)
Increase (decrease) in accounts payable 7,441 (13,949)
Accrual for Hales judgment 109,288 -
Net change in other current assets
and liabilities (690) 1,850
-------- --------
Net cash provided by operating activities 50,601 40,321
-------- --------
Cash Flows From Investing Activities
Capital expenditures (43,404) (28,534)
Sale of Missouri utility assets 32,000 -
Investment in partnership (1,620) -
Decrease in gas stored underground 944 3,286
Other items (354) 1,907
-------- --------
Net cash used in investing activities (12,434) (23,341)
-------- --------
Cash Flows From Financing Activities
Net change in revolving debt (27,700) (14,100)
Payment on revolving short-term note (7,500) -
Cash dividends (3,005) (2,992)
-------- --------
Net cash used in financing activities (38,205) (17,092)
-------- --------
Decrease in cash (38) (112)
Cash at beginning of year 1,240 1,622
-------- --------
Cash at end of period $ 1,202 $ 1,510
======== ========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 6 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 2,052,933 shares of common stock
with a weighted average exercise price of $10.51 per share at June 30,
2000, and options for 1,634,901 shares with an average exercise price
of $12.15 per share at June 30, 1999, that were not included in the
calculation of diluted shares because they would have had an
antidilutive effect.
3. UNUSUAL ITEM - HALES JUDGMENT
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 Mineral 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 (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
subsequent to June 30, 2000 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. The Company does, however, expect to realize
a gain from the sale of these assets.
-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 ($20.0 million
at June 30, 2000), and retire $22.0 million of private placement debt.
The new credit facility will also be 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
potential sale of its gas distribution assets (see Note 3).
In August 2000, the Company retired $22.0 million of 9.36% private
placement notes due in annual installments of $2.0 million beginning
December 4, 2001. 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.
Due to the Company's replacement of its revolving credit facility and
retirement of the private placement debt discussed above, the $20.0
million revolver balance and the $22.0 million private placement have
been classified as short-term debt on the Company's balance sheet at
June 30, 2000.
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.
-8-
<PAGE>
<TABLE>
<CAPTION>
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- -------- ---------
(in thousands)
<S> <C> <C> <C> <C> <C>
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
Depreciation, depletion and
amortization expense 9,522 1,687 17 25 11,251
Operating income (101,660)(3) (692) 572 (69) (101,849)
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
Capital expenditures 27,406 1,372 4 65 28,847
Three months ended June 30, 1999:
Revenues from external customers $ 13,185 $ 21,524 $ 21,330 $ - $ 56,039
Intersegment revenues 2,852 21 9,828 96 12,797
Depreciation, depletion and
amortization expense 8,456 1,824 18 23 10,321
Operating income 1,707 (623) 409 48 1,541
Interest expense (1) 2,729 1,249 (14) 145 4,109
Provision (benefit) for income taxes (1) (421) (736) 165 (98) (1,090)
Assets 413,275 170,153 8,664 35,505(2) 627,597
Capital expenditures 13,034 1,810 1 (25) 14,820
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
Depreciation, depletion and
amortization expense 18,762 3,497 35 48 22,342
Operating income (92,972)(3) 10,678 1,537 (36) (80,793)
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
Capital expenditures 40,517 2,652 4 231 43,404
Six months ended June 30, 1999:
Revenues from external customers $ 24,863 $ 74,591 $ 34,805 $ - $ 134,259
Intersegment revenues 11,555 72 18,347 192 30,166
Depreciation, depletion and
amortization expense 17,021 3,591 36 45 20,693
Operating income 7,593 12,327 1,455 95 21,470
Interest expense(1) 5,444 2,509 12 422 8,387
Provision (benefit) for income taxes(1) 791 3,798 563 (403) 4,749
Assets 413,275 170,153 8,664 35,505(2) 627,597
Capital expenditures 25,217 3,185 8 124 28,534
</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 a loss of $109.3 million for Hales judgment. Excluding
the judgment, operating income for the Exploration and Production
segment would have been $7.7 million and $16.3 million for the
three months and the six months ended June 30, 2000, respectively.
</FN>
-9-
<PAGE>
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
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 could increase volatility in future reported earnings and other
comprehensive income.
8. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
<TABLE>
<CAPTION>
Three Months Six Months
Periods Ended June 30 2000 1999 2000 1999
-----------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Interest payments $9,465 $9,117 $10,071 $9,424
Income tax payments $270 $212 $270 $641
</TABLE>
9. Contingencies and Commitments
In its Form 8-K filed July 2, 1996, the Company disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas
oil and gas properties had been filed against
-10-
<PAGE>
it and two of its wholly-owned subsidiaries. The lawsuit, which was
brought by a party who was originally included in (but opted out of)
the Hales class action litigation described in Note 3 above, involves
claims similar to those upon which judgment was rendered against the
Company and its subsidiaries. This matter went to a non-jury trial as
to liability on January 10, 2000 and the Company is awaiting the
Court's ruling. In September 1998, another party who opted out of the
class threatened the Company with similar litigation. That third party
has never pursued any action against the Company and we believe any
such action would now be barred by the statute of limitations. While
the amounts of these pending and threatened claims could be
significant, management believes, based on its extensive
investigations, trial preparation, and discussions with outside
counsel, that these claims are without merit and, that the Company's
ultimate liability, if any, will not be material to its consolidated
financial position or 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 June 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 six
month periods ended June 30, 2000, and the comparable periods of 1999.
RESULTS OF OPERATIONS
The Company reported a net loss for the three months ended June 30, 2000 of
$64.2 million, or $2.57 per share, compared to a net loss of $1.7 million, or
$.07 per share, in 1999. One-time charges during the quarter ended June 30, 2000
included a negative $109.3 million judgment in the Hales royalty lawsuit ($66.7
million after-tax) and an extraordinary loss on the early retirement of debt.
These charges more than offset a $3.2 million gain from the sale of the
Company's Missouri utility properties, which closed May 31, and improved results
from the Company's operations. Excluding these items, Southwestern would have
reported net income of $1.4 million, or $.05 per share, for the second quarter
of 2000. The net loss for the six months ended June 30, 2000 was $55.0 million,
or $2.20 per share. Excluding the unusual items discussed above, net income for
the first six months of 2000 would have been $10.6 million, or $.42 per share,
compared to net income of $7.4 million, or $.30 per share for the same period in
1999.
Excluding the effects of the Hales judgment, the exploration and production
segment had improved operating results benefiting from both increased production
and higher commodity prices. The following tables compare operating revenues and
operating income by business segment for the three and six month periods ended
June 30, 2000 and 1999:
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
-------------------------- --------------------------
2000 1999 2000 1999
---------- ---------- ---------- ----------
(in thousands)
<S> <C> <C> <C> <C>
Revenues
Exploration and production $ 24,785 $ 16,037 $ 49,546 $ 36,418
Gas distribution 23,326 21,545 76,574 74,663
Marketing and other 50,908 31,254 94,265 53,344
Eliminations (20,536) (12,797) (44,989) (30,166)
---------- ---------- ---------- ----------
$ 78,483 $ 56,039 $ 175,396 $ 134,259
========== ========== ========== ==========
Operating Income (Loss)
Exploration and production $ (101,660)(1) $ 1,707 $ (92,972)(1) $ 7,593
Gas distribution (692) (623) 10,678 12,327
Marketing and other 503 457 1,501 1,550
---------- ---------- ---------- ----------
$ (101,849) $ 1,541 $ (80,793) $ 21,470
========== ========== ========== ==========
</TABLE>
-12-
<PAGE>
[FN]
(1) Includes a loss of $109.3 million for the Hales judgment. Excluding this
loss, operating income for the exploration and production segment would
have been $7.7 million and $16.3 million for the three and six month
periods ended June 30, 2000, respectively.
</FN>
Exploration and Production
Revenues for the exploration and production segment were up 55% for the three
month period ended June 30, 2000 and up 36% for the six month period ended June
30, 2000, both as compared to the same periods in 1999. Operating income,
excluding the $109.3 Hales judgment, was up $5.9 million for the three months
ended June 30, 2000, and up $8.7 million for the six months ended June 30, 2000
both as compared to the same periods in 1999. The improvements in operating
income were due to both higher gas and oil prices and increased gas and oil
production. Gas and oil production during the second quarter of 2000 was 8.9
billion cubic feet (Bcf) equivalent, up from 8.1 Bcf equivalent for the same
period in 1999. For the six months ended June 30, 2000, gas and oil production
was 17.6 Bcf equivalent up from 16.6 Bcf equivalent for the same period of 1999.
The increase in production resulted from new wells added in 1999 and 2000. Gas
production was 7.9 Bcf for the three months ended June 30, 2000, and 15.7 Bcf
for the six months ended June 30, 2000, compared to 7.2 Bcf and 14.9 Bcf,
respectively, for the same periods in 1999. The Company's sales to its gas
distribution systems were 4.8 Bcf during the six months ended June 30, 2000,
compared to 4.5 Bcf for the same period in 1999. The Company's oil production
was 324 thousand barrels (MBbls) during the six months ended June 30, 2000, up
from 290 MBbls for the same period of 1999.
The Company received an average price of $2.64 per thousand cubic feet (Mcf) for
its gas production for the three months ended June 30, 2000, up from $1.91 per
Mcf for the same period of 1999. The Company received an average price of $2.63
per Mcf for its gas production during the six months ended June 30, 2000, up
from $2.19 for the same period of 1999. The Company hedged 9.5 Bcf of gas
production in the first half of 2000 at $2.42 per Mcf which had the effect of
reducing the average gas price realized during the period by $.40 per Mcf. On a
comparative basis, the average price during the first half of 1999 included the
positive effect of hedges that increased the average price by $.20 per Mcf.
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 approximately 5.6
Bcf of its production in the third quarter of 2000 at an average NYMEX price of
$2.38, and has hedged 2.6 Bcf 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. The Company
received an average price of $22.78 per barrel for its oil production during the
six months ended June 30, 2000, up from $13.70 per barrel for the same period of
1999. For the remainder of 2000, the Company has hedges in place for 318,000
barrels at an average price of $23.24 per barrel.
Subsequent to June 30, 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 $12.5 million.
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<PAGE>
Gas Distribution
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 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 subsequent to
June 30, 2000 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. The Company
does, however, expect to realize a gain from the sale of these assets.
Operating income of the gas distribution segment decreased 11% in the second
quarter of 2000 and 13% for the first six months of 2000, as compared to the
same periods of 1999. The decreases in operating income were primarily due to
weather which was 19% warmer than normal and 2% warmer than in the same period
of 1999, and a reduction in rates that became effective December 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. The utility systems
delivered 17.3 Bcf to sales and end-use transportation customers during the six
months ended June 30, 2000, down from 18.0 Bcf for the same period in 1999. The
decrease in deliveries was due to warmer weather.
The Company's average rate for its utility sales increased during the first half
of 2000 to $5.87 per Mcf, up from $5.44 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.
Going forward, the Company's comparative operating results for its gas
distribution segment will be lower reflecting the Missouri asset divestiture and
the loss of Missouri customers. However, the Company does not expect the sale to
materially impact earnings as the loss in operating income should be offset by a
corresponding decrease in interest expense. The Company served approximately
48,000 customers in Missouri. The Company's remaining gas distribution systems
in Arkansas serve approximately 134,000 customers.
Marketing and NOARK Pipeline
Operating income for the marketing segment was $1.5 million for the first half
of 2000, even with the same period in 1999, as an increase in gas marketing
revenues was offset by a comparable increase in purchased gas costs. The Company
marketed 33.9 Bcf of gas in the first six months of 2000, compared to 28.4 Bcf
for the same period in 1999.
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK)
pre-tax loss included in other income was $.5 million for the second quarter and
$1.1 million for the first six months of 2000, even with the same periods in
1999.
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<PAGE>
Operating Costs and Expenses
Operating costs and expenses, exclusive of purchased gas costs and the Hales
judgment, increased 9% in both the second quarter and the first six months of
2000, as compared to the same periods in 1999. The increases were primarily
caused by higher operating and general expenses and increased depreciation,
depletion and amortization expense. The increase in operating and general
expenses was due primarily to increased production costs and increased severance
and ad valorem taxes in the exploration and production segment that resulted
primarily from increased production volumes and higher prices. The increase in
depreciation, depletion and amortization expense was due to the increase in
production in the exploration and production segment and an increase in the
amortization rate per unit of production. The amortization rate for this segment
averaged $1.03 per Mcf equivalent for the first six months of 2000, compared to
$.99 per Mcf equivalent in the first six months of 1999. The changes in
purchased gas costs for the gas distribution and marketing segments reflect
volumes purchased, prices paid for supplies and the mix of purchases from
intercompany versus third party sources.
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, 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.
Interest expense for the six months ended June 30, 2000, was up 18% compared to
the same period in 1999, due to higher average borrowings, one-time costs
associated with the new revolving credit facility discussed below in Financing
Requirements, 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.
The changes in the provisions for current and deferred income taxes recorded in
the three and six month periods ended June 30, 2000, as compared to the same
periods in 1999, resulted primarily from the Hales judgment which resulted in a
deferred tax benefit of $42.6 million. Other items impacting deferred taxes
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 in prior years. Intangible
drilling costs are capitalized and amortized over future years for financial
reporting purposes under the full cost method of accounting.
-15-
<PAGE>
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at June 30, 2000, as compared to
December 31, 1999, primarily reflect the impact of the Hales judgment (see Note
3) 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 are
predominantly funded through cash provided by operations. For the first six
months of 2000 and 1999, net cash provided by operating activities was $50.6
million and $40.3 million, respectively, 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 ($20.0 million at June 30, 2000),
and retire $22.0 million of private placement debt. The new credit facility will
also be 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 potential sale of its gas distribution assets.
In August 2000, the Company retired $22.0 million of 9.36% private placement
notes due in annual installments of $2.0 million beginning December 4, 2001.
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.
Due to the Company's replacement of its revolving credit facility and retirement
of the private placement debt discussed above, the $20.0 million revolver
balance and the $22.0 million private placement have been classified as
short-term debt on the Company's balance sheet at June 30, 2000.
During the first six months of 2000, the Company's debt was reduced by $35.2
million, due to seasonally strong cash flow and the application of the proceeds
from the sale of the Company's Missouri gas distribution assets. Total debt at
June 30, 2000, accounted for 67% of the Company's capitalization, up from 61% at
December 31, 1999. The increase reflected the decline in shareholders' equity
resulting from the loss related to the Hales judgment. The Hales judgment was
funded on July 18, 2000 with the Company's new revolving credit facility.
Including this amount as a component of debt, the Company's debt capitalization
would have been 74% at June 30, 2000.
The Company expects its outstanding borrowings to increase during the remaining
months of 2000 as cash generated from operations will be less than the
requirements for routine capital expenditures due to lower levels of
heating-generated revenues and seasonally higher capital expenditures
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<PAGE>
resulting from favorable drilling and construction weather. The Company's
capital expenditures for the first six months of 2000 were $43.4 million,
compared to $28.5 million for the same period in 1999.
At June 30, 2000, the NOARK partnership had outstanding debt totaling
approximately $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 by the marketing segment. The decrease in
inventories since December 31, 1999, is the result of the sale of the Missouri
assets, combined with withdrawals of gas stored underground to meet seasonal
requirements in the gas distribution segment and sales of gas to unaffiliated
parties from the Company's unregulated underground storage facility.
Accounts payable has increased since December 31, 1999, due primarily to
increases in gas purchase costs in the marketing segment, seasonally lower third
party gas purchases of the gas distribution segment and to the timing of
expenditures. Short-term debt has increased since December 31, 1999 due
primarily to the reclassification of $42 million of long-term debt to short-term
debt as a result of the revolving credit facility entered into subsequent to
June 30, 2000, as discussed above in Financing Requirements. The June 30, 2000
accrued liability for the Hales judgment was subsequently funded using the new
revolving credit facility. At June 30, 2000, the company had under-recovered gas
costs of $3.6 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. Other changes in current assets
and current liabilities between periods resulted primarily from the timing of
expenditures and receipts.
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 timing and extent of the Company's success in discovering, developing,
producing, and estimating reserves, the effects of
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<PAGE>
weather and regulation 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, increased competition, legal and economic
factors, 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.
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<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 June 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 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), and (2) transactions in which parties agree
to pay a price based on two different indices (referred to as basis swaps).
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 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
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<PAGE>
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 June 30, 2000. At June 30, 2000, the "Carrying
Amount" of these financial instruments exceeded the "Fair Value" by $31.7
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) 8.3 1.2 1.0 .2
Weighted average price per Mcf $2.39 $2.70 $2.65 $2.75
Contract amount (in millions) $19.9 $2.5 $3.1 $2.0 $2.6 $2.2 $.6 $.6
Swaps with a fixed price payment
Contract volume (Bcf) .4 - - -
Weighted average price per Mcf $4.25 - - -
Contract amount (in millions) $1.6 $1.6 - - - - - -
Price collar
Contract volume (Bcf) 4.4 9.3 - -
Weighted average floor price
per Mcf $2.52 $2.56 - -
Contract amount of floor
(in millions) $11.0 $11.2 $23.7 $25.0 - - - -
Weighted average ceiling price
per Mcf $3.62 $3.20 - -
Contract amount of ceiling
(in millions) $15.7 $11.6 $29.6 $22.4 - - - -
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 318 72 - -
Weighted average price per Bbl $23.24 $17.49 - -
Contract amount (in millions) $7.4 $5.1 $1.3 $.6 - - - -
Price floor
Contract volume (MBbls) - 325 - -
Weighted average price per Bbl - $18.00 - -
Contract amount (in millions) - - $5.9 $5.9 - - - -
</TABLE>
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<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 its Form 8-K filed July 2, 1996, the Company disclosed that a lawsuit
relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
The lawsuit, which was brought by a party who was originally included in (but
opted out of) the class action litigation described above, involves claims
similar to those upon which judgment was rendered against the Company and its
subsidiaries. This matter went to a non-jury trial as to liability on January
10, 2000 and the Company is awaiting the Court's ruling. In September 1998,
another party who opted out of the class threatened the Company with similar
litigation. That third party has never pursued any action against the Company
and we believe any such action would now be barred by the statute of
limitations. While the amounts of these pending and threatened claims could be
significant, management believes, based on its extensive investigations, trial
preparation, and discussions with outside counsel, that these claims are without
merit and, that the Company's ultimate liability, if any, will not be material
to its consolidated financial position or results of operations.
Items 2 - 6(a)
No developments required to be reported under Items 2 - 6(a) occurred during the
quarter ended June 30, 2000.
Item 6(b)
On June 22, 2000, the Company filed a current report on Form 8-K announcing the
Arkansas Supreme Court ruling to affirm the 1998 decision of a Sebastian County
Circuit Court awarding $109.3 million in a class action to royalty owners of
SEECO, Inc., a wholly-owned Southwestern Energy Company subsidiary.
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<PAGE>
On June 26, 2000, the Company filed a current report of Form 8-K announcing
approval of the Board of Directors to pursue the sale of its utility business to
fund the $109.3 million class action judgment against the Company and to
strengthen the Company's financial condition.
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 8, 2000 BY: /s/ GREG D. KERLEY
--------------------- ---------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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