<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 June 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 August 5, 1998
---------------------------- ----------------------------
Common Stock, Par Value $.10 24,882,534
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<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
June 30, December 31,
1998 1997
--------- ---------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 1,976 $ 4,603
Accounts receivable 24,187 45,752
Income taxes receivable - 3,074
Inventories, at average cost 19,358 20,465
Under-recovered purchased gas costs, net - 9,428
Other 4,041 4,633
--------- ---------
Total current assets 49,562 87,955
--------- ---------
Investments 12,676 7,039
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 729,285 708,094
Gas distribution systems 216,073 212,779
Gas in underground storage 24,054 23,748
Other 25,643 25,319
--------- ---------
995,055 969,940
Less: Accumulated depreciation,
depletion and amortization 458,395 366,638
--------- ---------
536,660 603,302
--------- ---------
Other Assets 12,785 12,570
--------- ---------
Total Assets $ 611,683 $ 710,866
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
June 30, December 31,
1998 1997
--------- ---------
($ in thousands)
<S> <C> <C>
Current Liabilities
Current portion of long-term debt $ 3,071 $ 3,071
Accounts payable 28,083 29,903
Taxes payable 4,900 3,893
Interest payable 2,353 2,569
Customer deposits 5,153 5,307
Over-recovered purchased gas costs, net 149 -
Other 4,242 4,246
--------- ---------
Total current liabilities 47,951 48,989
--------- ---------
Long-Term Debt, less current portion above 259,071 296,472
--------- ---------
Other Liabilities
Deferred income taxes 114,270 139,256
Other 4,432 4,584
--------- ---------
118,702 143,840
--------- ---------
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 21,444 21,475
Retained earnings 194,702 230,669
Less: Common stock in treasury, at cost
2,863,080 shares in 1998 and
2,904,519 shares in 1997 31,895 32,357
Unamortized cost of 107,998
restricted shares in 1998
and 90,375 restricted shares
in 1997, issued under stock
incentive plan 1,066 996
--------- ---------
185,959 221,565
--------- ---------
Total Liabilities and Shareholders' Equity $ 611,683 $ 710,866
========= =========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
1998 1997 1998 1997
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues
Gas sales $ 32,412 $ 32,180 $ 95,294 $ 101,442
Gas marketing 19,504 14,020 34,705 28,023
Oil sales 2,575 3,667 5,344 7,683
Gas transportation and other 1,843 1,377 3,947 3,015
---------- ---------- ---------- ---------
56,334 51,244 139,290 140,163
---------- ---------- ---------- ---------
Operating Costs and Expenses
Gas purchases - utility 3,983 4,993 22,670 27,276
Gas purchases - marketing 19,054 13,602 33,326 26,714
Operating and general 16,612 14,388 31,741 28,736
Depreciation, depletion and amortization 12,399 11,543 25,438 23,829
Write-down of oil and gas properties 66,383 - 66,383 -
Taxes, other than income taxes 1,738 1,629 3,644 3,425
---------- ---------- ---------- ---------
120,169 46,155 183,202 109,980
---------- ---------- ---------- ---------
Operating Income (Loss) (63,835) 5,089 (43,912) 30,183
---------- ---------- ---------- ---------
Interest Expense 4,010 3,745 8,188 7,731
---------- ---------- ---------- ---------
Other Income (Expense) (1,103) (1,296) (1,976) (2,373)
---------- ---------- ---------- ---------
Income (Loss) Before Provision for Income Taxes (68,948) 48 (54,076) 20,079
---------- ---------- ---------- ---------
Income Tax Provision (Benefit)
Current (1,418) (243) 3,888 6,298
Deferred (25,472) 262 (24,978) 1,433
---------- ---------- ---------- ---------
(26,890) 19 (21,090) 7,731
---------- ---------- ---------- ---------
Net Income (Loss) $ (42,058) $ 29 $ (32,986) $ 12,348
========== ========== ========== ==========
Basic Earnings (Loss) Per Share ($1.70) $ .00 ($1.33) $ .50
====== ===== ====== =====
Weighted Average Common Shares Outstanding 24,859,789 24,736,398 24,851,447 24,728,318
========== ========== ========== ==========
Dilutive Earnings (Loss) Per Share $(1.70) $ .00 $(1.33) $ .50
====== ===== ====== =====
Dilutive Weighted Average Common
Shares Outstanding 24,859,789 24,834,804 24,851,447 24,855,471
========== ========== ========== ==========
Dividends Declared Per Share Payable 8/5/98
and 8/5/97 $ .06 $ .06 $ .06 $ .06
===== ===== ===== =====
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
<TABLE>
<CAPTION>
Six Months Ended
June 30,
1998 1997
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income (loss) $(32,986) $ 12,348
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 25,578 23,969
Write-down of oil and gas properties 66,383 -
Deferred income taxes (24,978) 1,433
Equity in loss of partnership 1,706 2,014
Change in assets and liabilities:
Decrease in accounts receivable 21,565 17,102
Decrease in income taxes receivable 4,751 11,584
Decrease in inventories 1,107 1,111
(Increase) decrease in under-recovered
purchased gas costs 9,577 (5,878)
Increase (decrease) in accounts payable (1,820) 719
Net change in other current assets
and liabilities (452) (190)
-------- --------
Net cash provided by operating activities 70,431 64,212
-------- --------
Cash Flows From Investing Activities
Capital expenditures (26,414) (41,482)
Investment in partnership (7,343) (2,496)
(Increase) decrease in gas stored underground (306) 2,228
Other items 1,386 563
-------- --------
Net cash used in investing activities (32,677) (41,187)
-------- --------
Cash Flows From Financing Activities
Decrease in revolving long-term debt (37,400) (78,900)
Issuance of long-term debt - 60,000
Cash dividends (2,981) (2,966)
-------- --------
Net cash used in financing activities (40,381) (21,866)
-------- --------
Increase (decrease) in cash (2,627) 1,159
Cash at beginning of year 4,603 2,297
-------- --------
Cash at end of period $ 1,976 $ 3,456
======== ========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
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<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 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 June 30, 1997,
financial statements in order to conform with the 1998 presentation.
These reclassifications had no effect on previously reported net
income.
2. 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 June 30, 1998,
the Company's unamortized costs of oil and gas properties exceeded this
ceiling amount by approximately $40.5 million (net of taxes) due to
lower oil and gas prices and the transfer of previously unevaluated
property costs to the amortizable portion of the full cost pool. As a
result, the Company recognized a $40.5 million non-cash charge to
earnings in the quarter ended June 30, 1998, by recording a write-down
of its oil and gas properties of $66.4 million and a related reduction
in the provision for deferred income taxes of $25.9 million.
3. 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 six month periods ended June 30, 1998 and 1997.
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<PAGE>
4. 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 six months
ended June 30, 1998 and 1997.
5. 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.
6. DIVIDEND PAYABLE
A dividend of $.06 per share was declared July 8, 1998, payable August
5, 1998.
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<PAGE>
7. 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 1998 1997 1998 1997
- ---------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Interest payments $9,280 $7,276 $9,781 $8,845
Income tax payments $2,342 $219 $2,342 $384
</TABLE>
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<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 six
month periods ended June 30, 1998, and the comparable periods of 1997.
RESULTS OF OPERATIONS
The Company reported a net loss of $42.1 million, or $1.70 per share, for the
second quarter of 1998, and a net loss of $33.0 million, or $1.33 per share, for
the six months ended June 30, 1998, reflecting the impact of an after-tax,
non-cash ceiling test write-down of its oil and gas properties of $40.5 million,
or $1.63 per share. Excluding the write-down, the Company would have recognized
a net loss for the three months ended June 30, 1998, of $1.6 million, or $.07
per share, down from net income of $29,000, or $.00 per share, for the same
period in 1997. For the six months ended June 30, 1998, net income would have
been $7.5 million, or $.30 per share, down from to $12.3 million, or $.50 per
share, for the same period in 1997, 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 June 30, 1998, the
Company's unamortized costs of oil and gas properties exceeded this ceiling
amount by approximately $40.5 million (net of taxes) due to lower gas and oil
prices and the transfer of previously unevaluated property costs to the
amortizable portion of the full cost pool. As a result, the Company recognized a
$40.5 million non-cash charge to earnings in the quarter ended June 30, 1998, by
recording a write-down of its oil and gas properties of $66.4 million ($.19 per
equivalent Mcf of existing proved reserves and $3.49 per equivalent Mcf produced
in the first six months) and a related reduction in the provision for deferred
income taxes of $25.9 million. The Company's full cost ceiling is evaluated at
the end of each quarter. If gas and oil prices remain at the current low levels
for a prolonged period, or other changes occur that affect terms of existing
sales contracts, the Company may be required to reflect additional non-cash
charges to earnings in future quarterly periods related to the Company's
unamortized costs of oil and gas properties.
The Company transferred approximately $27.2 million of previously unevaluated
property costs to its amortizable full cost pool during the second quarter of
1998 in connection with the Company's semi-annual impairment review of its
properties. A large portion of the costs
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<PAGE>
transferred were costs incurred over the past two years for 3-D seismic data,
leasehold and lease options related to the Company's Henry project in south
Louisiana. The final processed seismic data for this project was received in
September, 1997. The review and interpretation of this data was completed during
the second quarter of 1998. After the transfer of these costs, net unamortized
costs for unevaluated properties excluded from the amortizable full cost pool at
June 30, 1998, were approximately $47.1 million, down from $69.3 million at
December 31, 1997.
Excluding the impact of the write-down of oil and gas properties, results for
the second quarter 1997 were unfavorably impacted by low oil prices, increased
operating and general expenses, and higher depreciation, depletion and
amortization expense. The following tables compare operating revenues and
operating income (before the effects of the write-down of oil and gas
properties) by business segment for the three and six month periods ended June
30, 1998 and 1997:
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
--------------------- --------------------
1998 1997 1998 1997
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
Revenues
Exploration and production $21,146 $20,633 $45,407 $49,915
Gas distribution 22,528 24,280 78,552 85,179
Energy services and other 24,509 18,553 43,882 35,536
Eliminations (11,849) (12,222) (28,551) (30,467)
------- ------- -------- --------
$56,334 $51,244 $139,290 $140,163
======= ======= ======== ========
Operating Income
Exploration and production $ 3,065 $ 4,667 $ 9,621 $ 17,102
Gas distribution (708) 229 11,991 12,194
Energy services and other 191 193 859 887
------- ------- -------- --------
$ 2,548 $ 5,089 $ 22,471 $ 30,183
======= ======= ======== ========
</TABLE>
Exploration and Production
Revenues of the exploration and production segment were up slightly for the
three month period ended June 30, 1998, and were down 9% for the six month
period ended June 30, 1998, both as compared to the same periods in 1997.
Operating income of this segment, excluding the write-down, was down $1.6
million for the three months ended June 30, 1998, and was down $7.5 million for
the six months ended June 30, 1998, as compared to the same periods in 1997.
Gas production for the three months ended June 30, 1998, was 8.0 Bcf, compared
to 7.9 Bcf for the same period in 1997. For the six months ended June 30, 1998,
gas production was 16.7 Bcf, compared to 16.6 Bcf in 1997. The Company's sales
to its utility distribution systems were 6.9 Bcf during the six months ended
June 30, 1998, compared to 7.6 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 $2.33 per Mcf for
its gas production during the three months ended June 30, 1998, up from $2.13
per Mcf for the same
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<PAGE>
period in 1997. The Company received an average price of $2.39 per Mcf for its
gas production during the six months ended June 30, 1998, down from $2.54 per
Mcf for the same period in 1997.
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. AWG purchased 4.6 Bcf under this contract at an
average price of $3.09 per Mcf in the first six months of 1998, compared to 4.4
Bcf at an average price of $3.32 per Mcf for the same period in 1997. This
contract expired July 24, 1998, but is being continued on a month-to-month basis
pending resolution of the issues described below. In March, 1997, AWG filed a
gas supply plan with the Arkansas Public Service Commission which projects
system load growth patterns and long range gas supply needs for the utility's
northwest Arkansas system. As part of its long range supply plan, AWG proposed a
new intersegment gas supply contract for a similar portion of its system needs
at a price competitive with the cost of alternative supplies. After extensive
negotiations, the issues surrounding AWG's gas supply plan have not yet been
resolved. The Company believes it is likely that these issues will be resolved
in a manner that requires that the gas supply now provided under this contract
be replaced through a competitive bidding process involving multiple potential
suppliers. If this occurs, SEECO's continued sales of these volumes to AWG, and
the price of any such sales, will depend on the result of this competitive
bidding process. Other sales to AWG are made under long-term contracts with
flexible pricing provisions.
The Company's oil production was 387 thousand barrels (MBbls) during the six
months ended June 30, 1998, down slightly from 398 MBbls for the same period of
1997. Southwestern received an average price of $13.82 per barrel for its oil
production during the six months ended June 30, 1998, down from $19.32 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 half of 1998.
Gas Distribution
Operating income of the gas distribution segment decreased $.9 million for the
second quarter of 1998 and $.2 million for the first six months of 1998, as
compared to the same periods in 1997, due primarily to lower volumes delivered
to customers as a result of warmer weather. The utility systems delivered 18.2
Bcf to sales and end-use transportation customers during the six months ended
June 30, 1998, down from 18.7 Bcf for the same period in 1997. Operating income
for the first six months of 1998 remained relatively flat with 1997 results
despite weather that was 10% warmer than normal and 11% warmer than the same
period of 1997. Rate increases and tariff changes totaling $3.0 million annually
implemented in late 1997 largely offset the effect of 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 $5.40 per Mcf
during the first six months of 1998, up from $5.22 per Mcf for the same period
in 1997. The increase was the result of the rate increases discussed above and
the effects of weather normalization clauses included in the rate tariffs of
Arkansas customers.
- 12 -
<PAGE>
Energy Services
Operating income for the energy services segment was $.1 million on revenues of
$24.4 million for the second quarter of 1998, compared to $.2 million on
revenues of $18.5 million for the same period in 1997. For the six months ended
June 30, 1998, operating income for this segment was $.8 million on revenues of
$43.7 million, compared to $.9 million on revenues of $35.4 million for the same
period in 1997. The Company marketed 21.6 Bcf of gas in the first six months of
1998, compared to 16.4 Bcf for the same period in 1997. The higher margins
applicable to the first half of 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 second quarter of 1998 and $1.7 million for
the first six months of 1998, compared to $.9 million and $2.0 million,
respectively, for the same periods in 1997. The improvement in NOARK's pre-tax
loss for the first half 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
will fund the integration project and an expansion of the combined system. The
integrated system will include 749 miles of pipeline and have total throughput
capacity of 330 MMcfd.
The Company, through its wholly owned subsidiary, Southwestern Energy Pipeline
Company, held a 60% general partnership interest in NOARK through July 31, 1998.
The Company's ownership interest in NOARK had temporarily increased from 48% in
January, 1998 as a result of the Enogex transaction. Enogex will spend
approximately $70 million to acquire Ozark and integrate it with NOARK. Upon
completion and funding by Enogex of the integration, the Company's interest in
the partnership will decrease to 25% and Enogex will own a 75% interest. The
parties expect the integrated system to be operational by November 1, 1998.
After a start-up period, the Company expects the improved project to eliminate
the losses it has been experiencing on its NOARK investment.
Operating Costs and Expenses
Excluding the impact of the write-down of oil and gas properties, operating
costs and expenses increased 17% in the second quarter of 1998 and increased 6%
for the first six months of 1998,
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<PAGE>
both as compared to the comparable periods in 1997. The increases were primarily
caused by increased gas purchases by the energy services segment, increased
operating and general expenses and higher depreciation, depletion and
amortization expense, offset by lower purchased gas costs of the Company's gas
distribution segment. The increase in operating and general expenses 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. The Company's amortization rate, excluding the impact of the write-down
of oil and gas properties, was $1.11 per Mcf equivalent for the first six months
of 1998, compared to $1.04 for the same period in 1997. Due to the write-down of
its property costs, the Company's amortization rate will drop below these
levels. 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 six months ended June 30, 1998,
was up 6% 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 will initially be lower going forward 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 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, the changes in the provisions for current and deferred
income taxes recorded in the three and six month periods ended June 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 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. The costs associated with the modification of these
systems is not expected to have a material impact on the Company's financial
condition or its results of operations.
- 14 -
<PAGE>
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
roll-out 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 Company is also evaluating the risk of year 2000 noncompliance by third
parties through communication with industry partners, suppliers, financial
institutions and others. The Company does not have a material relationship with
any single third party entity that would cause a significant business
interruption as a result of that party's year 2000 noncompliance. However, these
third parties have been risk-weighted based upon the historical level of
business transacted with the Company. The Company is now beginning the process
of contacting parties who have not responded to the Company's request for
information or whose responses are inadequate. The parties are being contacted
in order of the perceived risk that is posed to the Company by their potential
year 2000 noncompliance. The Company is taking the above steps to lessen the
risk associated with year 2000 noncompliance by third parties, however, if a
substantial number of third parties in the aggregate were not year 2000
compliant in their processing systems, the Company could be adversely impacted
by such things as late or incorrect revenue receipts or expense disbursements,
communication problems, or scheduling problems related to the transportation of
natural gas. Based upon its assessment to date of third party assurances, the
Company does not anticipate any material disruptions in its business activities
as a result of third party noncompliance, although it cannot be certain that
such disruptions will not occur.
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at June 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 six
months of 1998 and 1997, net cash provided by operating activities was $70.4
million and $64.2 million, respectively, and exceeded the total of these routine
requirements. The increase in net cash provided by operating activities during
the first six months of 1998 was largely due to the utility segment's collection
of $9.6 million of gas costs incurred during the past year, 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 $.1 million at June 30, 1998, that were classified
- 15 -
<PAGE>
as a current liability. 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, $9.0 million was outstanding at June 30, 1998, all of which was
classified as long-term debt. During the first six months of 1998, the Company's
revolving long-term debt decreased by $37.4 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 $35.6
million, as compared to December 31, 1997. As a result, long-term debt at June
30, 1998, accounted for 58.2% of the Company's capitalization, up slightly from
57.2% at December 31, 1997.
The Company expects its outstanding borrowings to increase during the upcoming
months of 1998 as cash generated from operations will be less than the
requirements for routine capital expenditures and cash dividends due to lower
levels of heating-generated revenues and seasonally higher capital expenditures
resulting from favorable drilling and construction weather. The Company's
capital expenditures for the first six months of 1998 were $26.4 million,
compared to $41.5 million for the same period in 1997. Planned capital spending
during 1998 is expected to be at least $15.0 million, lower than actual 1997
spending. The Company is currently reviewing the timing and level of its capital
expenditures for the remainder of 1998 and may further reduce its planned
capital 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 half 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 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. The decrease in
income taxes receivable resulted from the receipt of federal income tax refunds
and an increase in taxes payable resulted from taxable income generated in the
first half of 1998. 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.
- 16 -
<PAGE>
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
In 1997, the Company's subsidiary, Southwestern Energy Production Company
(SEPCO), filed suit against several parties, including an outside consultant
previously employed by SEPCO, alleging breach of contract, fraud, and other
causes of action in connection with services performed on SEPCO's south
Louisiana exploration projects. On June 23, 1998, the outside consultant filed a
counterclaim against SEPCO. The consultant's primary cause of action relates to
a claim that he is contractually entitled to a 25% interest in the Boure'
project, one of SEPCO's south Louisiana exploration projects. The counterclaim
alleges seven different claims for relief, including breach of contract, fraud,
and defamation and requests damages in excess of $10,000,000 for each claim plus
punitive damages in excess of $10,000,000. The Company feels these claims are
without merit and intends to vigorously contest them. Although the total amount
of these claims is significant in the aggregate, management believes, based on
its investigation, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operation.
Items 2 - 3
No developments required to be reported under Items 2 - 3 occurred during the
quarter ended June 30, 1998.
Item 4 - Submission of Matters to a Vote of Security Holders
The Company held its Annual Meeting of Shareholders on May 21, 1998, for the
purpose of electing Directors of the Company for the ensuing year and to vote on
a proposal to amend and restate the Southwestern Energy Company 1993 Stock
Incentive Plan. Holders of 21,090,696 shares voted in total. Holders of
20,911,401 shares voted for the election of directors and 179,195 shares voted
as withheld. Shares voted regarding the proposal to amend the Southwestern
Energy Company 1993 Stock Incentive Plan were 15,811,187 for the amendment,
5,050,064 against, and 229,345 voted as abstentions. The Directors were elected
with the number of shares voted as follows:
Voted For Withheld
--------- --------
Lewis E. Epley, Jr. 20,877,946 212,750
John Paul Hammerschmidt 20,858,779 231,917
Robert L. Howard 20,901,327 189,369
Kenneth R. Mourton 20,895,472 195,224
Charles E. Scharlau 20,877,528 213,168
- 18 -
<PAGE>
Items 5 - 6(a)
No developments required to be reported under Items 5 - 6(a) occurred during the
quarter ended June 30, 1998.
Item 6(b)
On May 27, 1998, the Company filed a current report on Form 8-K dated May 22,
1998, announcing the appointment of Harold M. Korell as President and Chief
Operating Officer of Southwestern Energy Company and its subsidiaries.
On June 2, 1998, the Company filed a current report on Form 8-K dated May 27,
1998, regarding a decision issued by the Arkansas Court of Appeals remanding an
order of the Arkansas Public Service Commission (APSC) because the order did not
contain adequate findings of fact for the court to conduct a meaningful review
of the APSC's decision. The APSC's order was issued in November, 1996 in
connection with a rate case filed by the Company's utility subsidiary.
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 14, 1998 /s/ GREGORY D. KERLEY
--------------------- --------------------------------
Gregory D. Kerley
Senior Vice President - Finance
and Chief Financial Officer
- 19 -
<PAGE>
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