<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, 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 November 5, 1999
---------------------------- -------------------------------
Common Stock, Par Value $.10 24,943,934
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- 1 -
<PAGE>
PART I
FINANCIAL INFORMATION
- 2 -
<PAGE>
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- ------------
($ in thousands)
<S> <C> <C>
Current Assets
Cash $ 1,560 $ 1,622
Accounts receivable 28,482 40,655
Income taxes receivable 5,500 2,008
Inventories, at average cost 27,109 22,812
Other 7,188 5,174
--------- ---------
Total current assets 69,839 72,271
--------- ---------
Investments 12,394 14,015
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 801,723 758,863
Gas distribution systems 221,008 217,741
Gas in underground storage 23,658 24,279
Other 28,192 27,582
--------- ---------
1,074,581 1,028,465
Less: Accumulated depreciation,
depletion and amortization 509,603 478,790
--------- ---------
564,978 549,675
--------- ---------
Other Assets 11,128 11,659
--------- ---------
Total Assets $ 658,339 $ 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>
September 30, December 31,
1999 1998
------------- ------------
($ in thousands)
<S> <C> <C>
Current Liabilities
Current portion of long-term debt $ 1,536 $ 1,536
Accounts payable 36,760 37,780
Taxes payable 2,829 3,408
Interest payable 7,017 2,471
Customer deposits 5,712 5,635
Other 2,626 3,956
--------- ---------
Total current liabilities 56,480 54,786
--------- ---------
Long-Term Debt, less current portion above 282,600 281,900
--------- ---------
Other Liabilities
Deferred income taxes 128,612 121,413
Other 3,355 3,665
--------- ---------
131,967 125,078
--------- ---------
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 21,221 21,249
Retained earnings 195,107 194,102
Less: Common stock in treasury, at cost,
2,796,570 shares in 1999 and
2,803,527 shares in 1998 31,154 31,248
Unamortized cost of 99,233
restricted shares in 1999
and 133,172 restricted shares
in 1998, issued under stock
incentive plan 656 1,021
--------- ---------
187,292 185,856
--------- ---------
Total Liabilities and Shareholders' Equity $ 658,339 $ 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
<S> <C> <C> <C> <C>
Operating Revenues
Gas sales $ 28,238 $ 27,974 $ 119,892 $ 123,268
Gas marketing 27,915 21,851 62,720 56,556
Oil sales 2,556 2,138 6,529 7,482
Gas transportation and other 1,691 1,588 5,518 5,535
---------- ---------- ---------- ----------
60,400 53,551 194,659 192,841
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gas purchases - utility 5,994 3,588 34,068 26,258
Gas purchases - marketing 27,079 21,199 59,752 54,525
Operating and general 13,854 13,865 42,096 45,606
Depreciation, depletion and amortization 10,133 10,356 30,826 35,794
Write-down of oil and gas properties - - - 66,383
Taxes, other than income taxes 1,676 1,629 4,783 5,273
---------- ---------- ---------- ----------
58,736 50,637 171,525 233,839
---------- ---------- ---------- ----------
Operating Income (Loss) 1,664 2,914 23,134 (40,998)
---------- ---------- ---------- ----------
Interest Expense
Interest on long-term debt 4,916 4,833 14,429 14,584
Other interest charges 252 387 793 1,155
Interest capitalized (814) (763) (2,480) (3,094)
---------- ---------- ---------- ----------
4,354 4,457 12,742 12,645
---------- ---------- ---------- ----------
Other Income (Expense) (482) (638) (1,387) (2,614)
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes (3,172) (2,181) 9,005 (56,257)
---------- ---------- ---------- ----------
Income Tax Provision (Benefit)
Current (4,402) (4,705) (3,652) (817)
Deferred 3,165 3,855 7,164 (21,123)
---------- ---------- ---------- ----------
(1,237) (850) 3,512 (21,940)
---------- ---------- ---------- ----------
Net Income (Loss) $ (1,935) $ (1,331) $ 5,493 $ (34,317)
========== ========== ========== ==========
Basic Earnings (Loss) Per Share ($0.08) ($0.05) $0.22 ($1.38)
====== ====== ====== ======
Weighted Average Common Shares Outstanding 24,938,229 24,892,778 24,935,402 24,865,375
========== ========== ========== ==========
Diluted Earnings (Loss) Per Share ($0.08) ($0.05) $0.22 ($1.38)
====== ====== ====== ======
Diluted Weighted Average Common
Shares Outstanding 24,938,229 24,892,778 24,935,402 24,865,375
========== ========== ========== ==========
Dividends Declared Per Share Payable 11/5/99
and 11/5/98 $ .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,
1999 1998
-------- --------
($ in thousands)
<S> <C> <C>
Cash Flows From Operating Activities
Net income (loss) $ 5,493 $(34,317)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 31,850 36,790
Write-down of oil and gas properties - 66,383
Deferred income taxes 7,164 (21,123)
Equity in loss of partnership 1,620 2,618
Change in assets and liabilities:
Decrease in accounts receivable 12,173 23,884
Increase in income taxes receivable (3,492) (579)
Increase in inventories (4,297) (3,329)
Increase (decrease) in over-recovered
purchased gas costs (3,704) 9,734
Decrease in accounts payable (1,020) (5,896)
Increase in interest payable 4,546 4,511
Net change in other current assets
and liabilities (141) 881
-------- --------
Net cash provided by operating activities 50,192 79,557
-------- --------
Cash Flows From Investing Activities
Capital expenditures (49,482) (41,641)
Investment in partnership - (7,955)
(Increase) decrease in gas stored underground 621 (2,046)
Other items 2,395 3,392
-------- --------
Net cash used in investing activities (46,466) (48,250)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt 700 (29,100)
Cash dividends (4,488) (5,970)
-------- --------
Net cash used in financing activities (3,788) (35,070)
-------- --------
Decrease in cash (62) (3,763)
Cash at beginning of year 1,622 4,603
-------- --------
Cash at end of period $ 1,560 $ 840
======== ========
</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, 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 September 30, 1998,
financial statements in order to conform with the 1999 presentation.
These reclassifications had no effect on previously reported net
income.
2. EARNINGS PER SHARE
Basic earnings per common share is computed by dividing net income by
the weighted average number of common shares outstanding during each
year. The diluted earnings per share calculation adds to the weighted
average number of common shares outstanding the incremental shares that
would have been outstanding assuming the exercise of dilutive stock
options. The Company had options for 1,574,815 shares of common stock
with a weighted average exercise price of $12.02 per share at September
30, 1999, and options to purchase 1,581,901 shares with a weighted
average exercise price of $12.33 at September 30, 1998, that were not
included in the calculation of diluted shares because they would have
had an anti-dilutive effect.
3. DIVIDEND PAYABLE
A dividend of $.06 per share was declared October 7, 1999, payable
November 5, 1999.
4. 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.
-7-
<PAGE>
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 September 30, 1999:
Revenues from external customers $ 13,074 $ 19,411 $ 27,915 $ - $ 60,400
Intersegment revenues 3,782 59 11,423 112 15,376
Depreciation, depletion and
amortization expense 8,344 1,749 18 22 10,133
Operating income 2,667 (1,542) 469 70 1,664
Assets 428,408 177,297 13,669 38,965<F1> 658,339
Capital expenditures 19,398 1,536 - 14 20,948
Three months ended September 30, 1998:
Revenues from external customers $ 15,044 $ 16,623 $ 21,850 $ 34 $ 53,551
Intersegment revenues 3,931 54 5,304 96 9,385
Depreciation, depletion and
amortization expense 8,468 1,849 7 32 10,356
Operating income 4,345 (1,839) 322 86 2,914
Assets 398,023 176,785 7,453 37,608<F1> 619,869
Capital expenditures 12,047 2,839 - 341 15,227
Nine months ended September 30, 1999:
Revenues from external customers $ 37,937 $ 94,002 $ 62,720 $ - $ 194,659
Intersegment revenues 15,337 131 29,770 304 45,542
Depreciation, depletion and
amortization expense 25,365 5,340 54 67 30,826
Operating income 10,260 10,785 1,924 165 23,134
Assets 428,408 177,297 13,669 38,965<F1> 658,339
Capital expenditures 44,615 4,721 8 138 49,482
Nine months ended September 30, 1998:
Revenues from external customers $ 41,349 $ 94,700 $ 56,556 $ 236 $ 192,841
Intersegment revenues 23,033 327 14,288 288 37,936
Depreciation, depletion and
amortization expense 30,014 5,632 23 125 35,794
Write-down of oil and gas properties 66,383 - - - 66,383
Operating income (52,417)<F2> 10,032 1,146 241 (40,998)
Assets 398,023 176,785 7,453 37,608<F1> 619,869
Capital expenditures 33,705 7,272 8 656 41,641
<FN>
<F1> 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.
<F2> Includes a $66.4 million pre-tax write-down of oil and gas properties.
</FN>
</TABLE>
Intersegment sales 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>
5. DERIVATIVE AND HEDGING ACTIVITIES
In June 1999, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 137, "Accounting for Derivative
Instruments and Hedging Activities - Deferral of the Effective Date of
FASB Statement No. 133" (SFAS No. 137). FASB Statement No. 133 (SFAS
No. 133) establishes accounting and reporting standards requiring that
every derivative instrument (including certain derivative instruments
embedded in other contracts) be recorded in the balance sheet as either
an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative's gains and losses
to offset related results on the hedged item in the income statement,
and requires that a company 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,
2000, as amended in SFAS 137, and cannot be applied retroactively.
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. 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 1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
Interest payments $322 $145 $9,746 $9,926
Income tax payments $ - $907 $641 $3,249
</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, 1998, and
analyzes the changes in the results of operations between the three and nine
month periods ended September 30, 1999, and the comparable periods of 1998.
RESULTS OF OPERATIONS
The Company reported a net loss of $1.9 million, or $.08 per share, for the
third quarter of 1999, compared to a net loss of $1.3 million or $.05 per share,
for the same period in 1998. Net income for the nine months ended September 30,
1999, was $5.5 million, or $.22 per share, compared to $6.2 million, or $.25 per
share for the same period in 1998, excluding 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.
Results for the third quarter of 1999, compared to the same period in 1998, were
unfavorably impacted by lower production volumes and lower average gas prices
received. The following tables compare operating revenues and operating income
(before the effects of the write-down of oil and gas properties in 1998) by
business segment for the three and nine month periods ended September 30, 1999
and 1998:
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
Revenues
Exploration and production $ 16,856 $ 18,975 $ 53,274 $ 64,382
Gas distribution 19,470 16,677 94,133 95,027
Marketing and other 39,450 27,284 92,794 71,368
Eliminations (15,376) (9,385) (45,542) (37,936)
-------- -------- -------- --------
$ 60,400 $ 53,551 $194,659 $192,841
======== ======== ======== ========
Operating Income (Loss)
Exploration and production $ 2,667 $ 4,345 $ 10,260 $ 13,966
Gas distribution (1,542) (1,839) 10,785 10,032
Marketing and other 539 408 2,089 1,387
-------- -------- -------- --------
$ 1,664 $ 2,914 $ 23,134 $ 25,385
======== ======== ======== ========
</TABLE>
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<PAGE>
Exploration and Production
Revenues of the exploration and production segment were down 11% for the three
month period ended September 30, 1999, and down 17% for the nine month period
ended September 30, 1999, both as compared to the same periods in 1998,
primarily due to lower production volumes and lower gas prices received.
Operating income of this segment, excluding the write-down in 1998, was down
$1.7 million for the three months ended September 30, 1999, and was down $3.7
million for the nine months ended September 30, 1999, as compared to the same
periods in 1998.
Gas production for the three months ended September 30, 1999, was 7.2 Bcf,
compared to 7.6 Bcf for the same period in 1998. For the nine months ended
September 30, 1999, gas production was 22.1 Bcf, compared to 24.3 Bcf in 1998.
The decrease in production resulted from the combined effects of lower
production from the Company's non-operated properties caused primarily by the
industry slowdown that began last year, reduced demand from the Company's
utility systems due to warm weather, and higher declines than expected from some
of the Company's Gulf Coast properties. The Company's sales to its utility
distribution systems were 5.7 Bcf during the nine months ended September 30,
1999, compared to 8.5 Bcf for the same period in 1998. The decline in sales to
the utility segment was primarily the result of weather that was 5% warmer than
in 1998. Warmer weather impacts deliveries to customers and lowers the utility
segment's requirements for gas to be injected into its storage facilities.
Southwestern received an average price of $1.99 per Mcf for its gas production
during the three months ended September 30, 1999, down from $2.22 per Mcf for
the same period in 1998. The Company received an average price of $2.13 per Mcf
for its gas production during the nine months ended September 30, 1999, down
from $2.34 per Mcf for the same period in 1998. The Company's average price was
reduced by $.48 cents per Mcf for the quarter and $.02 cents per Mcf for the
first nine months of 1999 as a result of the Company's hedging activities. In
the fourth quarter of 1999 the Company has hedged approximately 5.0 Bcf at an
average NYMEX price of $2.33 per Mcf. For the year 2000, the Company has hedged
2.5 Bcf of its production in the first quarter at an average NYMEX price of
$2.47, 4.0 Bcf in each of the second and third quarters at an average NYMEX
price of $2.29, and 2.5 Bcf in the fourth quarter at an average NYMEX price of
$2.35.
The Company's oil production was 423 thousand barrels (MBbls) during the nine
months ended September 30, 1999, down from 550 MBbls for the same period of
1998, primarily reflecting the decline in productive capability of existing
properties. Southwestern received an average price of $15.44 per barrel for its
oil production during the nine months ended September 30, 1999, compared to
$13.60 per barrel for the same period of 1998.
Gas Distribution
Operating income of the gas distribution segment increased $.3 million for the
third quarter of 1999 and $.8 million for the first nine months of 1999, as
compared to the same periods in 1998, despite weather during the first nine
months of 1999 that was 16% warmer than normal and 5% warmer than the same
period of 1998. Customer growth and reduced operating costs and expenses more
than offset the effect of warmer weather. The utility systems delivered 22.5 Bcf
to sales and end-use transportation customers during the nine months ended
September 30, 1999, up slightly from 22.4 Bcf for the same period in 1998. The
Company's average rate for its utility sales increased to $5.77
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<PAGE>
per Mcf during the first nine months of 1999, up from $5.62 per Mcf or the same
period in 1998. The utility also realized 1% growth in the average number of
customers.
In October 1999, the Company signed a definitive agreement to sell its Missouri
gas distribution assets for $32.0 million. The net book value of the assets
being sold is approximately $28.0 million. Proceeds from the sale will be used
to reduce the Company's long term debt. The sale requires regulatory approval
and is expected to close in three to ten months following execution of the
agreement. After closing, the Company's operating results for its gas
distribution segment will be lower reflecting the asset divestiture and the loss
of Missouri customers. However, the Company does not expect the sale to
negatively impact earnings as the loss in operating income should be offset by a
corresponding decrease in interest expense. The Company currently serves
approximately 48,000 customers in Missouri. The Company will continue to operate
its gas distribution systems in Arkansas where it currently serves approximately
131,000 customers.
Marketing
Operating income for the marketing segment was $.5 million on revenues of $39.3
million for the third quarter of 1999, compared to $.3 million on revenues of
$27.2 million for the same period in 1998. For the nine months ended September
30, 1999, operating income for this segment was $1.9 million on revenues of
$92.5 million, compared to $1.1 million on revenues of $70.8 million for the
same period in 1998. The increase in operating income in the marketing segment
was primarily due to increased volumes marketed. The Company marketed 44.6 Bcf
of gas in the first nine months of 1999, compared to 36.4 Bcf for the same
period in 1998.
NOARK Pipeline
The Company's share of NOARK's pre-tax loss included in other income was $.5
million for the third quarter of 1999 and $1.6 million for the first nine months
of 1999, compared to $.9 million and $2.6 million, respectively, for the same
periods 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 System. The integration of the two systems was completed in
November 1998. The Company expects its losses associated with NOARK to continue
to decline over time from historical levels.
Regulatory Matters
On May 19, 1999, the Staff of the Arkansas Public Service Commission (Staff)
initiated a proceeding before the Arkansas Public Service Commission (APSC) in
which it sought an annual reduction of approximately $2.3 million in the rates
Arkansas Western Gas Company charges its ratepayers in northwest Arkansas (AWG
division). The AWG division's last rate case was settled in 1996. Staff's
position was based on various adjustments to the utility's rate base, operating
expenses, capital structure and rate of return. A large portion of the proposed
reduction was based on a downward adjustment to the utility's current return on
equity authorized by the APSC in 1996. The Company has reached agreement with
the Staff to resolve this issue and close several other dockets that had
remained open. In the settlement agreement, the Company has agreed to reduce its
rates collected from customers on a prospective basis in the amount of $1.4
million annually, effective December 1, 1999. The agreement also includes the
resolution of a proceeding initiated in December 1998 by the Staff of the APSC
where they had previously recommended the disallowance of approximately $3.1
million of gas supply costs. As part of the settlement, this
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<PAGE>
docket will be closed with no negative adjustment to the Company. The settlement
agreement between Staff and the Company is subject to approval by the APSC.
Operating Costs and Expenses
The Company's operating costs and expenses, exclusive of gas purchases by the
Company's utility and marketing segments and the non-cash write-down of oil and
gas properties in the second quarter of 1998, were down slightly in the third
quarter of 1999 and decreased 10% for the first nine months of 1999, both as
compared to the comparable periods in 1998. The decrease in operating and
general expenses for the first nine months of 1999 was due primarily to
decreases in operating costs in both the exploration and production and gas
distribution segments, and lower general and administrative costs due to
severance and other costs incurred in connection with the closing of the
Company's Oklahoma City exploration and production office in 1998. The decrease
in depreciation, depletion and amortization expense for this same period was due
to both lower production and a decrease in the average amortization rate per
unit of production in the exploration and production segment that resulted
primarily from the second quarter 1998 write-down of oil and gas properties. The
Company's amortization rate was $1.00 per Mcf equivalent for the first nine
months of 1999, compared to $1.06 for the same period in 1998.
The Company utilizes the full cost method of accounting for costs related to its
oil and natural gas properties. Under this method, all such costs (productive
and nonproductive) are capitalized and amortized on an aggregate basis over the
estimated lives of the properties using the units-of-production method. These
capitalized costs are subject to a ceiling test, however, which limits such
pooled costs to the aggregate of the present value of future net revenues
attributable to proved gas and oil reserves discounted at 10 percent plus the
lower of cost or market value of unproved properties. At September 30, 1999, the
Company's unamortized costs of oil and gas properties did not exceed this
ceiling amount. The Company's full cost ceiling is evaluated at the end of each
quarter. A decline in gas and oil prices from current levels, or other factors,
without mitigating circumstances could cause a future write-down of capitalized
costs and a non-cash charge against future earnings.
Gas purchased for resale by the Company's marketing segment increased in the
third quarter and the first nine months of 1999 due to increases in volumes
marketed. The increases in purchased gas costs for the gas distribution segment
for these same periods reflect prices paid for supplies and the mix of purchases
from intercompany versus third party sources.
The changes in the provisions for current and deferred income taxes recorded in
the three and nine month periods ended September 30, 1999, as compared to the
same periods in 1998, resulted primarily from the June 1998 write-down of the
Company's oil and gas properties which resulted in a deferred tax benefit of
$25.9 million. Other items impacting deferred taxes were the level of taxable
income and the deduction of intangible drilling costs in the year incurred for
tax purposes, netted against the turnaround of intangible drilling costs
deducted for tax purposes in prior years. Intangible drilling costs are
capitalized and amortized over future years for financial reporting purposes
under the full cost method of accounting.
-13-
<PAGE>
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at September 30, 1999, as compared
to December 31, 1998, primarily reflect the seasonal nature of the gas
distribution segment of the Company's business and the timing of cash receipts
and payments.
Routine capital expenditures, cash dividends and scheduled debt retirements are
predominately funded through cash provided by operations. For the first nine
months of 1999 and 1998, net cash provided by operating activities was $50.2
million and $79.6 million, respectively. Net cash provided by operating
activities met 93% of routine cash requirements in the first nine months of
1999, and exceeded these routine requirements in 1998. The decrease in net cash
provided by operating activities during the first nine months of 1999 was due in
large part to the timing of cash receipts and payments for working capital
items.
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, $35.6 million was outstanding at September 30, 1999, all of which
was classified as long-term debt. Long-term debt accounted for 60% of the
Company's capitalization, at both September 30, 1999 and December 31, 1998.
The Company remains confident that it will prevail in its appeal of the royalty
owners proceeding described in Part II, Item 1. However, the agreement under
which unsecured letters of credit have been provided to collateralize the appeal
bond would require the Company to reimburse its lenders for the full amount
drawn under the letters of credit if it were to lose the appeal. Under these
circumstances the Company's ability to borrow money would be restricted and
existing financing agreements could be impacted through cross default
provisions.
The Company's capital expenditures for the first nine months of 1999 were $49.5
million, compared to $41.6 million for the same period in 1998. Capital
expenditures in the third quarter of 1999 include an acquisition of
approximately 12 Bcf equivalent of proved producing oil and gas properties for
$9.3 million. Including the acquisition, planned capital investments during
calendar year 1999 are currently expected to be approximately level with 1998.
Working Capital
Accounts receivable has declined since December 31, 1998, due primarily to
seasonally lower deliveries of the gas distribution segment. Inventories have
increased since December 31, 1998 due to injection of gas storage volumes in
anticipation of the upcoming heating season. Accounts payable is down slightly
since December 31, 1998, as liabilities for seasonally lower gas purchases for
the gas distribution segment have been partially offset by a payable for the
acquisition of oil and gas properties discussed above in Financing Requirements.
The payment for this acquisition was funded by the Company's revolving long-term
debt on October 1, 1999. Other changes in current assets and current liabilities
between periods resulted primarily from the timing of expenditures and receipts.
-14-
<PAGE>
YEAR 2000
The primary financial information systems of the Company that are supported by
outside vendors are designed to accommodate the century date or have been
upgraded and tested in 1998 to a year 2000 compliant version at no additional
cost to the Company. Other information systems supported internally by the
Company have been either scheduled for replacement at which time they will
become year 2000 compliant, or have been modified to support year 2000
processing. Scheduled implementation and final testing of these systems was
originally scheduled to be completed no later than mid-year 1999. Due to delays
by a third party vendor, one of the information systems that was an upgrade to
existing software will not be completely installed and tested by December 31,
1999. Due to this delay, the Company has modified its existing processes to
accommodate the year 2000 date. The Company is continuing with the installation
of the software upgrade that will be completed in the year 2000. For additional
information regarding the Company's state of readiness for the year 2000, refer
to "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.
-15-
<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
8% 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 September 30, 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 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
-16-
<PAGE>
credit quality of each counterparty and the level of financial exposure the
Company has to each counterparty are periodically reviewed to ensure limited
credit risk exposure.
The following table provides information about the Company's financial
instruments designated as hedges 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 September 30, 1999. At September 30,
1999, the "Carrying Amount" exceeds the "Fair Value" by $7.7 million.
<TABLE>
<CAPTION>
Expected Maturity Date
1999 2000 2001 2002
Carrying Fair Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value Amount Value
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 5.4 15.5 .7 .5
Weighted average price per Mcf $2.36 $2.33 $2.57 $2.57
Contract amount (in millions) $12.7 $10.5 $36.1 $31.0 $1.7 $1.7 $1.2 $1.2
Swaps with a fixed price payment
Contract volume (Bcf) .2 - - -
Weighted average price per Mcf $2.47 - - -
Contract amount (in millions) $.4 $.4 - - - - - -
Oil:
Price floor
Contract volume (MBbls) 94 350 325 -
Weighted average price per Bbl $18.00 $18.00 $18.00 -
Contract amount (in millions) $1.7 $1.7 $6.3 $6.3 $5.9 $5.9 - -
Swaps with a fixed price receipt
Contract volume (MBbls) 21 96 72 -
Weighted average price per Bbl $20.80 $18.87 $17.49 -
Contract amount (in millions) $.4 $.3 $1.8 $1.6 $1.3 $1.2 - -
</TABLE>
-17-
<PAGE>
PART II
OTHER INFORMATION
Item 1
In May 1996, a class action suit was filed against the Company in the Circuit
Court of Sebastian County, Arkansas on behalf of royalty owners alleging
improprieties in the disbursements of royalty proceeds. A trial was held on the
class action suit beginning in late September 1998 that resulted in 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 had 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. The bond was placed by a
surety company and was collateralized by unsecured letters of credit. The amount
of this bond has been increased to $109.3 million in November 1999 to include
additional interest costs through June 2000.
The verdict was returned following a trial on the issues of the 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 obtained a temporary stay of the judgment on
the jury's verdict and has filed and will vigorously prosecute an appeal in the
Arkansas Supreme Court. All appeal briefs are expected to be filed by the end of
November. Oral argument is likely to occur in the first quarter of 2000, and a
decision from the Court is likely by July 2000. If the Company is not successful
in 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. This case has been set for trial in January 2000. 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, 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.
-18-
<PAGE>
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. MMS has withdrawn its cross appeal on this
issue and 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 1 - 6(a) occurred during the
quarter ended September 30, 1999 that have not been previously reported.
Item 6(b)
On October 20, 1999, the Company filed a current report on Form 8-K dated
October 19, 1999, announcing the sale of its Missouri gas distribution assets to
Atmos Energy Corporation for $32.0 million.
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 12, 1999 /s/ GREGORY D. KERLEY
--------------------- ---------------------------
Gregory D. Kerley
Senior Vice President
and Chief Financial Officer
-19-
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,560
<SECURITIES> 0
<RECEIVABLES> 28,482
<ALLOWANCES> 0
<INVENTORY> 27,109
<CURRENT-ASSETS> 69,839
<PP&E> 1,074,581
<DEPRECIATION> (509,603)
<TOTAL-ASSETS> 658,339
<CURRENT-LIABILITIES> 56,480
<BONDS> 282,600
0
0
<COMMON> 2,774
<OTHER-SE> 184,518
<TOTAL-LIABILITY-AND-EQUITY> 658,339
<SALES> 189,141
<TOTAL-REVENUES> 194,659
<CGS> 0
<TOTAL-COSTS> 171,525
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,742
<INCOME-PRETAX> 9,005
<INCOME-TAX> 3,512
<INCOME-CONTINUING> 5,493
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,493
<EPS-BASIC> 0.22
<EPS-DILUTED> 0.22
<FN>
The information has been prepared in accordance with SFAS No. 128.
Basic and diluted EPS have been entered in place of primary and fully diluted,
respectively.
</FN>
</TABLE>
