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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 March 31, 2000
--------------
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from _______ to _______
Commission file number 1-8246
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas 71-0205415
(State of incorporation (I.R.S. Employer
or organization) Identification No.)
1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas 72702-1408
(Address of principal executive offices, including zip code)
(501) 521-1141
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year; if changed
since last report)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding twelve months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes: X No:
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Class Outstanding at May 4, 2000
---------------------------- --------------------------
Common Stock, Par Value $.10 25,035,154
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- 1 -
PART I
FINANCIAL INFORMATION
- 2 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
March 31, December 31,
2000 1999
------------- ------------
($ in thousands)
Current Assets
Cash $ 1,254 $ 1,240
Accounts receivable 42,189 43,339
Inventories, at average cost 13,486 21,520
Other 3,005 4,073
--------- ---------
Total current assets 59,934 70,172
--------- ---------
Investments 13,545 14,180
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 827,983 816,199
Gas distribution systems 222,957 222,145
Gas in underground storage 25,834 28,712
Other 29,058 28,826
--------- ---------
1,105,832 1,095,882
Less: Accumulated depreciation,
depletion and amortization 530,736 519,927
--------- ---------
575,096 575,955
--------- ---------
Other Assets 11,050 11,139
--------- ---------
Total Assets $ 659,625 $ 671,446
========= =========
The accompanying notes are an integral part
of the financial statements.
- 3 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
March 31, December 31,
2000 1999
------------- ------------
($ in thousands)
Current Liabilities
Short-term debt $ - $ 7,500
Accounts payable 27,049 33,069
Taxes payable 5,291 3,506
Interest payable 7,117 2,483
Customer deposits 6,029 6,021
Other 2,467 3,767
--------- ---------
Total current liabilities 47,953 56,346
--------- ---------
Long-Term Debt, less current portion above 278,400 294,700
--------- ---------
Other Liabilities
Deferred income taxes 131,924 126,902
Other 3,143 3,142
--------- ---------
135,067 130,044
--------- ---------
Commitments and Contingencies
Shareholders' Equity
Common stock, $.10 par value; authorized
75,000,000 shares, issued 27,738,084
shares 2,774 2,774
Additional paid-in capital 20,732 20,732
Retained earnings 205,728 198,044
Less: Common stock in treasury, at cost,
2,700,731 shares in 2000 and
2,700,391 shares in 1999 30,087 30,083
Unamortized cost of 179,275
restricted shares in 2000
and 188,781 restricted shares
in 1999, issued under stock
incentive plan 942 1,111
--------- ---------
198,205 190,356
--------- ---------
Total Liabilities and Shareholders' Equity $ 659,625 $ 671,446
========= =========
The accompanying notes are an integral part
of the financial statements.
- 4 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Quarter Ended
March 31,
-------------------------
2000 1999
---------- ----------
($ in thousands, except
per share amounts)
Operating Revenues
Gas sales $ 60,292 $ 60,939
Gas marketing 30,004 13,475
Oil sales 3,579 1,661
Gas transportation and other 3,038 2,145
---------- ----------
96,913 78,220
---------- ----------
Operating Costs and Expenses
Gas purchases - utility 19,263 20,360
Gas purchases - marketing 28,663 12,088
Operating and general 14,786 13,923
Depreciation, depletion and amortization 11,091 10,372
Taxes, other than income taxes 2,054 1,548
---------- ----------
75,857 58,291
---------- ----------
Operating Income 21,056 19,929
---------- ----------
Interest Expense
Interest on long-term debt 5,201 4,834
Other interest charges 192 283
Interest capitalized (637) (839)
---------- ----------
4,756 4,278
---------- ----------
Other Income (Expense) (1,241) (680)
---------- ----------
Income Before Income Taxes 15,059 14,971
---------- ----------
Income Tax Provision
Current 872 5,370
Deferred 5,001 469
---------- ----------
5,873 5,839
---------- ----------
Net Income $ 9,186 $ 9,132
========== ==========
Basic Earnings Per Share $0.37 $0.37
====== ======
Weighted Average Common Shares Outstanding 25,037,508 24,933,919
========== ==========
Diluted Earnings Per Share $0.37 $0.37
====== ======
Diluted Weighted Average Common
Shares Outstanding 25,063,076 24,933,919
========== ==========
Dividends Declared Per Share Payable 5/5/00
and 5/5/99 $ .06 $ .06
===== =====
The accompanying notes are an integral part
of the financial statements.
- 5 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Quarter Ended
March 31,
--------------------
2000 1999
-------- --------
($ in thousands)
Cash Flows From Operating Activities
Net income $ 9,186 $ 9,132
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 11,394 10,715
Deferred income taxes 5,001 469
Equity in loss of partnership 634 557
Change in assets and liabilities:
Decrease in accounts receivable 1,150 6,493
Change in income taxes receivable/payable 1,222 4,814
Decrease in inventories 8,034 5,550
Decrease in accounts payable (6,020) (10,093)
Increase in interest payable 4,634 4,562
Net change in other current assets
and liabilities 340 3,088
-------- --------
Net cash provided by operating activities 35,575 35,287
-------- --------
Cash Flows From Investing Activities
Capital expenditures (14,557) (13,714)
Decrease in gas stored underground 2,878 5,161
Other items 1,420 935
-------- --------
Net cash used in investing activities (10,259) (7,618)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt (16,300) (26,200)
Payment on revolving short-term debt (7,500) -
Cash dividends (1,502) (1,496)
-------- --------
Net cash used in financing activities (25,302) (27,696)
-------- --------
Increase (decrease) in cash 14 (27)
Cash at beginning of year 1,240 1,622
-------- --------
Cash at end of period $ 1,254 $ 1,595
======== ========
The accompanying notes are an integral part
of the financial statements.
- 6 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2000
1. BASIS OF PRESENTATION
The financial statements included herein are unaudited; however, such
information reflects all adjustments (consisting solely of normal
recurring adjustments) which are, in the opinion of management,
necessary for a fair presentation of the results for the interim
periods. The Company's accounting policies are summarized in the 1999
Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial
Statements.
2. EARNINGS PER SHARE
Basic earnings per common share is computed by dividing net income by
the weighted average number of common shares outstanding during each
year. The diluted earnings per share calculation adds to the weighted
average number of common shares outstanding the incremental shares that
would have been outstanding assuming the exercise of dilutive stock
options. The Company had options for 1,582,916 shares of common stock
with a weighted average exercise price of $11.85 per share at March 31,
2000, and options for 1,634,901 shares with an average exercise price
of $12.15 per share at March 31, 1999, that were not included in the
calculation of diluted shares because they would have had an
antidilutive effect.
3. DIVIDEND PAYABLE
A dividend of $.06 per share was declared April 5, 2000, payable May 5,
2000.
4. SEGMENT INFORMATION
The Company applies SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." The Company's reportable business
segments have been identified based on the differences in products or
services provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and crude oil.
Revenues for the gas distribution segment arise from the transportation
and sale of natural gas at retail. The marketing segment generates
revenue through the marketing of both Company and third party produced
gas volumes.
Summarized financial information for the Company's reportable segments
are shown in the following table. The "Other" column includes items
related to non-reportable segments (real estate and pipeline
operations) and corporate items.
-7-
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- --------- ---------
(in thousands)
Three months ended March 31, 2000:
Revenues from external customers $ 13,715 $ 53,194 $ 30,004 $ - $ 96,913
Intersegment revenues 11,046 54 13,241 112 24,453
Depreciation, depletion and
amortization expense 9,240 1,810 18 23 11,091
Operating income 8,688 11,370 965 33 21,056
Interest expense(1) 3,238 1,253 - 265 4,756
Provision (benefit) for income taxes(1) 1,902 3,930 379 (338) 5,873
Assets 431,829 179,854 14,598 33,344(2) 659,625
Capital expenditures 13,111 1,280 - 166 14,557
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
Interest expense(1) 2,715 1,260 26 277 4,278
Provision (benefit) for income taxes(1) 1,212 4,534 398 (305) 5,839
Assets 406,800 180,662 7,358 34,778(2) 629,598
Capital expenditures 12,183 1,375 7 149 13,714
[FN]
(1) Interest expense and the provision (benefit) for income taxes by
segment is an allocation of corporate amounts as debt and income tax
expense (benefit) are incurred at the corporate level.
(2) Other assets includes the Company's equity investment in the operations
of the NOARK Pipeline System, Limited Partnership, corporate assets not
allocated to segments, and assets for non-reportable segments.
</FN>
Intersegment sales by the exploration and production segment and
marketing segment to the gas distribution segment are priced in
accordance with terms of existing contracts and current market
conditions. Parent company assets include furniture and fixtures,
prepaid debt costs and prepaid pension costs. Parent company general
and administrative costs, depreciation expense and taxes other than
income are allocated to segments. All of the Company's operations are
located within the United States.
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
-8-
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. 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.
Quarter Ended March 31 2000 1999
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(in thousands)
Interest payments $606 $307
Income tax payments $ - $429
7. Contingencies and Commitments
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on NOARK's 7.15% Notes
due 2018. The Company's share of the several guarantee is 60%. At March
31, 2000 and December 31, 1999, the principal outstanding for these
Notes was $77.0 million. The Notes were issued in June 1998 and require
semi-annual principal payments of $1.0 million. The proceeds from the
issuance of the Notes were used to repay temporary financing provided
by the other general partner and outstanding amounts under an unsecured
revolving credit agreement. The temporary financing provided by the
other general partner was incurred in connection with the prepayment in
early 1998 of NOARK's 9.74% Senior Secured notes. Under the several
guarantee, the Company is required to fund its share of NOARK's debt
service which is not funded by operations of the pipeline. As a result
of the integration of NOARK Pipeline with the Ozark Gas Transmission
System, management of the Company believes that it will realize its
investment in NOARK over the life of the system. Therefore, no
provision for any loss has been made in the accompanying financial
statements. Additionally, the Company's gas distribution subsidiary has
transportation contracts for firm capacity of 82.3 MMcfd on NOARK's
integrated pipeline system. These contracts expire in 2002 and 2003,
and are renewable year-to-year thereafter until terminated by 180 days'
notice.
In May 1996, a class action suit was filed against the Company 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 has
been required by the state court to post a judgment bond which now
stands
-9-
at $109.3 million (verdict amount plus pre-judgment interest and 20
months 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 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
significant grounds for a successful appeal. The Company had asked the
trial judge to recuse himself due to his apparent bias toward the
plaintiffs and had also filed a motion with the trial court for
judgment notwithstanding the verdict or, in the alternative, for a new
trial. These motions were denied. The Company has filed and will
vigorously prosecute an appeal in the Arkansas Supreme Court. Based on
discussion with outside legal counsel, management of the Company
remains confident that the jury's verdict will be overturned and the
case remanded for a new trial. All appeal briefs have been filed and
oral argument has been set for May 25, 2000. A decision from the court
is likely by the end of 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.
However, management believes that the Company's ultimate liability, if
any, resulting from this case will not be material to its financial
position, but in any one year could be significant to the results of
operations. At March 31, 2000 and December 31, 1999, no amounts had
been accrued on this matter.
In its Form 8-K filed July 2, 1996, the Company disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas
oil and gas properties had been filed against it and two of its
wholly-owned subsidiaries. The lawsuit, which was brought by a party
who was originally included in (but opted out of) the class action
litigation described above, involves claims similar to those upon which
judgment was rendered against the Company and its subsidiaries. In
September 1998, another party who opted out of the class threatened the
Company with similar litigation. While the amounts of these pending and
threatened claims could be significant, management believes, based on
its extensive investigations and trial preparation, that these claims
are without merit, and that the Company's ultimate liability, if any,
will not be material to its consolidated financial position or results
of operations. This matter went to a non-jury trial as to liability on
January 10, 2000 and the Company is awaiting the court's ruling.
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
-10-
included in the class action litigation against its objections, but has
not pursued further action to remove itself from the class. If MMS does
remove itself from the class, its claims may be brought separately
under federal statutes that provide for treble damages and civil
penalties. In such event, the Company believes it would have defenses
that were not available in the class action litigation. While the
aggregate amount of MMS's claims could be significant, management
believes, based on its investigations, that the Company's ultimate
liability, if any, will not be material to its consolidated financial
position or results of operations.
The Company is subject to laws and regulations relating to the
protection of the environment. The Company's policy is to accrue
environmental and cleanup related costs of a noncapital nature when it
is both probable that a liability has been incurred and when the amount
can be reasonably estimated. Management believes any future remediation
or other compliance related costs will not have a material effect on
the financial position or reported results of operations of the
Company.
The Company is subject to other litigation and claims that have arisen
in the ordinary course of business. The Company accrues for such items
when a liability is both probable and the amount can be reasonably
estimated. In the opinion of management, the results of such litigation
and claims will not have a material effect on the results of operations
or the financial position of the Company.
-11-
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to the Company's financial condition
provided in the Company's Form 10-K for the year ended December 31, 1999, and
analyzes the changes in the results of operations between the three month period
ended March 31, 2000, and the comparable period of 1999.
RESULTS OF OPERATIONS
Net income for the three months ended March 31, 2000, was $9.2 million, or $.37
per share, compared to $9.1 million, or $.37 per share, in 1999. Improved
operating results experienced by the exploration and production segment during
the first quarter offset a decline in operating income experienced by the
natural gas utility segment caused by record warm weather. The exploration and
production segment benefited from both increased production and higher commodity
prices.
The following tables compare operating revenues and operating income by business
segment for the first three months of 2000 and 1999:
Increase
2000 1999 (Decrease)
---------- ---------- ----------
(in thousands)
Revenues
Exploration and production $ 24,761 $ 20,381 $ 4,380
Gas distribution 53,248 53,118 130
Marketing and other 43,357 22,090 21,267
Eliminations (24,453) (17,369) (7,084)
-------- -------- --------
$ 96,913 $ 78,220 $ 18,693
======== ======== ========
Operating Income
Exploration and production $ 8,688 $ 5,886 $ 2,802
Gas distribution 11,370 12,950 (1,580)
Marketing and other 998 1,093 (95)
-------- -------- --------
$ 21,056 $ 19,929 $ 1,127
======== ======== ========
Exploration and Production
Revenues for the exploration and production segment were up 21% and operating
income was up 48% for the three months ended March 31, 2000, as compared to the
same period in 1999. The Company benefited from both higher gas and oil prices
and increased gas and oil production. Gas and oil production during the first
quarter of 2000 was 8.7 billion cubic feet (Bcf) equivalent, up from 8.3 Bcf
equivalent in the fourth quarter and 8.5 Bcf equivalent for the same period in
1999. The increase in production resulted from new wells added in 1999. Gas
production was 7.8 Bcf for the three months ended March 31, 2000, compared to
7.7 Bcf for the same period in 1999. The Company's sales to its gas distribution
systems were 3.5 Bcf during the three months ended
-12-
March 31, 2000, compared to 3.2 Bcf for the same period in 1999. The Company's
oil production was 155 thousand barrels (MBbls) during the three months ended
March 31, 2000, up from 137 MBbls for the same period of 1999.
The Company received an average price of $2.62 per thousand cubic feet (Mcf) for
its gas production for the three months ended March 31, 2000, up from $2.46 per
Mcf for the same period of 1999. The Company hedged 4.0 Bcf of gas production in
the first quarter of 2000 at $2.50 per Mcf which had the effect of reducing the
average gas price by $.06 during the quarter. On a comparative basis, the
average price during the first quarter of 1999 included the positive effect of
hedges that increased the average price by $.47 per Mcf. Additionally, the
Company receives monthly demand charges related to the no-notice service it
makes available to the utility segment which increases the Company's average gas
price received. The Company has hedged approximately 5.5 Bcf of its production
in each of the second and third quarters of 2000 at an average NYMEX price of
$2.37, and has hedged 2.6 Bcf in the fourth quarter at an average price of $2.38
per Mcf. Additionally, the Company has natural gas price collars on 4.5 Bcf of
its fourth quarter 2000 gas production that have an average NYMEX price floor of
$2.52 per Mcf and an average ceiling price of $3.62 per Mcf. The Company
received an average price of $23.03 per barrel for its oil production during the
three months ended March 31, 2000, up from $12.16 per barrel for the same period
of 1999. For the remainder of 2000, the Company has hedges in place for 470,000
barrels at an average price of $23.25 per barrel.
Gas Distribution
Operating income of the gas distribution segment decreased 12% in the first
quarter of 2000, as compared to the first quarter of 1999. The decrease in
operating income was primarily due to weather which was 21% warmer than normal
and 6% warmer than in the same period of 1999. A reduction in rates that became
effective December 1999 also contributed to the decrease. The decrease in rates
was the result of an agreement with the Staff of the Arkansas Public Service
Commission during the third quarter of 1999 to close multiple open dockets and
to reduce annual rates by $1.4 million. The utility systems delivered 12.1 Bcf
to sales and end-use transportation customers during the three months ended
March 31, 2000, down from 12.6 Bcf for the same period in 1999.
The Company's average rate for its utility sales increased during the first
quarter of 2000 to $5.47 per Mcf, up from $5.09 per Mcf for the same period in
1999. The increase reflected higher prices paid for purchases of natural gas
which are passed through to customers under automatic adjustment clauses.
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 has received all required
regulatory approvals and is expected to close by June 1, 2000. 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 materially impact earnings as the loss
in operating income should be offset by a
-13-
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 and NOARK Pipeline
Operating income for the marketing segment was $1.0 million for the first
quarter of 2000, even with the same period in 1999, as an increase in gas
marketing revenues was offset by a comparable increase in purchased gas costs.
The Company marketed 18.2 Bcf of gas in the first three months of 2000, compared
to 12.7 Bcf for the same period in 1999.
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK)
pre-tax loss included in other income was $.6 million for the first quarter of
2000, even with the same period in 1999.
Operating Costs and Expenses
Operating costs and expenses, exclusive of purchased gas costs, increased 8% in
the first quarter of 2000, as compared to the same period in 1999. The increase
was primarily caused by higher operating and general expenses and increased
depreciation, depletion and amortization expense. The increase in operating and
general expenses was due primarily to increased production costs and increased
severance and ad valorem taxes in the exploration and production segment. The
increase in depreciation, depletion and amortization expense was due to the
increase in production in the exploration and production segment and an increase
in the amortization rate per unit of production. The amortization rate for this
segment averaged $1.03 per Mcf equivalent for the first quarter of 2000,
compared to $.98 per Mcf equivalent in the first quarter of 1999. The changes in
purchased gas costs for the gas distribution and marketing segments reflect
volumes purchased, prices paid for supplies and the mix of purchases from
intercompany versus third party sources.
The Company utilizes the full cost method of accounting for costs related to its
oil and natural gas properties. Under this method, all such costs (productive
and nonproductive) are capitalized and amortized on an aggregate basis over the
estimated lives of the properties using the units-of-production method. These
capitalized costs are subject to a ceiling test, however, which limits such
pooled costs to the aggregate of the present value of future net revenues
attributable to proved gas and oil reserves discounted at 10 percent plus the
lower of cost or market value of unproved properties. At March 31, 2000, the
Company's unamortized costs of oil and gas properties did not exceed this
ceiling amount. The Company's full cost ceiling is evaluated at the end of each
quarter. A decline in gas and oil prices from current levels, or other factors,
without other mitigating circumstances, could cause a future write-down of
capitalized costs and a non-cash charge against future earnings.
Interest expense for the three months ended March 31, 2000, was up 11% compared
to the same period in 1999, due to higher average borrowings and a lower level
of capitalized interest. Interest is capitalized in the exploration and
production segment on costs that are unevaluated and excluded from amortization.
-14-
The changes in the provisions for current and deferred income taxes recorded in
the three month period ended March 31, 2000, as compared to the same period in
1999, 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.
CHANGES IN FINANCIAL CONDITION
Changes in the Company's financial condition at March 31, 2000, as compared to
December 31, 1999, 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 2000 and 1999, net cash provided by operating activities was $35.6
million and $35.3 million, respectively, and exceeded the total of these routine
requirements.
Financing Requirements
The Company has access to $80.0 million of variable rate capital through two
banks. Of this amount, long-term variable rate credit facilities provide the
Company access to $60.0 million of revolving credit, and a short-term variable
rate credit facility provides the Company access to $20.0 million of revolving
credit. Of those amounts, $31.4 million was outstanding at March 31, 2000, all
of which was classified as long-term debt. During the first quarter of 2000, the
Company's revolving debt was reduced by $23.8 million, due to seasonally strong
cash flow. As a result, long-term debt at March 31, 2000, accounted for 58% of
the Company's capitalization, down from 61% at December 31, 1999, and should
drop to approximately 55% after the Company closes the sale of its Missouri
utility properties prior to June 1, 2000.
The Company expects its outstanding borrowings to increase during the remaining
months of 2000 as cash generated from operations will be less than the
requirements for routine capital expenditures 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 2000 were $14.6 million,
compared to $13.7 million for the same period in 1999.
The Company remains confident that it will prevail in its appeal of the royalty
owners proceeding described in Part II, Item 1 and in Note 7 to the Consolidated
Financial Statements included in this Form 10-Q. 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.
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At March 31, 2000, the NOARK partnership had outstanding debt totaling
approximately $77.0 million. The Company and the other general partner of NOARK
have severally guaranteed the principal and interest payments on the NOARK debt.
The Company's share of the several guarantee is 60%.
Working Capital
Accounts receivable has declined since December 31, 1999, due primarily to
seasonally lower gas deliveries of the gas distribution segment, offset
partially by increases in sales by the marketing segment. The decrease in
inventories since December 31, 1999, 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, 1999, due primarily to
seasonally lower gas purchases of the gas distribution segment and to the timing
of expenditures. Short-term debt has declined since December 31, 1999 due to the
pay off of the Company's short-term revolving credit facility. 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.
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.
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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
6% 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, 2000. There have been no material changes in the
interest rate risk information that was presented in the Company's 1999 10-K.
Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production and marketing activity against
the inherent price risks of adverse price fluctuations or locational pricing
differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps include (1) transactions in which one
party will pay a fixed price (or variable price) for a notional quantity in
exchange for receiving a variable price (or fixed price) based on a published
index (referred to as price swaps), and (2) transactions in which parties agree
to pay a price based on two different indices (referred to as basis swaps).
The primary market risk related to these derivative contracts is the
volatility in market prices for natural gas and crude oil. However, this market
risk is offset by the gain or loss recognized upon the related sale of the
natural gas or oil that is hedged. Credit risk relates to the risk of loss as a
result of non-performance by the Company's counterparties. The counterparties
are primarily major investment and commercial banks which management believes
present minimal credit risks.
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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, 2000. At March 31, 2000, the
"Carrying Amount" of these financial instruments exceeded the "Fair Value" by
$11.1 million.
Expected Maturity Date
-----------------------------------------------------------
2000 2001 2002
----------------- ----------------- -----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 13.7 .7 .5
Weighted average price per Mcf $2.36 $2.57 $2.57
Contract amount (in millions) $32.4 $24.0 $1.7 $1.5 $1.2 $1.1
Swaps with a fixed price payment
Contract volume (Bcf) .3 - -
Weighted average price per Mcf $2.86 - -
Contract amount (in millions) $.9 $.9 - - - -
Price collar
Contract volume (Bcf) 4.4 9.6 -
Weighted average floor price
per Mcf $2.52 $2.56 -
Contract amount of floor
(in millions) $11.0 $11.5 $24.6 $25.5 - -
Weighted average ceiling price
per Mcf $3.62 $3.19 -
Contract amount of ceiling
(in millions) $15.7 $14.7 $30.6 $29.4 - -
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 4.4 9.6 -
Weighted average price per Bbl $23.24 $17.49 -
Contract amount (in millions) $11.1 $9.7 $1.3 $.9 - -
Price floor
Contract volume (MBbls) - 325 -
Weighted average price per Bbl - $18.00 -
Contract amount (in millions) - - $5.9 $6.1 - -
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PART II
OTHER INFORMATION
Item 1
In May 1996, a class action suit was filed against the Company 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 has been
required by the state court to post a judgment bond which now stands at $109.3
million (verdict amount plus pre-judgment interest and 20 months 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 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 significant grounds for a
successful appeal. The Company had asked the trial judge to recuse himself due
to his apparent bias toward the plaintiffs and had also filed a motion with the
trial court for judgment notwithstanding the verdict or, in the alternative, for
a new trial. These motions were denied. The Company has filed and will
vigorously prosecute an appeal in the Arkansas Supreme Court. Based on
discussion with outside legal counsel, management of the Company remains
confident that the jury's verdict will be overturned and the case remanded for a
new trial. All appeal briefs have been filed and oral argument has been set for
May 25, 2000. A decision from the court is likely by the end of 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. However, management believes that the Company's ultimate liability, if
any, resulting from this case will not be material to its financial position,
but in any one year could be significant to the results of operations. At March
31, 2000 and December 31, 1999, no amounts had been accrued on this matter.
In its Form 8-K filed July 2, 1996, the Company disclosed that a lawsuit
relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
The lawsuit, which was brought by a party who was originally included in (but
opted out of) the class action litigation described above, involves claims
similar to those upon which judgment was rendered against the Company and its
subsidiaries. In
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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 significant, management believes, based on its extensive
investigations and trial preparation, that these claims are without merit and,
that the Company's ultimate liability, if any, will not be material to its
consolidated financial position or results of operations. This matter went to a
non-jury trial as to liability on January 10, 2000 and the Company is awaiting
the court's ruling.
The United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the class action litigation. MMS was included in the class action
litigation against its objections, but has not pursued further action to remove
itself from the class. If MMS does remove itself from the class, its claims may
be brought separately under federal statutes that provide for treble damages and
civil penalties. In such event, the Company believes it would have defenses that
were not available in the class action litigation. While the aggregate amount of
MMS's claims could be significant, 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(b)
No developments required to be reported under Items 2 - 6(b) occurred during the
quarter ended March 31, 2000.
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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 5, 2000 /s/ GREG D. KERLEY
----------------- ---------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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