<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 March 31, 1999
--------------
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 May 5, 1999
---------------------------- --------------------------
Common Stock, Par Value $.10 24,933,280
===========================================================================
- 1 -
<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
March 31, December 31,
1999 1998
------------ ---------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 1,595 $ 1,622
Accounts receivable 34,162 40,655
Income taxes receivable - 2,008
Inventories, at average cost 17,262 22,812
Other 4,852 5,174
--------- ---------
Total current assets 57,871 72,271
--------- ---------
Investments 13,457 14,015
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 770,208 758,863
Gas distribution systems 218,558 217,741
Gas in underground storage 19,118 24,279
Other 28,094 27,582
--------- ---------
1,035,978 1,028,465
Less: Accumulated depreciation,
depletion and amortization 489,119 478,790
--------- ---------
546,859 549,675
--------- ---------
Other Assets 11,411 11,659
--------- ---------
Total Assets $ 629,598 $ 647,620
========= =========
</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>
March 31, December 31,
1999 1998
------------- ---------
($ in thousands)
<S> <C> <C>
Current Liabilities
Current portion of long-term debt $ 1,536 $ 1,536
Accounts payable 27,687 37,780
Taxes payable 7,060 3,408
Interest payable 7,033 2,471
Customer deposits 5,675 5,635
Over-recovered purchased gas costs 3,372 1,503
Other 2,464 2,453
--------- ---------
Total current liabilities 54,827 54,786
--------- ---------
Long-Term Debt, less current portion above 255,700 281,900
--------- ---------
Other Liabilities
Deferred income taxes 121,878 121,413
Other 3,574 3,665
--------- ---------
125,452 125,078
--------- ---------
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 21,249 21,249
Retained earnings 201,738 194,102
Less: Common stock in treasury, at cost,
2,804,804 shares in 1999 and
2,803,527 shares in 1998 31,262 31,248
Unamortized cost of 120,877
restricted shares in 1999
and 133,172 restricted shares
in 1998, issued under stock
incentive plan 880 1,021
--------- ---------
193,619 185,856
--------- ---------
Total Liabilities and Shareholders' Equity $ 629,598 $ 647,620
========= =========
</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
March 31,
1999 1998
---------- ----------
($ in thousands, except
per share amounts)
<S> <C> <C>
Operating Revenues
Gas sales $ 60,939 $ 62,882
Gas marketing 13,475 15,201
Oil sales 1,661 2,769
Gas transportation and other 2,145 2,104
---------- ----------
78,220 82,956
---------- ----------
Operating Costs and Expenses
Gas purchases - utility 20,360 18,687
Gas purchases - marketing 12,088 14,272
Operating and general 13,923 15,129
Depreciation, depletion and amortization 10,372 13,039
Taxes, other than income taxes 1,548 1,906
---------- ----------
58,291 63,033
---------- ----------
Operating Income 19,929 19,923
---------- ----------
Interest Expense
Interest on long-term debt 4,834 5,048
Other interest charges 283 265
Interest capitalized (839) (1,135)
---------- ----------
4,278 4,178
---------- ----------
Other Income (Expense) (680) (873)
---------- ----------
Income Before Provision for Income Taxes 14,971 14,872
---------- ----------
Income Tax Provision
Current 5,370 5,306
Deferred 469 494
---------- ----------
5,839 5,800
---------- ----------
Net Income $ 9,132 $ 9,072
========== ==========
Basic Earnings Per Share $0.37 $0.37
====== ======
Weighted Average Common Shares Outstanding 24,933,919 24,843,012
========== ==========
Diluted Earnings Per Share $0.37 $0.37
====== ======
Diluted Weighted Average Common
Shares Outstanding 24,933,919 24,860,505
========== ==========
Dividends Declared Per Share Payable 5/5/99
and 5/5/98 $ .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>
Quarter Ended
March 31,
1999 1998
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 9,132 $ 9,072
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 10,715 13,364
Deferred income taxes 469 494
Equity in loss of partnership 557 786
Change in assets and liabilities:
Decrease in accounts receivable 6,493 7,813
Change in income taxes receivable/payable 4,814 8,506
Decrease in inventories 5,550 4,809
Increase in over-recovered purchased gas costs 1,869 7,927
Decrease in accounts payable (10,093) (5,301)
Increase in interest payable 4,562 4,578
Net change in other current assets
and liabilities 1,219 841
-------- --------
Net cash provided by operating activities 35,287 52,889
-------- --------
Cash Flows From Investing Activities
Capital expenditures (13,714) (8,930)
Investment in partnership - (7,343)
Decrease in gas stored underground 5,161 2,951
Other items 935 114
-------- --------
Net cash used in investing activities (7,618) (13,208)
-------- --------
Cash Flows From Financing Activities
Decrease in revolving long-term debt (26,200) (40,400)
Cash dividends (1,496) (1,491)
-------- --------
Net cash used in financing activities (27,696) (41,891)
-------- --------
Decrease in cash (27) (2,210)
Cash at beginning of year 1,622 4,603
-------- --------
Cash at end of period $ 1,595 $ 2,393
======== ========
</TABLE>
The accompanying notes are an integral part
of the financial statements.
- 6 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
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 1998
Annual Report to Shareholders, Notes to Financial Statements.
Certain reclassifications have been made to the March 31, 1998,
financial statements in order to conform with the 1999 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 March 31, 1999,
the Company's unamortized costs of oil and gas properties exceeded this
ceiling amount by approximately $41.4 million (net of taxes) due
primarily to low gas prices. However, the ceiling limitation was
recalculated using May 1999 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.
3. 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. Antidilutive options not included in the computation were for
1,634,901 shares of common stock with a weighted average exercise price
of $12.15 per share in the first quarter of 1999, and options to
purchase 1,286,501 shares with a weighted average exercise price of
$13.83 in the first quarter of 1998.
-7-
<PAGE>
4. DIVIDEND PAYABLE
A dividend of $.06 per share was declared April 7, 1999, payable May 5,
1999.
5. SEGMENT INFORMATION
The Company adopted SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," in 1998 which changes the way the
Company reports information about its operating segments. 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. The Company
utilizes operating income to evaluate segment profit or loss.
Summarized financial information for the Company's reportable segments
are shown in the following table. The "Other" column includes items
related to non-reportable segments (real estate and pipeline
operations) and corporate items.
<TABLE>
<CAPTION>
Exploration
and Gas
Production Distribution Marketing Other Total
---------- ------------ --------- ------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Three months ended March 31, 1999:
Revenues from external customers $ 11,678 $ 53,067 $ 13,475 $ -- $ 78,220
Intersegment revenues 8,703 51 8,519 96 17,369
Depreciation, depletion and
amortization expense 8,565 1,767 18 22 10,372
Operating income 5,886 12,950 1,046 47 19,929
Assets 406,800 180,662 7,358 34,778<F1> 629,598
Capital expenditures 12,183 1,375 7 149 13,714
Three months ended March 31, 1998:
Revenues from external customers $ 11,875 $ 55,868 $ 15,201 $ 12 $ 82,956
Intersegment revenues 12,386 57 4,076 183 16,702
Depreciation, depletion and
amortization expense 11,093 1,891 8 47 13,039
Operating income 6,556 12,640 649 78 19,923
Assets 452,157 186,229 7,087 38,366<F1> 683,839
Capital expenditures 7,145 1,666 3 116 8,930
<FN>
<F1> (1) Other assets includes the Company's equity investment in the
operations of NOARK, corporate assets not allocated to segments, and
assets for non-reportable segments.
</FN>
</TABLE>
Intersegment sales by the exploration and production segment to the gas
distribution and marketing segments 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.
-8-
<PAGE>
6. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
Quarter Ended March 31 1999 1998
-----------------------------------------------------------------------
(in thousands)
Interest payments $307 $501
Income tax payments $429 $ -
-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, 1998, and
analyzes the changes in the results of operations between the three month period
ended March 31, 1999, and the comparable period of 1998.
RESULTS OF OPERATIONS
Net income for the three months ended March 31, 1999, was $9.1 million, or $.37
per share, even with the same period in 1998. Improved operating results
experienced by the natural gas utility and marketing segments during the first
quarter offset a decline in operating income experienced by the exploration and
production segment.
The following tables compare operating revenues and operating income by business
segment for the first three months of 1999 and 1998:
<TABLE>
<CAPTION>
Increase
1999 1998 (Decrease)
-------- -------- ----------
(in thousands)
<S> <C> <C> <C>
Revenues
Exploration and production $ 20,381 $ 24,261 $(3,880)
Gas distribution 53,118 55,925 (2,807)
Marketing and other 22,090 19,472 2,618
Eliminations (17,369) (16,702) (667)
-------- -------- -------
$ 78,220 $ 82,956 $(4,736)
======== ======== =======
Operating Income
Exploration and production $ 5,886 $ 6,556 $ (670)
Gas distribution 12,950 12,640 310
Marketing and other 1,093 727 366
-------- -------- -------
$ 19,929 $ 19,923 $ 6
======== ======== =======
</TABLE>
Exploration and Production
Revenues for the exploration and production segment were down 16% and operating
income was down 10% for the three months ended March 31, 1999, as compared to
the same period in 1998, primarily due to lower oil and gas production. Gas and
oil production during the first quarter of 1999 was 8.5 billion cubic feet (Bcf)
equivalent, compared to 9.9 Bcf equivalent for the same period in 1998. Gas
production was 7.7 Bcf for the three months ended March 31, 1999, compared to
8.7 Bcf for the same period in 1998. The decrease in production was largely due
to reduced demand from the Company's utility systems due to warm weather
combined with delays in non-operated projects. The Company's sales to its gas
distribution systems were 3.2 Bcf during the three months ended March 31, 1999,
compared to 4.5 Bcf for the same period in 1998. The
-10-
<PAGE>
Company's oil production was 137 thousand barrels (MBbls) during the three
months ended March 31, 1999, down from 192 MBbls for the same period of 1998,
primarily reflecting the decline in productive capability of existing
properties.
The Company received an average price of $2.46 per thousand cubic feet (Mcf) for
its gas production for the three months ended March 31, 1999, up slightly from
$2.44 per Mcf for the same period of 1998. The Company hedged 4.2 Bcf of gas in
the first quarter of 1999 that added $.47 per Mcf to the average gas price.
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 received an average price of
$12.16 per barrel for its oil production during the three months ended March 31,
1999, down from $14.44 per barrel for the same period of 1998.
Gas Distribution
Operating income of the gas distribution segment increased 2% in the first
quarter of 1999, as compared to the first quarter of 1998, despite weather which
was 16% warmer than normal and 5% warmer than in the same period of 1998. The
improvement in operating income was due to the combined effects of reduced
operating expenses, customer growth and weather normalization adjustments. The
utility realized growth of 1.3% during the quarter in the average number of
utility customers served. Additionally, weather normalization adjustments which
are now applicable to the Company's Arkansas systems offset a large part of the
effect of the warmer weather. The utility systems delivered 12.6 Bcf to sales
and end-use transportation customers during the three months ended March 31,
1999, down slightly from 12.7 Bcf for the same period in 1998.
The Company's average rate for its utility sales decreased during the first
quarter of 1999 to $5.09 per Mcf, down from $5.15 per Mcf for the same period in
1998. The decrease reflected lower prices paid for purchases of natural gas
which are passed through to customers under automatic adjustment clauses.
Marketing
Operating income for the marketing segment was $1.0 million for the first
quarter of 1999, compared to $.7 million for the first quarter of 1998. The
increase in operating income in the Marketing segment was due to increased
volumes marketed and monthly demand charges received under a competitively bid
contract with the Company's gas distribution subsidiary. The Company marketed
12.7 Bcf of gas in the first three months of 1999, compared to 9.8 Bcf for the
same period in 1997.
NOARK Pipeline
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK)
pre-tax loss included in other income was $.6 million for the first quarter of
1999, down from $.8 million for the same period in 1998. The improvement in
NOARK's pre-tax loss primarily reflects the benefits of the integration of the
NOARK Pipeline System with the Ozark Gas Transmission
-11-
<PAGE>
System. The integration of the two systems was completed in November 1998. The
Company expects its losses associated with NOARK to continue to decline from
historical levels.
Operating Costs and Expenses
Operating costs and expenses decreased 8% in the first quarter of 1999, as
compared to the first quarter of 1998. The decrease was primarily caused by
lower operating expenses and lower depreciation, depletion and amortization
expense. The decrease in operating and general expenses was due to both
decreased general and administrative costs and decreased operating expenses in
both the exploration and production segment and the gas distribution segment.
The decrease in depreciation, depletion and amortization expense was due to a
decrease in the amortization rate per unit of production in the exploration and
production segment that resulted from the Company's write-down of its oil and
gas properties in the second quarter of 1998. The amortization rate for this
segment averaged $.98 per Mcf equivalent for the first quarter of 1999, compared
to $1.10 per Mcf equivalent in the first quarter of 1998. The changes in
purchased gas costs for the gas distribution and marketing segments reflect
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. Such capitalized costs do
not include costs related to unevaluated properties. At March 31, 1999, the
Company's unamortized costs of oil and gas properties exceeded this ceiling
amount by approximately $41.4 million (net of taxes) due primarily to low oil
and gas prices. However, the ceiling limitation was recalculated using May 1999
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.
Interest expense, net of capitalization, for the three months ended March 31,
1999, was up 2% compared to the same period in 1998, as lower interest costs
that primarily resulted from lower average borrowings were more than offset by
the 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 month period ended March 31, 1999, as compared to the same period in
1998, 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
-12-
<PAGE>
purposes in prior years. Intangible drilling costs are capitalized and amortized
over future years for financial reporting purposes under the full cost method of
accounting.
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at March 31, 1999, as compared to
December 31, 1998, 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
predominantly funded through cash provided by operations. For the first three
months of 1999 and 1998, net cash provided by operating activities was $35.3
million and $52.9 million, respectively, and exceeded the total of these routine
requirements. The decrease in cash provided by operations during the first
quarter of 1999 was due to the timing of cash receipts and payments. The Company
had net over-recovered purchased gas costs of $3.4 million at March 31, 1999. At
December 31, 1998, the Company had net over-recovered purchased gas costs in the
amount of $1.5 million. These amounts are classified as current liabilities.
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 revolving credit
facilities. Of this amount, $8.7 million was outstanding at March 31, 1999, all
of which was classified as long-term debt. During the first quarter of 1999, the
Company's revolving long-term debt was reduced by $26.2 million, due to
seasonally strong cash flow. As a result, long-term debt at March 31, 1999,
accounted for 57% of the Company's capitalization, down from 60% at December 31,
1998.
The Company expects its outstanding borrowings to increase during the remaining
months of 1999 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 three months of 1999 were $13.7 million,
compared to $8.9 million for the same period in 1998. Planned capital spending
during 1999 is expected to be approximately even with 1998 spending.
At March 31, 1999, the NOARK partnership had outstanding debt totaling
approximately $79.0 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, 1998, due primarily to
seasonally lower gas deliveries of the gas distribution segment. The decrease in
income taxes receivable resulted from an increase in taxes payable that resulted
from taxable income generated in the first quarter of
-13-
<PAGE>
1999. The decrease in inventories since December 31, 1998, is both the result of
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 declined since December 31, 1998, due primarily to
seasonally lower gas purchases of the gas distribution segment and to the timing
of expenditures. The increase in interest payable is due to the timing of
interest payments on the Company's long-term debt. Other changes in current
assets and current liabilities between periods resulted primarily from the
timing of expenditures and receipts.
YEAR 2000
The Company's current state of readiness for the year 2000 has not materially
changed from its state of readiness that was disclosed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations" in the
Company's 1998 Form 10-K.
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 weather and regulation on the
Company's gas distribution 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.
-14-
<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
4% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
Interest Rate Risk
The Company's long-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 March 31, 1999. There have been no material changes in the
interest rate risk information that was presented in the Company's 1998 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
-15-
<PAGE>
as a result of non-performance by the Company's counterparties. The
counterparties are primarily major investment and commercial banks which
management believes present minimal credit risks. The credit quality of each
counterparty and the level of financial exposure the Company has to each
counterparty are periodically reviewed to ensure limited credit risk exposure.
The following table provides information about the Company's financial
instruments that are sensitive to changes in commodity prices. The table
presents the notional amount in Bcf (billion cubic feet), the weighted average
contract prices, and the total dollar contract amount by expected maturity
dates. The "Carrying Amount" for the contract amounts are calculated as the
contractual payments for the quantity of gas or oil to be exchanged under
futures contracts and do not represent amounts recorded in the Company's
financial statements. The "Fair Value" represents values for the same contracts
using comparable market prices at March 31, 1999. The net difference between the
contract amounts and fair value amounts of the contracts was $.9 million at
March 31, 1999.
<TABLE>
<CAPTION>
Expected Maturity Date
----------------------------------------------------------
1999 2000 2001
---------------- ---------------- ----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
------ ----- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C> <C>
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 12.9 9.3 -
Weighted average price per Mcf $2.04 $2.24 -
Contract amount (in millions) $26.4 $26.0 $20.9 $20.5 - -
Swaps with a fixed price payment
Contract volume (Bcf) .9 - -
Weighted average price per Mcf $2.13 - -
Contract amount (in millions) $2.0 $1.9 - - - -
Basis swaps
Contract volume (Bcf) .7 - -
Weighted average basis difference
per Mcf $.089 - -
Contract amount (in millions) $.1 $.1 - - - -
Oil:
Price floor
Contract volume (MBbls) 281 350 325
Weighted average price per Bbl $18.00 $18.00 $18.00
Contract amount (in millions) $5.1 $5.5 $6.3 $7.0 $5.9 $6.6
</TABLE>
-16-
<PAGE>
PART II
OTHER INFORMATION
Item 1
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 in the Company's Form 10-K
for the fiscal year ended December 31, 1998, involves claims similar to those
upon which judgment was rendered against the Company and its subsidiaries in
that class action litigation. This lawsuit has been set for trial in January
2000. While the amounts of this pending claim 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.
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. This case has been scheduled for
non-binding mediation in June 1999 and is expected to be tried in October 1999.
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 - 6(a)
No developments required to be reported under Items 2 - 6(a) occurred during the
quarter ended March 31, 1999.
Item 6(b)
On April 8, 1999, the Company filed a current report on Form 8-K dated April 7,
1999, announcing the approval by the Company's Board of Directors of an
amendment and extension of the Company's Share Purchase Rights Plan.
-17-
<PAGE>
Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
Registrant
DATE: May 14, 1999 /s/ GREG D. KERLEY
------------------ ------------------------------
Greg D. Kerley
Senior Vice President
and Chief Financial Officer
- 18 -
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 1,595
<SECURITIES> 0
<RECEIVABLES> 34,162
<ALLOWANCES> 0
<INVENTORY> 17,262
<CURRENT-ASSETS> 57,871
<PP&E> 1,035,978
<DEPRECIATION> (489,119)
<TOTAL-ASSETS> 629,598
<CURRENT-LIABILITIES> 54,827
<BONDS> 255,700
0
0
<COMMON> 2,774
<OTHER-SE> 190,845
<TOTAL-LIABILITY-AND-EQUITY> 629,598
<SALES> 76,075
<TOTAL-REVENUES> 78,220
<CGS> 0
<TOTAL-COSTS> 58,291
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,278
<INCOME-PRETAX> 14,971
<INCOME-TAX> 5,839
<INCOME-CONTINUING> 9,132
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,132
<EPS-PRIMARY> 0.37
<EPS-DILUTED> 0.37
<FN>
The information has been prepared in accordance with SFAS No. 128.
Basic and dilted EPS have been entered in place of primary and fully diluted,
respectively.
</FN>
</TABLE>
