<PAGE>
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------------
FORM 10-Q
(Mark one)
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended September 30, 1998
------------------
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _______ to _______
Commission file number 1-8246
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas 71-0205415
(State of incorporation (I.R.S. Employer
or organization) Identification No.)
1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas 72702-1408
(Address of principal executive offices, including zip code)
(501) 521-1141
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year; if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes: X No:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding at November 5, 1998
---------------------------- -------------------------------
Common Stock, Par Value $.10 24,931,337
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- 1 -
<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
------------ ---------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 840 $ 4,603
Accounts receivable 21,868 45,752
Income taxes receivable 3,653 3,074
Inventories, at average cost 23,794 20,465
Under-recovered purchased gas costs, net - 9,428
Other 4,219 4,633
--------- ---------
Total current assets 54,374 87,955
--------- ---------
Investments 12,377 7,039
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 741,332 708,094
Gas distribution systems 216,053 212,779
Gas in underground storage 25,794 23,748
Other 26,206 25,319
--------- ---------
1,009,385 969,940
Less: Accumulated depreciation,
depletion and amortization 468,254 366,638
--------- ---------
541,131 603,302
--------- ---------
Other Assets 11,987 12,570
--------- ---------
Total Assets $ 619,869 $ 710,866
========= =========
</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>
September 30, December 31,
1998 1997
------------- ---------
($ in thousands)
<S> <C> <C>
Current Liabilities
Current portion of long-term debt $ 3,071 $ 3,071
Accounts payable 24,007 29,903
Taxes payable 3,282 3,893
Interest payable 7,080 2,569
Customer deposits 5,233 5,307
Other 5,704 4,246
--------- ---------
Total current liabilities 48,377 48,989
--------- ---------
Long-Term Debt, less current portion above 267,371 296,472
--------- ---------
Other Liabilities
Deferred income taxes 118,279 139,256
Other 3,874 4,584
--------- ---------
122,153 143,840
--------- ---------
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 21,252 21,475
Retained earnings 190,382 230,669
Less: Common stock in treasury, at cost
2,804,259 shares in 1998 and
2,904,519 shares in 1997 31,253 32,357
Unamortized cost of 137,588
restricted shares in 1998
and 90,375 restricted shares
in 1997, issued under stock
incentive plan 1,187 996
--------- ---------
181,968 221,565
--------- ---------
Total Liabilities and Shareholders' Equity $ 619,869 $ 710,866
========= =========
</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 Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues
Gas sales $ 27,974 $ 27,876 $ 123,268 $ 129,318
Gas marketing 21,851 16,264 56,556 44,287
Oil sales 2,138 3,295 7,482 10,978
Gas transportation and other 1,588 1,209 5,535 4,224
---------- ---------- ---------- ---------
53,551 48,644 192,841 188,807
---------- ---------- ---------- ---------
Operating Costs and Expenses
Gas purchases - utility 3,588 2,773 26,258 30,049
Gas purchases - marketing 21,199 15,877 54,525 42,591
Operating and general 13,865 14,019 45,606 42,755
Depreciation, depletion and amortization 10,356 11,123 35,794 34,952
Write-down of oil and gas properties - - 66,383 -
Taxes, other than income taxes 1,629 1,731 5,273 5,156
---------- ---------- ---------- ---------
50,637 45,523 233,839 155,503
---------- ---------- ---------- ---------
Operating Income (Loss) 2,914 3,121 (40,998) 33,304
---------- ---------- ---------- ---------
Interest Expense 4,457 4,114 12,645 11,845
---------- ---------- ---------- ---------
Other Income (Expense) (638) (1,068) (2,614) (3,441)
---------- ---------- ---------- ---------
Income (Loss) Before Provision for Income Taxes (2,181) (2,061) (56,257) 18,018
---------- ---------- ---------- ---------
Income Tax Provision (Benefit)
Current (4,705) (4,801) (817) 1,497
Deferred 3,855 4,007 (21,123) 5,440
---------- ---------- ---------- ---------
(850) (794) (21,940) 6,937
---------- ---------- ---------- ---------
Net Income (Loss) $ (1,331) $ (1,267) $(34,317) $ 11,081
========== ========== ========== ==========
Basic Earnings (Loss) Per Share ($0.05) ($0.05) ($1.38) $ .45
====== ====== ====== =====
Weighted Average Common Shares Outstanding 24,892,778 24,742,129 24,865,375 24,732,972
========== ========== ========== ==========
Diluted Earnings (Loss) Per Share $(0.05) ($0.05) $(1.38) $ .45
====== ====== ====== =====
Diluted Weighted Average Common
Shares Outstanding 24,892,778 24,742,129 24,865,375 24,846,650
========== ========== ========== ==========
Dividends Declared Per Share Payable 11/5/98
and 11/5/97 $ .06 $ .06 $ .06 $ .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>
Nine Months Ended
September 30,
1998 1997
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income (loss) $(34,317) $ 11,081
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 36,790 35,732
Write-down of oil and gas properties 66,383 -
Deferred income taxes (21,123) 5,440
Equity in loss of partnership 2,618 3,169
Change in assets and liabilities:
Decrease in accounts receivable 23,884 11,589
(Increase) decrease in income taxes receivable (579) 4,235
Increase in inventories (3,329) (4,382)
(Increase) decrease in under-recovered
purchased gas costs 9,734 (7,612)
Increase (decrease) in accounts payable (5,896) 3,683
Increase in interest payable 4,511 4,898
Net change in other current assets
and liabilities 881 (2,546)
-------- --------
Net cash provided by operating activities 79,557 65,287
-------- --------
Cash Flows From Investing Activities
Capital expenditures (41,641) (64,751)
Investment in partnership (7,955) (3,726)
Increase in gas stored underground (2,046) (1,112)
Other items 3,392 (117)
-------- --------
Net cash used in investing activities (48,250) (69,706)
-------- --------
Cash Flows From Financing Activities
Decrease in revolving long-term debt (29,100) (66,700)
Issuance of long-term debt - 75,000
Cash dividends (5,970) (4,451)
-------- --------
Net cash provided (used) in financing activities (35,070) 3,849
-------- --------
Decrease in cash (3,763) (570)
Cash at beginning of year 4,603 2,297
-------- --------
Cash at end of period $ 840 $ 1,727
======== ========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 6 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
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 1997
Annual Report to Shareholders, Notes to Financial Statements.
Certain reclassifications have been made to the September 30, 1997,
financial statements in order to conform with the 1998 presentation.
These reclassifications had no effect on previously reported net
income.
2. CONTINGENCIES AND COMMITMENTS
The Company announced on October 16, 1998, that a state court jury in
Fort Smith, Arkansas, by a vote of nine to three, returned a verdict
against the Company and two of its wholly-owned subsidiaries, SEECO,
Inc. and Arkansas Western Gas Company, in the amount of $62.1 million.
The trial judge subsequently awarded pre-judgment interest in an amount
of $31.1 million, and post-judgment interest accrued from the date of
the judgment at the rate of 10% per annum simple interest. The Company
has been required by the state court to post a judgment bond in the
amount of $102.5 million (verdict amount plus pre-judgment interest and
one year of post-judgment interest) in order to stay the jury's verdict
and proceed with an appeal process. Subject to court approval, the bond
will be placed by a surety company and will be collateralized by
unsecured letters of credit.
The verdict was returned following a trial on the issues of a class
action lawsuit brought by certain royalty owners of SEECO, Inc., who
contend that since 1979 the defendants breached implied covenants in
certain oil and gas leases, misrepresented or failed to disclose
material facts to royalty owners concerning gas purchase contracts
between the Company's subsidiaries, and failed to fulfill other alleged
common law duties to the members of the royalty owner plaintiff class.
The litigation was commenced in May 1996 and was disclosed by the
Company at that time.
The Company believes that the jury's verdict was wrong as a matter of
law and fact and that incorrect rulings by the trial judge (including
evidentiary rulings and prejudicial jury instructions) provide
substantial grounds for a successful appeal. The Company has asked the
trial judge to recuse himself due to his apparent bias toward the
plaintiffs and has also filed a motion with the trial court for
judgement notwithstanding the verdict or, in the alternative, for a new
trial. The Company has obtained a temporary stay of the judgment on the
jury's verdict and intends to file and vigorously prosecute an appeal
in the Arkansas
- 7 -
<PAGE>
Supreme Court if its post trial motions are denied. The Company expects
that an indefinite stay pending appeal will be approved by the state
court trial judge upon approval of the bond. If the Company is not
successful in post trial motions and its appeal from the jury verdict,
the Company's financial condition and results of operations would be
materially and adversely affected.
3. OIL AND GAS PROPERTIES
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. Such capitalized costs do
not include costs related to unevaluated properties. At September 30,
1998, the Company's unamortized costs of oil and gas properties
exceeded this ceiling amount by approximately $40.1 million (net of
taxes) due primarily to low oil and gas prices. However, the ceiling
limitation was recalculated using October, 1998 prices, as prescribed
by SEC guidelines, and, as a result, the Company's unamortized costs of
oil and gas properties did not exceed this recomputed ceiling amount.
4. EARNINGS PER SHARE
The Company has adopted Financial Accounting Standards Board Statement
No. 128, "Earnings Per Share" (SFAS No. 128). 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 impact of the
adoption of SFAS No. 128 had no effect on reported earnings per share
for the three month and nine month periods ended September 30, 1998 and
1997.
5. COMPREHENSIVE INCOME
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130, "Reporting Comprehensive
Income" (SFAS No. 130), establishing standards for reporting and
display of comprehensive income and its components in financial
statements. SFAS No. 130 defines comprehensive income as the total of
net income and all other nonowner changes in equity. The Company had no
nonowner changes in equity other than net income during the nine months
ended September 30, 1998 and 1997.
- 8 -
<PAGE>
6. DERIVATIVE AND HEDGING ACTIVITIES
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 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 must 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,
1999. A company may also implement the statement as of the beginning of
any fiscal quarter after issuance (that is, fiscal quarters beginning
June 16, 1998 and thereafter). SFAS No. 133 cannot be applied
retroactively and must be applied to (a) derivative instruments and (b)
certain derivative instruments embedded in hybrid contracts that were
issued, acquired, or substantively modified after December 31, 1997
(and, at the company's election, before January 1, 1998).
The Company has not yet quantified the impacts of adopting SFAS No. 133
on its financial statements, nor has it determined the timing of or
method of adoption. However, it should be noted that SFAS No. 133 could
increase volatility in future reported earnings and other comprehensive
income.
7. DIVIDEND PAYABLE
A dividend of $.06 per share was declared September 11, 1998, payable
November 5, 1998.
8. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
<TABLE>
<CAPTION>
Three months Nine months
Periods Ended September 30 1998 1997 1998 1997
- ---------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Interest payments $145 $431 $9,926 $9,276
Income tax payments $907 $3,025 $3,249 $3,409
</TABLE>
- 9 -
<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, 1997, and
analyzes the changes in the results of operations between the three and nine
month periods ended September 30, 1998, and the comparable periods of 1997.
RESULTS OF OPERATIONS
The Company reported a net loss of $1.3 million, or $.05 per share, for the
third quarter of 1998, even with the same period in 1997. The loss reflects the
seasonal nature of both natural gas prices and consumption by the Company's
utility customers. The Company reported a net loss of $34.3 million, or $1.38
per share, for the nine months ended September 30, 1998. The loss for the nine
months reflects the impact of an after-tax, non-cash ceiling test write-down of
the Company's oil and gas properties of $40.5 million, or $1.63 per share,
recorded in the second quarter of 1998. Excluding the non-cash charge, the
Company would have recognized net income for the nine months ended September 30,
1998, of $6.2 million, or $.25 per share, down from net income of $11.1 million,
or $.45 per share, for the same period in 1997. The decrease in earnings
(excluding the non-cash charge) was primarily due to lower wellhead prices for
both oil and gas.
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. Such capitalized costs do
not include costs related to unevaluated properties. At September 30, 1998, the
Company's unamortized costs of oil and gas properties exceeded this ceiling
amount by approximately $40.1 million (net of taxes) due primarily to low oil
and gas prices. However, the ceiling limitation was recalculated using October,
1998 prices, as prescribed by SEC guidelines, and, as a result, the Company's
unamortized costs of oil and gas properties did not exceed this recomputed
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.
The following tables compare operating revenues and operating income (before the
effects of the second quarter write-down of oil and gas properties) by business
segment for the three and nine month periods ended September 30, 1998 and 1997:
- 10 -
<PAGE>
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
--------------------- --------------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Revenues
Exploration and production $18,975 $20,324 $64,382 $70,239
Gas distribution 16,711 18,791 95,263 103,970
Energy services and other 27,250 20,779 71,132 56,315
Eliminations (9,385) (11,250) (37,936) (41,717)
------- ------- -------- --------
$53,551 $48,644 $192,841 $188,807
======= ======= ======== ========
Operating Income
Exploration and production $ 4,345 $ 4,942 $ 13,966 $ 22,044
Gas distribution (1,818) (2,021) 10,173 10,173
Energy services and other 387 200 1,246 1,087
------- ------- -------- --------
$ 2,914 $ 3,121 $ 25,385 $ 33,304
======= ======= ======== ========
</TABLE>
Exploration and Production
Revenues of the exploration and production segment were down 7% for the three
month period ended September 30, 1998, and were down 8% for the nine month
period ended September 30, 1998, both as compared to the same periods in 1997.
Operating income of this segment was down $.6 million for the three months ended
September 30, 1998, and excluding the write-down of oil and gas properties, was
down $8.1 million for the nine months ended September 30, 1998, both as compared
to the same periods in 1997. Gas production for the three months ended September
30, 1998, was 7.6 Bcf, even with the same period in 1997. For the nine months
ended September 30, 1998, gas production was 24.3 Bcf, compared to 24.2 Bcf in
1997. The Company's sales to its utility distribution systems were 8.5 Bcf
during the nine months ended September 30, 1998, compared to 10.1 Bcf for the
same period in 1997. The decline in sales to the utility segment was primarily
the result of weather that was 11% warmer than in 1997.
Southwestern received an average price of $2.22 per Mcf for its gas production
during the three months ended September 30, 1998, down from $2.25 per Mcf for
the same period in 1997. The Company received an average price of $2.34 per Mcf
for its gas production during the nine months ended September 30, 1998, down
from $2.45 per Mcf for the same period in 1997. The Company's average price was
enhanced by 30 cents per Mcf for the quarter and 22 cents per Mcf for the first
nine months of 1998 as a result of the Company's hedging activities. The Company
hedged approximately 80% of its floating price gas production through September,
1998. For the period of October, 1998 through March, 1999, the Company has
hedged approximately 1.4 Bcf per month at an average NYMEX price of $2.51 per
Mcf.
Most of the intersegment gas sales to Arkansas Western Gas Company (AWG), the
utility subsidiary that operates the Company's northwest Arkansas utility
system, are pursuant to a long-term contract entered into in 1978 which was
amended and restated in 1994. SEECO, one of the Company's exploration and
production subsidiaries, sold 5.6 Bcf under this contract at an average
- 11 -
<PAGE>
price of $2.92 per Mcf in the first nine months of 1998, compared to 5.9 Bcf at
an average price of $3.42 per Mcf for the same period in 1997. This contract
expired July 24, 1998, but is being continued on a month-to-month basis through
November, 1998. In March, 1997, AWG filed a gas supply plan with the Arkansas
Public Service Commission (APSC) which projects system load growth patterns and
long range gas supply needs for the utility's northwest Arkansas system. The gas
supply plan also addressed replacement supplies for AWG's long-term contract
with SEECO. After discussions with the APSC it was determined that the majority
of the utility's future gas supply needs should be provided through a
competitive bidding process. On October 1, 1998, AWG sent requests for proposal
to various suppliers requesting bids on seven different packages of gas supply
to be effective December 1, 1998. These bid requests included replacement of the
gas supply and no-notice service previously provided by the long-term gas supply
contract between AWG and SEECO. Eleven potential suppliers returned bids in late
October.
SEECO along with the Company's energy services subsidiary successfully bid on
five of the seven packages with prices based on the NorAm East Index plus a
demand charge. The volumes of gas projected to be sold under these contracts in
their first year are approximately equal to the historical annual volumes sold
under the expired long-term contract. However, the volumes to be sold under
these contracts are not fixed as they were under the expired contract. The total
premium over the NorAm East Index under these contracts is estimated to be
approximately $1.0 million lower (after tax) than the annual premium earned
under the expired long-term contract. The majority of the premium will be
received through monthly demand charges ranging from approximately $1.0 million
in December through February to approximately $225,000 per month for the
remainder of the year. These demand charges will be received regardless of
volumes actually delivered. Other sales to AWG are made under long-term
contracts with flexible pricing provisions.
The Company's oil production was 550 thousand barrels (MBbls) during the nine
months ended September 30, 1998, compared to 576 MBbls for the same period of
1997. Southwestern received an average price of $13.60 per barrel for its oil
production during the nine months ended September 30, 1998, down from $19.07 per
barrel for the same period of 1997. The decrease in average price reflects the
general decline in the market price for oil during the first nine months of
1998.
Gas Distribution
Operating income in the third quarter for the gas distribution segment improved
by $.2 million from the level in 1997. Operating income for the first nine
months of 1998 remained even with 1997 results, despite weather that was 12%
warmer than normal and 11% warmer than last year. The utility systems delivered
22.4 Bcf to sales and end-use transportation customers during the nine months
ended September 30, 1998, down from 23.0 Bcf for the same period in 1997. Rate
increases and tariff changes totaling $3.0 million annually implemented in late
1997 helped offset the effect of decreased deliveries due to warmer weather. The
utility also realized 2% growth in the average number of customers.
The Company's average rate for its utility sales increased to $5.62 per Mcf
during the first nine months of 1998, up from $5.39 per Mcf for the same period
in 1997. The increase was the result
- 12 -
<PAGE>
of the rate increases discussed above and the effects of weather normalization
clauses included in the rate tariffs of Arkansas customers.
Energy Services
Operating income for the energy services segment was $.3 million on revenues of
$27.1 million for the third quarter of 1998, compared to $.2 million on revenues
of $20.7 million for the same period in 1997. For the nine months ended
September 30, 1998, operating income for this segment was $1.1 million on
revenues of $70.8 million, compared to $1.1 million on revenues of $56.1 million
for the same period in 1997. The Company marketed 36.4 Bcf of gas in the first
nine months of 1998, compared to 26.1 Bcf for the same period in 1997. The
higher margins in relation to revenue levels realized during 1997 primarily
relate to income realized from the Company's unregulated storage facilities
which were utilized to take advantage of the higher gas prices available at that
time.
A portion of the activity of the energy services segment involves the NOARK
Pipeline System (NOARK). The Company's share of NOARK's pre-tax loss included in
other income was $.9 million for the third quarter of 1998 and $2.6 million for
the first nine months of 1998, compared to $1.2 million and $3.2 million,
respectively, for the same periods in 1997. The improvement in NOARK's pre-tax
loss for the first nine months of 1998 primarily reflects a lower interest rate
on NOARK's debt which resulted from a refinancing discussed below in "Changes in
Financial Condition".
In January, 1998, the Company entered into an agreement with Enogex Inc.
(Enogex), a subsidiary of OGE Energy Corp., to expand the NOARK system and
provide access to Oklahoma gas supplies through an integration of NOARK with the
Ozark Gas Transmission System (Ozark). Ozark is a 437-mile interstate pipeline
system which begins in eastern Oklahoma and terminates in eastern Arkansas. On
July 1, 1998, the Federal Energy Regulatory Commission (FERC) authorized the
operation and integration of the Ozark pipeline and the NOARK pipeline as a
single, integrated pipeline. The FERC order also authorized the purchase of
Ozark by a subsidiary of Enogex and the construction of integration facilities.
Effective August 1, 1998, Enogex acquired Ozark and contributed the pipeline
system to the NOARK partnership. Enogex has also acquired the NOARK partnership
interests not held by Southwestern. In addition to its purchase of Ozark, Enogex
funded the integration project and an expansion of the combined system. Enogex
spent approximately $70 million to acquire Ozark and integrate it with NOARK.
The integrated system became operational November 1, 1998, and includes 749
miles of pipeline with a total throughput capacity of 330 MMcfd.
Effective November 1, 1998, the Company's interest in the expanded project
decreased to 25% with Enogex owning a 75% interest. After its start-up period,
the Company expects the improved project to significantly reduce the losses it
has been experiencing on its NOARK investment.
Operating Costs and Expenses
Operating costs and expenses increased 11% in the third quarter of 1998 and
increased 8% for the first nine months of 1998 (excluding the impact of the
write-down of oil and gas properties), both as compared to the comparable
periods in 1997. The increase in the third quarter was
- 13 -
<PAGE>
primarily caused by increased gas purchases by the gas distribution and energy
services segments, partially offset by lower depreciation, depletion and
amortization expense. The increase in the year-to-date expense was primarily due
to increased gas purchases in the energy services segment, increased operating
and general expenses and higher depreciation, depletion and amortization
expense, offset by lower purchased gas costs of the gas distribution segment.
The increase in operating and general expenses for the first nine months of 1998
was due primarily to increased payroll and benefit costs, and for employee
termination benefits and other costs incurred in connection with the closing of
the Company's Oklahoma City exploration and production office. The activities of
this office were consolidated into the Company's Houston office. The increase in
depreciation, depletion and amortization expense was due to an increase in the
amortization rate per unit of production in the exploration and production
segment for the nine month period ended September 30, 1998. The Company's
amortization rate, excluding the impact of the write-down of oil and gas
properties, was $1.07 per Mcf equivalent for the first nine months of 1998,
compared to $1.05 for the same period in 1997. Due primarily to the write-down
of its property costs in the second quarter of 1998, the Company's amortization
rate for the third quarter of 1998 was $.96 per Mcf equivalent compared to $1.06
for the same period in 1997. The future amortization rate will be impacted by
the level of reserve additions and costs added to the full cost pool.
Interest expense, net of capitalization, for the nine months ended September 30,
1998, was up 7% compared to the same period in 1997, due to slightly higher
average borrowings. Interest is capitalized in the exploration and production
segment on costs that are unevaluated and excluded from amortization. The
Company's capitalized interest for this segment was down $.4 million, or 36%, in
the third quarter of 1998 as compared to the prior year. This decrease was due
to the transfer of approximately $27.2 million of previously unevaluated costs
to the amortizable full cost pool in the second quarter of 1998.
The previously discussed second quarter write-down of the Company's oil and gas
properties resulted in a deferred tax benefit of $25.9 million. Excluding the
impact of this change in deferred income taxes, the changes in the provisions
for current and deferred income taxes recorded in the three and nine month
periods ended September 30, 1998, as compared to the same periods in 1997,
resulted primarily from the level of taxable income and from 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.
Year 2000
The year 2000 problem impacts most companies as many informational and
operational systems that currently exist will be unable to continue processing
in the year 2000 due to the improper recognition of calendar dates. The Company
began an initial review in late 1996 of its processing systems and the ability
of those systems to process year 2000 data. The primary financial information
systems of the Company that are supported by outside vendors are designed to
accommodate the century date or are scheduled for an upgrade in 1998 to a year
2000 compliant version at no additional cost to the Company. The Company is
currently testing these upgrades
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<PAGE>
and expects these systems to be year 2000 compliant by the end of 1998. Other
information systems supported internally by the Company are either scheduled for
replacement at which time they will become year 2000 compliant or they will be
subject to modification to support year 2000 processing during 1998.
Implementation and final testing of these systems is expected to be completed no
later than mid-year 1999. The total costs associated with the modification of
these systems are expected to be approximately $.8 million. Of this amount,
approximately $.5 million relates to planned improvements that were not directly
related to the year 2000 problem.
The Company has also identified internal processes and areas of non-information
technology (e.g. equipment with embedded chips) that require modification to
process year 2000 data or that require further assessment. The Company is
replacing the operating system of its personal computers to the NT version of
Windows, which will also result in the replacement of noncompliant personal
computers and the related software that is not already year 2000 compliant. This
rollout of NT was a scheduled replacement not directly related to the year 2000
problem. It is expected to be completed by the end of 1998 at an estimated cost
of $.6 million. An assessment is underway in other non-information technology
areas related to electronic meter reading and field measurement. Currently,
replacement of electronic meter reading equipment is estimated to cost
approximately $.3 million and is expected to be completed by the end of 1998.
The Company has not completed its estimate of the timing and costs related to
its field measurement equipment, but it is not expected to have a material
impact on the Company's financial condition or its results of operations.
The highest risk area for the Company related to the year 2000 issues is
noncompliance by third parties. At this time, the most reasonably likely worst
case scenario would be year 2000 noncompliance by third parties that comprised a
significant level of business conducted with the Company. Depending upon the
level of noncompliance, the Company could be adversely impacted by such things
as late or incorrect revenue receipts or expense disbursements, communication
problems, or scheduling or delivery problems related to the transportation and
distribution of natural gas. The Company is addressing this risk through
communication with industry partners, suppliers, financial institutions and
others. The major risk areas associated with third party noncompliance have been
identified, and the third parties within these areas have been further
risk-weighted based upon the Company's level of business reliance. These third
parties are being contacted and the Company is in the process of evaluating
responses and corresponding with those parties that have not responded or that
have responded inadequately. As this process continues, the Company will develop
contingency plans that it deems necessary based on its evaluations of third
party readiness. The Company expects to have this process completed with any
necessary contingency plans in place by mid-year 1999. No such contingency plans
have been developed to date. Based upon its assessment of third party assurances
at this time, the Company does not anticipate any material disruptions in its
business activities as a result of third party year 2000 noncompliance, although
it cannot be certain that such disruptions will not occur. If such disruptions
do occur, the materiality of their impact on the Company's financial condition
and results of operations will depend on the extent and duration of the
disruptions and the nature of any legal proceedings resulting from the
disruptions.
- 15 -
<PAGE>
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at September 30, 1998, as compared
to December 31, 1997, primarily reflect the seasonal nature of the gas
distribution segment of the Company's business.
Routine capital expenditures, cash dividends and scheduled debt retirements are
predominately funded through cash provided by operations. For the first nine
months of 1998 and 1997, net cash provided by operating activities was $79.6
million and $65.3 million, respectively, and exceeded the total of these routine
requirements. The increase in net cash provided by operating activities during
the first nine months of 1998 was largely due to the utility segment's
collection of $9.7 million of gas costs incurred during 1997, but deferred for
collection until 1998 pursuant to the utility's purchased gas adjustment clauses
in its filed rate tariffs. The Company had net over-recovered purchased gas
costs of $.3 million at September 30, 1998, recorded in other current
liabilities. At December 31, 1997, the Company had net under-recovered purchased
gas costs of $9.4 million. This amount was classified as a current asset.
Financing Requirements
The Company has access to $80.0 million of medium to long-term capital at
current market lending rates through two floating rate credit facilities. Of
this amount, $17.3 million was outstanding at September 30, 1998, all of which
was classified as long-term debt. During the first nine months of 1998, the
Company's revolving long-term debt decreased by $29.1 million primarily due to
cash flow generated by seasonally high utility revenues and the collection of
deferred gas costs discussed above. Due primarily to the second quarter
write-down of the Company's oil and gas properties, shareholders' equity
decreased by $39.6 million, as compared to December 31, 1997. As a result,
long-term debt at September 30, 1998, accounted for 59.5% of the Company's
capitalization, up from 57.2% at December 31, 1997.
The Company's capital expenditures for the first nine months of 1998 were $41.6
million, down from $64.8 million for the same period in 1997. The decrease
primarily relates to reduced capital expenditures by the Company's exploration
and production segment. Planned capital spending during 1998 is expected to be
approximately $20.0 million lower than actual 1997 spending.
In connection with the Enogex transaction discussed above, the Company and a
previous general partner converted certain of their loans to the NOARK
partnership, plus accrued interest, into equity, and contributed approximately
$10.7 million to the partnership to fund costs incurred in connection with the
prepayment of NOARK's 9.74% Senior Secured Notes. The Company's share of the
contribution was $6.5 million and is the primary reason for the increase in
investments during the first nine months of 1998. The notes were temporarily
refinanced with Senior Secured Notes payable to the other current general
partner of NOARK. In June, 1998, the NOARK partnership issued $80.0 million of
7.15% Notes due 2018. Proceeds from the issue of the notes were used to repay
the Senior Secured Notes and amounts borrowed under the partnership's bank
revolving line of credit. The notes require semi-annual principal payments of
$1.0 million beginning in December, 1998. The Company and the other general
partner of
- 16 -
<PAGE>
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, 1997, due primarily to
seasonally lower deliveries of the gas distribution segment. Accounts payable
has decreased since December 31, 1997 due to the seasonally lower gas purchases
for the gas distribution segment and due to the timing of expenditures. 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 and Section 21E of the Securities Exchange Act of 1934.
These statements reflect the Company's current views with respect to future
events and performance. The Company believes that its expectations are based on
reasonable assumptions. No assurances, however can be given that its goals will
be achieved. Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include (1) the
timing and extent of changes in commodity prices for gas and oil and interest
rates, (2) the timing and extent of the Company's success in discovering,
developing, producing, and estimating reserves, (3) the effects of weather and
regulation on the Company's gas distribution segment, and (4) conditions in
capital markets, availability of oil field services, drilling rigs, and other
equipment, as well as other competitive factors during the periods covered by
the forward-looking statements.
- 17 -
<PAGE>
PART II
OTHER INFORMATION
Item 1 - Legal Proceedings
As previously disclosed in its Form 8-K filed October 16, 1998, a state court
jury in Fort Smith, Arkansas, by a vote of nine to three, returned a verdict
against the Company and two of its wholly-owned subsidiaries, SEECO, Inc. and
Arkansas Western Gas Company, in the amount of $62.1 million. The trial judge
subsequently awarded pre-judgment interest in an amount of $31.1 million and
post-judgment interest accrued from the date of the judgment at the rate of 10%
per annum simple interest. The Company has been required by the state court to
post a judgment bond in the amount of $102.5 million (verdict amount plus
pre-judgment interest and one year of post-judgment interest) in order to stay
the jury's verdict and proceed with an appeal process. Subject to court
approval, the bond will be placed by a surety company and will be collateralized
by unsecured letters of credit.
The verdict was returned following a trial on the issues of a class action
lawsuit brought by certain royalty owners of SEECO, Inc., who contend that since
1979 the defendants breached implied covenants in certain oil and gas leases,
misrepresented or failed to disclose material facts to royalty owners concerning
gas purchase contracts between the Company's subsidiaries, and failed to fulfill
other alleged common law duties to the members of the royalty owner plaintiff
class. The litigation was commenced in May 1996 and was disclosed by the Company
at that time.
The Company believes that the jury's verdict was wrong as a matter of law and
fact and that incorrect rulings by the trial judge (including evidentiary
rulings and prejudicial jury instructions) provide substantial grounds for a
successful appeal. The Company has asked the trial judge to recuse due to his
apparent bias toward the plaintiffs and has also filed a motion with the trial
court for judgement notwithstanding the verdict or, in the alternative, for a
new trial. The Company has obtained a temporary stay of the judgment on the
jury's verdict and intends to file and vigorously prosecute an appeal in the
Arkansas Supreme Court if its post trial motions are denied. The Company expects
that an indefinite stay pending appeal will be approved by the state court trial
judge upon approval of the bond.
If the Company is not successful in post trial motions and its appeal from the
jury verdict, the Company's financial condition and results of operations would
be materially and adversely affected.
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. In September 1998, another party who opted out of the class
threatened the Company with similar litigation. While the amounts of these
pending and threatened claims could be material,
- 18 -
<PAGE>
management believes, based on its investigations, that the Company's ultimate
liability, if any, will not be material to its consolidated financial position
or results of operations.
The United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the class action litigation. MMS was included in the class action
litigation against its objections, but has not pursued further action to remove
itself from the class. If MMS does remove itself from the class, its claims may
be brought separately under federal statutes that provide for treble damages and
civil penalties. In such event, the Company believes it would have defenses that
were not available in the class action litigation. While the aggregate amount of
MMS's claims could be material, management believes, based on its
investigations, 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 September 30, 1998.
Item 6(b)
On October 16, 1998, the Company filed a current report on Form 8-K dated
October 15, 1998, announcing the verdict of a state court jury in a class action
royalty lawsuit against Southwestern Energy Company and two of its subsidiaries.
The verdict is discussed above in Item 1 of Part II.
On October 30, 1998, the Company filed a current report on Form 8-K dated
October 29, 1998, announcing the appointment by the Company's Board of Directors
of Harold Korell to replace Charles E. Scharlau as Chief Executive Officer of
the Company effective January 1, 1999. Mr. Korell was also elected to the
Company's Board of Directors effective immediately.
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
Registrant
DATE: November 16, 1998 /s/ GREGORY D. KERLEY
-------------------------------
Gregory D. Kerley
Senior Vice President - Finance
and Chief Financial Officer
- 19 -
<PAGE>
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<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1998
<CASH> 840
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<RECEIVABLES> 21,868
<ALLOWANCES> 0
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<CURRENT-ASSETS> 54,374
<PP&E> 1,009,385
<DEPRECIATION> (468,254)
<TOTAL-ASSETS> 619,869
<CURRENT-LIABILITIES> 48,377
<BONDS> 267,371
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0
<COMMON> 2,774
<OTHER-SE> 179,194
<TOTAL-LIABILITY-AND-EQUITY> 619,869
<SALES> 187,306
<TOTAL-REVENUES> 192,841
<CGS> 0
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<INTEREST-EXPENSE> 12,645
<INCOME-PRETAX> (56,257)
<INCOME-TAX> (21,940)
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<EPS-PRIMARY> (1.38)
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The information has been prepared in accordance with SFAS No. 128.
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