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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, 2001
------------------
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.)
2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
(281) 618-4700
(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 October 10, 2001
---------------------------- -------------------------------
Common Stock, Par Value $.10 25,191,747
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- 1 -
PART I
FINANCIAL INFORMATION
- 2 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
September 30, December 31,
2001 2000
-------------- ------------
($ in thousands)
Current Assets
Cash $ 673 $ 2,386
Accounts receivable 27,959 77,041
Inventories, at average cost 26,112 17,000
Under-recovered purchased gas costs 2,097 12,942
Hedging asset - SFAS No.133 8,492 -
Other 4,719 3,486
--------- ---------
Total current assets 70,052 112,855
--------- ---------
Investments 15,980 15,574
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 945,233 872,023
Gas distribution systems 191,111 190,893
Gas in underground storage 32,853 27,867
Other 28,463 27,940
--------- ---------
1,197,660 1,118,723
Less: Accumulated depreciation,
depletion and amortization 591,292 554,616
--------- ---------
606,368 564,107
--------- ---------
Other Assets 14,811 12,842
--------- ---------
Total Assets $ 707,211 $ 705,378
========= =========
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
September 30, December 31,
2001 2000
------------- ------------
($ in thousands)
Current Liabilities
Short-term debt $ - $ 171,000
Accounts payable 30,432 54,304
Taxes payable 2,391 4,346
Interest payable 6,876 2,806
Customer deposits 4,572 4,799
Deferred income tax payable 3,312 -
Other 3,295 2,629
--------- ---------
Total current liabilities 50,878 239,884
--------- ---------
Long-Term Debt, less current portion above 356,300 225,000
--------- ---------
Other Liabilities
Deferred income taxes 115,759 97,431
Other 1,910 1,772
--------- ---------
117,669 99,203
--------- ---------
Commitments and Contingencies
Minority Interest in Partnership 6,626 -
--------- ---------
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 20,202 20,220
Retained earnings 176,253 148,353
Accumulated other comprehensive income 5,970 -
--------- ---------
205,199 171,347
Less: Common stock in treasury, at cost,
2,547,041 shares in 2001 and
2,556,908 shares in 2000 28,432 28,485
Unamortized cost of 225,794
restricted shares in 2001
and 241,452 restricted shares
in 2000, issued under stock
incentive plan 1,029 1,571
--------- ---------
175,738 141,291
--------- ---------
Total Liabilities and Shareholders' Equity $ 707,211 $ 705,378
========= =========
The accompanying notes are an integral part
of the financial statements.
- 4 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2001 2000 2001 2000
---------- ---------- ---------- ----------
($ in thousands, except per share amounts)
Operating Revenues
Gas sales $ 41,975 $ 32,421 $ 189,533 $ 130,399
Gas marketing 11,392 38,109 64,104 103,497
Oil sales 4,348 3,683 13,192 11,060
Gas transportation and other 1,681 1,129 5,719 5,782
---------- ---------- ---------- ----------
59,396 75,342 272,548 250,738
---------- ---------- ---------- ----------
Operating Costs and Expenses
Gas purchases - utility 4,119 3,275 54,617 30,501
Gas purchases - marketing 10,518 37,187 61,098 100,306
Operating expenses 9,437 8,238 29,115 25,580
General and administrative expenses 5,049 5,217 17,456 17,907
Unusual item - 2,000 - 111,288
Depreciation, depletion and amortization 13,881 11,627 38,155 33,969
Taxes, other than income taxes 2,129 1,914 7,230 6,096
---------- ---------- ---------- ----------
45,133 69,458 207,671 325,647
---------- ---------- ---------- ----------
Operating Income (Loss) 14,263 5,884 64,877 (74,909)
---------- ---------- ---------- ----------
Interest Expense
Interest on long-term debt 5,787 7,039 18,558 17,184
Other interest charges 180 212 1,009 1,317
Interest capitalized (375) (548) (1,235) (1,868)
---------- ---------- ---------- ----------
5,592 6,703 18,332 16,633
---------- ---------- ---------- ----------
Other Income (Expense) (184) (417) (162) 1,581
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes &
Minority Interest 8,487 (1,236) 46,383 (89,961)
---------- ---------- ---------- ----------
Minority Interest in Partnership (261) - (645) -
---------- ---------- ---------- ----------
Income (Loss) Before Income Taxes 8,226 (1,236) 45,738 (89,961)
---------- ---------- ---------- ----------
Income Tax Provision (Benefit)
Current - - - -
Deferred 3,208 (482) 17,838 (35,084)
---------- ---------- ---------- ----------
3,208 (482) 17,838 (35,084)
---------- ---------- ---------- ----------
Income (Loss) Before Extraordinary Item 5,018 (754) 27,900 (54,877)
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569 Tax Benefit) - - - (890)
---------- ---------- ---------- ----------
Net Income (Loss) $ 5,018 $ (754) $ 27,900 $ (55,767)
========== ========== ========== ==========
Basic Earnings Per Share $0.20 ($0.03) $1.11 ($2.23)
========== ========== ========== ==========
Basic Average Common Shares Outstanding 25,190,387 25,034,306 25,189,045 25,035,626
========== ========== ========== ==========
Diluted Earnings Per Share $0.20 ($0.03) $1.09 ($2.23)
========== ========== ========== ==========
Diluted Average Common Shares Outstanding 25,621,214 25,034,306 25,591,554 25,035,626
========== ========== ========== ==========
Dividends Declared Per Share Payable 5/5/00 - - - $0.06
========== ========== ========== ==========
The accompanying notes are an integral part
of the financial statements.
- 5 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
--------------------
2001 2000
-------- --------
($ in thousands)
Cash Flows From Operating Activities
Net income (loss) $ 27,900 $(55,767)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 39,342 35,010
Deferred income taxes 17,838 (35,084)
Equity in loss of NOARK partnership 1,043 1,510
Gain on sale of Missouri utility assets - (3,209)
Extraordinary loss due to early retirement
of debt (net of tax) - 890
Minority interest in partnership 271 -
Change in assets and liabilities:
Accounts receivable 49,082 (287)
Inventories (9,112) (319)
Under recovered purchased gas costs 10,845 (8,025)
Accounts payable (23,872) 3,686
Interest payable 4,070 4,613
Other current assets and liabilities (2,750) 3,978
-------- --------
Net cash provided by (used in) operating activities 114,657 (53,004)
-------- --------
Cash Flows From Investing Activities
Capital expenditures (77,143) (57,422)
Sale of Missouri utility assets - 32,000
Sale of oil and gas properties - 13,651
Investment in NOARK partnership (1,449) (1,620)
Change in gas stored underground (4,986) (2,172)
Other items 553 (132)
-------- --------
Net cash used in investing activities (83,025) (15,695)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt (39,700) 103,600
Retirement of private placement notes and
prepayment penalty - (24,910)
Contributions from minority interest partner 6,355 -
Payment on revolving short-term debt - (7,500)
Cash dividends - (3,004)
-------- --------
Net cash provided by (used in) financing activities (33,345) 68,186
-------- --------
Decrease in cash (1,713) (513)
Cash at beginning of year 2,386 1,240
-------- --------
Cash at end of period $ 673 $ 727
======== ========
The accompanying notes are an integral part
of the financial statements.
- 6 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
($ in thousands) ($ in thousands)
Net income (loss) $ 5,018 $ (754) $ 27,900 $(55,767)
Other comprehensive income:
Unrealized gain on derivative instruments 2,112 - 21,299 -
-------- -------- -------- --------
Comprehensive Income (Loss) $ 7,130 $ (754) $ 49,199 $(55,767)
======== ======== ======== ========
Reconciliation of Accumulated Other Comprehensive
Income (Loss):
Balance, Beginning of Period $ 4,601 $ - $ - $ -
Cumulative effect of adoption of SFAS No. 133 - - (36,963) -
Current period reclassification to earnings (743) - 21,634 -
Current period change in derivative instruments 2,112 - 21,299 -
-------- -------- -------- --------
Balance, End of Period $ 5,970 $ - 5,970 $ -
======== ======== ======== ========
The accompanying notes are an integral part
of the financial statements.
- 7 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2001
1. BASIS OF PRESENTATION
The financial statements included herein are unaudited; however, such
financial statements reflect 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 2000
Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial
Statements.
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. At September 30, 2001, the
Company's unamortized costs of oil and gas properties exceeded this
ceiling amount by $54.8 million due to low gas prices in effect on that
date. The market price for natural gas at Henry Hub was $1.86 on
September 30, 2001. However, due to the subsequent recovery in the
market prices for natural gas the Company was not required to record a
write-down of its oil and gas properties. 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.
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. The Company had options for 997,700 shares of common stock
with a weighted average exercise price of $13.90 per share at September
30, 2001, and options for 2,033,665 shares with an average exercise
price of $10.53 per share at September 30,
- 8 -
2000, that were not included in the calculation of diluted shares
because they would have had an antidilutive effect.
4. UNUSUAL ITEMS
During the first nine months of 2000, the Company recorded unusual
charges totaling $111.3 million related to the adverse Hales judgment
and other litigation.
5. DIVIDEND PAYABLE
As a result of the financial impact of the Hales judgment in the second
quarter of 2000, the Company has indefinitely suspended payment of
quarterly dividends on its common stock.
6. LONG-TERM DEBT
In July 2001, the Company arranged a new unsecured revolving credit
facility with a group of banks to replace its existing short-term
credit facility that was put in place in July 2000. The new revolving
credit facility has a capacity of $160 million and a three-year term.
The interest rate on the new facility is 137.5 basis points over the
current London Interbank Offered Rate (LIBOR), and was 4.9% at
September 30, 2001. The new credit facility contains covenants which
impose certain restrictions on the Company. Under the credit agreement,
the Company may not issue total debt in excess of 75% of its total
capital, must maintain a certain level of shareholders' equity, and the
Company must maintain a ratio of earnings before interest, taxes,
depreciation and amortization (EBITDA) to fixed charges of at least
3.75 or higher through March 30, 2002. These covenants change over the
term of the credit facility and generally become more restrictive. At
September 30, 2001, the Company's revolving credit facility had a
balance of $131.3 million and was classified as long-term debt in the
Company's balance sheet. The Company has also entered into an interest
rate swap for calendar year 2002 that allows the Company to pay a fixed
interest rate of 5.7% on $50 million of its outstanding revolving debt.
7. DERIVATIVE AND HEDGING ACTIVITIES
Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No.
137 and SFAS No. 138, was adopted by the Company on January 1, 2001.
SFAS No. 133 requires that each derivative be recognized in the balance
sheet as either an asset or liability measured at its fair value.
Special accounting for qualifying hedges allows a derivative's gains
and losses
- 9 -
to offset related results on the hedged item in the income statement.
Upon adoption of SFAS No. 133 on January 1, 2001, the Company recorded
a transition obligation of $60.6 million related to cash flow hedges
that are intended to reduce the volatility in commodity prices for the
Company's forecasted oil and gas production. At September 30, 2001, the
Company recorded assets of $9.8 million related to its commodity and
interest rate cash flow hedges. Additionally, at September 30, 2001,
the Company recorded net of tax cumulative income to other
comprehensive income (equity section of the balance sheet) of $6.0
million. The amount recorded in other comprehensive income will be
taken to the income statement as the physical transactions being hedged
occur. Additional volatility in earnings and other comprehensive income
may occur in the future as a result of the adoption of SFAS No. 133.
8. SEGMENT INFORMATION
The Company applies SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information." The Company's reportable business
segments have been identified based on the differences in products or
services provided. Revenues for the exploration and production segment
are derived from the production and sale of natural gas and crude oil.
Revenues for the gas distribution segment arise from the transportation
and sale of natural gas at retail. The marketing segment generates
revenue through the marketing of both Company and third party produced
gas volumes.
Summarized financial information for the Company's reportable segments
are shown in the following table. The "Other" column includes items
related to non-reportable segments (real estate and pipeline
operations) and corporate items.
Exploration
and Gas
Production Distribution Marketing Other Total
----------- ------------ --------- --------- ---------
($ in thousands)
Three months ended September 30, 2001:
--------------------------------------
Revenues from external customers $ 34,079 $ 13,925 $ 11,392 $ -- $ 59,396
Intersegment revenues 1,988 20 25,088 112 27,208
Operating income (loss) 15,913 (2,356) 640 66 14,263
Depreciation, depletion and
amortization expense 12,344 1,496 17 24 13,881
Interest expense(1) 5,087 175 77 253 5,592
Provision (benefit) for income taxes(1) 4,127 (972) 219 (166) 3,208
Assets 523,789 144,475 9,474 29,473(2) 707,211(2)
Capital expenditures 27,870(4) 1,144 -- 139 29,153(4)
- 10 -
Exploration
and Gas
Production Distribution Marketing Other Total
------------ ------------- ---------- --------- ---------
($ in thousands)
Three months ended September 30, 2000:
--------------------------------------
Revenues from external customers $ 21,180 $ 16,052 $ 38,110 $ -- $ 75,342
Intersegment revenues 5,337 29 20,796 112 26,274
Unusual items (2,000)(3) -- -- -- (2,000)(3)
Operating income (loss) 7,166(3) (1,745) 464 (1) 5,884(3)
Depreciation, depletion and
amortization expense 10,092 1,494 18 23 11,627
Interest expense(1) 5,570 859 -- 274 6,703
Provision (benefit) for income taxes(1) 638 (1,008) 176 (288) (482)
Assets 452,167 154,716 18,674 33,350(2) 658,907(2)
Capital expenditures 12,497 1,351 -- 170 14,018
Nine months ended September 30, 2001:
-------------------------------------
Revenues from external customers $ 93,570 $ 114,874 $ 64,104 $ -- $ 272,548
Intersegment revenues 23,948 169 98,036 336 122,489
Operating income 56,173 6,274 2,227 203 64,877
Depreciation, depletion and
amortization expense 33,429 4,604 50 72 38,155
Interest expense(1) 15,664 1,646 239 783 18,332
Provision (benefit) for income taxes(1) 15,549 2,028 775 (514) 17,838
Assets 523,789 144,475 9,474 29,473(2) 707,211(2)
Capital expenditures 73,503(4) 3,313 17 310 77,143(4)
Nine months ended September 30, 2000:
-------------------------------------
Revenues from external customers $ 54,694 $ 92,546 $ 103,498 $ -- $ 250,738
Intersegment revenues 21,369 110 49,449 335 71,263
Unusual items (111,288)(3) -- -- -- (111,288)(3)
Operating income (loss) (85,806)(3) 8,933 2,001 (37) (74,909)(3)
Depreciation, depletion and
amortization expense 28,854 4,991 53 71 33,969
Interest expense(1) 12,436 3,386 -- 811 16,633
Provision (benefit) for income taxes(1) (38,553) 3,351 781 (663) (35,084)
Assets 452,167 154,716 18,674 33,350(2) 658,907(2)
Capital expenditures 53,014 4,003 4 401 57,422
(1) Interest expense and the provision (benefit) for income taxes by
segment reflect an allocation of corporate amounts as debt and the
provision (benefit) for income taxes 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.
(3) Includes an unusual charge of $2.0 million in the third quarter of
2000 for litigation and a loss of $109.3 million in the second
quarter of 2000 for the Hales judgment. Excluding these items,
operating income for the exploration and production segment would
have been $9.2 million and $25.5 million for the three and nine
month periods ended September 30, 2000, respectively.
(4) Capital expenditures for the Exploration and Production segment
includes $7.7 million and $16.7 for the three and nine month
periods ended September 30, 2001, related to the consolidated
results of a limited
- 11 -
partnership. The Company received reimbursement of $6.4 million of
the year to date amount from the minority interest partner.
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. The exploration and production
segment includes the consolidated amounts for a limited partnership in
which the Company is the controlling partner. All of the Company's
operations are located within the United States.
9. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
Three Months Nine Months
Periods Ended September 30 2001 2000 2001 2000
-----------------------------------------------------------------------
(in thousands)
Interest payments $1,598 $2,323 $14,830 $12,394
Income tax payments $ -- $ 206 $ -- $ 206
10. MINORITY INTEREST IN PARTNERSHIP
In the second quarter of 2001, the Company formed a limited partnership
with an investor to drill and complete the first 14 development wells
in the Company's Overton Field located in Smith County, Texas. Because
Southwestern is the sole general partner and controls the partnership,
the operating and financial results are consolidated with the Company's
exploration and production results and the investor's share of the
partnership activity is reported as a minority interest item in the
financial statements. The Company will contribute 50% of the capital
required to drill the first 14 wells. Revenues and expenses are
allocated 65% to the Company prior to payout of the initial investment
and 85% to the Company thereafter.
11. 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. At September 30, 2001 and December 31, 2000, the principal
outstanding for these Notes was $74.0 million and $75.0 million,
respectively. The Company's share of the several guarantee is 60%. The
Notes were issued in June 1998 and require semi-annual principal
payments of $1.0
- 12 -
million. 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 66.9 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.
The Company is also 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.
- 13 -
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, 2000, and
analyzes the changes in the results of operations between the three and nine
month periods ended September 30, 2001, and the comparable periods of 2000.
RESULTS OF OPERATIONS
Net income for the three months ended September 30, 2001 was $5.0 million, or
$.20 per share, compared to a net loss of $.8 million, or $.03 per share, in
2000. The increase in net income was due to improved operating results
experienced by the exploration and production segment. This segment benefited
from both increased production and higher commodity prices.
Net income for the nine months ended September 30, 2001, was $27.9 million, or
$1.11 of basic earnings per share ($1.09 per share on a fully diluted basis),
compared to a net loss for the nine months ended September 30, 2000, of $55.8
million, or $2.23 per share. The Company's results for the nine months ended
September 30, 2000, included an unusual charge of $109.3 million for the adverse
judgment in the Hales royalty lawsuit ($66.7 million after-tax), an
extraordinary loss on the early retirement of debt, a $3.2 million gain from the
sale of the Company's Missouri utility properties, and a $2.0 million charge in
the third quarter related to other litigation. Excluding these unusual and
extraordinary items, Southwestern would have reported net income of $11.1
million, or $.44 per share, for the first nine months of 2000.
Exploration and Production
Overview
The Company's exploration and production segment's revenue, profitability and
future rate of growth are substantially dependent upon prevailing prices for
natural gas and oil, which are dependent upon numerous factors beyond its
control, such as economic, political and regulatory developments and competition
from other sources of energy. The energy markets have historically been very
volatile, and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future.
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
2001 2000 2001 2000
------------------- -------------------
Revenues (in thousands) $36,067 $26,517 $117,518 $ 76,063
Operating income (loss) (in thousands) $15,913 $ 7,166(1) $ 56,173 $(85,806)(1)
- 14 -
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
2001 2000 2001 2000
------------------- -------------------
Gas production (Bcf) 9,420 7,936 26,098 23,636
Oil production (MBbls) 183 171 535 495
Total production (MMcfe) 10,518 8,962 29,308 26,606
Average gas price per Mcf $3.37 $2.87 $3.97 $2.71
Average oil price per Bbl $23.75 $21.56 $24.67 $22.36
Operating expenses per Mcfe
Production expenses $0.38 $0.40 $0.44 $0.38
Production taxes $0.15 $0.15 $0.18 $0.14
General & administrative expenses $0.21 $0.26 $0.32(2) $0.29
Full cost pool amortization $1.15 $1.09 $1.11 $1.05
(1) Includes an unusual charge of $2.0 million in the third quarter of 2000
for litigation and a loss of $109.3 million in the second quarter of
2000 for the Hales judgment. Excluding these items, operating income
for the exploration and production segment would have been $9.2 million
and $25.5 million for the three and nine month periods ended September
30, 2000, respectively.
(2) Includes $2.0 million, or $.07 per Mcfe for the nine months ended
September 30, 2001, for settled litigation.
Revenues and Operating Income
Revenues for the exploration and production segment were up 36% for the three
months ended September 30, 2001 and up 55% for the nine month period ended
September 30, 2001, compared to the same periods in 2000. The increases were due
to both higher gas and oil prices and increased gas and oil production.
Operating income, excluding unusual items, for the exploration and production
segment was up $6.7 million for the three months ended September 30, 2001, and
up $30.7 million for the first nine months of 2001, both as compared to the same
periods in 2000. The improvements in operating income were due to the higher
segment revenues, partially offset by increased depreciation, depletion and
amortization expense.
Production
Gas and oil production during the third quarter of 2001 was 10.5 billion cubic
feet (Bcf) equivalent, up 17% from 9.0 Bcf equivalent for the same period in
2000. The increase in production primarily resulted from new wells added in 2000
and 2001 in the Company's Arkoma Basin and Gulf Coast operating areas. Gas
production was 9.4 Bcf for the third quarter of 2001, compared to 7.9 Bcf for
the same period in 2000. For the nine months ended September 30, 2001, gas and
oil production was 29.3 Bcf equivalent, up 10% from 26.6 Bcf equivalent for the
same
- 15 -
period in 2000. Gas production was 26.1 Bcf for the first nine months of 2001
compared to 23.6 in 2000.
The Company's sales to its gas distribution systems were 3.7 Bcf during the nine
months ended September 30, 2001, compared to 5.8 Bcf for the same period in
2000. Gas supply for the Company's gas distribution systems is provided using a
competitive bidding process. Future sales to the gas distribution systems will
be dependent upon the Company's success in obtaining gas supply contracts with
the utility systems.
During the third quarter of 2001, the Company was successful in obtaining four
out of six bid packages to supply the gas distribution systems with base load
and swing-service gas supplies beginning in the fourth quarter of 2001. The
Company was unsuccessful in bidding on a no-notice gas supply package that it
previously held. This no-notice gas supply package extends through the first
quarter of 2002. In the future, the Company will continue to bid to obtain these
gas supply packages, although there is no assurance that it will be successful.
If successful, the Company cannot predict the amount of premium that would be
associated with the new contracts.
Commodity Prices
The Company realized an average price of $3.37 per thousand cubic feet (Mcf) for
its natural gas production for the three months ended September 30, 2001, up
from $2.87 per Mcf for the same period of 2000. For the first nine months of
2001, the Company realized an average gas price of $3.97 per Mcf, up from $2.71
for the same period of 2000. The Company hedged 20.4 Bcf of gas production in
the first nine months of 2001 primarily through zero-cost collars, which had the
effect of increasing the average gas price by $.57 per Mcf in the third quarter
of 2001 and reducing the average gas price by $.78 per Mcf in the first nine
months of 2001. On a comparative basis, the average realized price during the
third quarter of 2000 was reduced by $1.36 per Mcf and was reduced by $.73 per
Mcf in the first nine months of 2000, due to the effect of commodity price
hedges.
For the remainder of 2001, the Company has 6.2 Bcf of gas production hedged with
collars having an average NYMEX floor price of $4.06 per Mcf and an average
NYMEX ceiling price of $4.95 per Mcf. The Company also has .4 Bcf of gas
production for the remainder of 2001 hedged with fixed-price swaps at an average
NYMEX price of $3.19 per Mcf. For 2002, the Company has fixed-price swaps on
13.0 Bcf at an average NYMEX price of $2.88 and a collar on 6.0 Bcf with a floor
price of $4.00 and a ceiling price of $4.72. For 2003, the Company has
fixed-price swaps on 9.2 Bcf at an average NYMEX price of $3.18. See Part I,
Item 3 of this Form 10-Q for additional information regarding the Company's
commodity price risk hedging activities.
The Company received an average price of $23.75 per barrel for its oil
production during the three months ended September 30, 2001, up from $21.56 per
barrel for the same period of 2000.
- 16 -
For the nine months ended September 30, 2001, the Company received an average
price of $24.67 per barrel for its oil production, up from $22.36 per barrel for
the same period of 2000. For the remainder of 2001, the Company has a collar on
75,000 barrels with an average floor of $27.40 per barrel, and an average
ceiling of $29.95 per barrel, and a hedge on 24,000 barrels at an average NYMEX
price of $17.49 per barrel.
Operating Costs and Expenses
Operating costs and expenses for the exploration and production segment
increased in the third quarter and first nine months of 2001 due to higher
production related expenses and increased depreciation, depletion and
amortization expense. The increase in operating expenses was due to increased
production volumes, a higher level of workover expenses and an industry-wide
increase in costs related to normal production activities. Additionally,
increased severance and ad valorem taxes resulted from both increased production
volumes and higher commodity prices. The Company anticipates that the
inflationary increases in exploration and production related costs that have
resulted from an overall increase in the activity level of the domestic oil and
gas industry are beginning to decline along with the current level of commodity
prices. The increases in depreciation, depletion and amortization expense were
due to the increase in production and an increase in the amortization rate per
unit of production. The full cost pool amortization rate for this segment
averaged $1.15 per Mcf equivalent for the third quarter of 2001 and $1.11 for
the first nine months of 2001, compared to $1.09 per Mcf equivalent for the
third quarter of 2000 and $1.05 for the first nine months of 2000.
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, 2001, the
Company's unamortized costs of oil and gas properties exceeded this ceiling
amount by $54.8 million due to low gas prices in effect on that date. The market
price for natural gas at Henry Hub was $1.86 on September 30, 2001. However, due
to the subsequent recovery in the market prices for natural gas, the Company was
not required to record a write-down of its oil and gas properties. 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.
Earlier in 2001, the Company formed a limited partnership with an investor to
drill and complete the first 14 development wells in the Company's Overton Field
located in Smith County, Texas. This partnership was created to provide the
capital necessary to accelerate the field's development. The Overton properties
were acquired by the Company in April 2000 and have multiple
- 17 -
development locations through the downspacing of the existing producing units.
Because Southwestern is the sole general partner and controls the partnership,
operating and financial results for the partnership are consolidated with the
other operations of the Company and the investor's share of the partnership
activity is reported as a minority interest item in the financial statements.
Gas Distribution
Overview
The operating results of the Company's gas distribution segment are highly
seasonal. This segment typically realizes operating losses in the second and
third quarters of the year and realizes operating income during the winter
heating season in the first and fourth quarters. The extent and duration of
heating weather also impacts the profitability of this segment, although the
Company has a weather normalization clause in its filed rate tariffs that
lessens the impact of revenue increases and decreases which might result from
weather variations during the winter heating season. The gas distribution
segment's profitability is also dependent upon the timing and amount of
regulatory rate increases that are filed with and approved by the Arkansas
Public Service Commission. For periods subsequent to allowed rate increases, the
Company's profitability is impacted by its ability to manage and control this
segment's operating costs and expenses.
Three Months Nine Months
Ended September 30, Ended September 30,
--------------------- ---------------------
2001 2000 2001 2000
--------------------- ---------------------
($ in thousands, except for per Mcf amounts)
Revenues $ 13,945 $ 16,081 $115,043 $ 92,656
Gas purchases 6,099 8,611 78,536 51,869
Operating costs and expenses 10,202 9,215 30,233 31,854
-------- -------- -------- --------
Operating income (loss) $ (2,356) $ (1,745) $ 6,274 $ 8,933
-------- -------- -------- --------
Deliveries (Bcf)
Sales and end-use transportation 3.0 3.4 17.1 20.7
Off-system transportation 1.6 .7 2.6 2.8
Average number of customers 131,313 131,082 133,890 159,109
Average sales rate per Mcf $7.85 $8.40 $9.14 $6.18
Heating weather - degree days 51 44 2,378 2,026
- percent of normal - % - % 96% 81%
Note: Amounts and statistics for nine months ended September 30, 2000, include
the operations of the Company's Missouri properties that were sold in
May 2000.
- 18 -
On May 31, 2000, the Company completed the sale of its Missouri gas distribution
assets for $32.0 million. The sale resulted in a pre-tax gain of approximately
$3.2 million and proceeds from the sale were used to pay down debt. As a result
of the adverse Hales judgment, the Company's Board of Directors had authorized
management to pursue the sale of the Company's remaining gas distribution
operations. The Company has suspended the sale process as it did not result in
an acceptable bid. Although the Company may decide to sell its gas distribution
segment in the future, it currently plans to operate these assets as a
continuing part of its business.
Revenues and Operating Income
Revenues for the three months ended September 30, 2001 were down due to
decreased deliveries to sales and end use customers and a decrease in the
average sales rate, as compared to the comparable period of 2000. Revenues for
the nine months ended September 30, 2001 were up primarily due to the increased
cost of gas supply. The high cost of gas supply is reflected in the Company's
average rate for its utility sales which increased during the first nine months
of 2001 to $9.14 per Mcf, up from $6.18 per Mcf for the same period in 2000. The
average sales rate for the third quarter of 2001 was $7.85 compared to $8.40 for
the same period of 2000. The prices paid for purchases of natural gas are passed
through to customers under automatic adjustment clauses.
Operating income of the gas distribution segment decreased 35% in the third
quarter of 2001 and decreased 30% in the first nine months of 2001, as compared
to the same periods of 2000. The decrease in operating income for the three
months ended September 30, 2001 was primarily due to increased operating costs
and expenses. The decrease in operating income for the nine month period was due
primarily to the impact of the sale of the Company's Missouri gas distribution
assets in May 2000. Weather during the first nine months of 2001 was 4% warmer
than normal and 17% colder than in the same period of 2000. The Company has a
weather normalization clause in its filed rate tariffs which lessens the impact
of revenue increases and decreases that might result from weather variations
during the winter heating season.
Deliveries
The utility systems delivered 3.0 Bcf to sales and end-use transportation
customers during the third quarter of 2001, down from 3.4 Bcf for the same
period in 2000. For the nine months ended September 30, 2001, the utility
systems delivered 17.1 Bcf to sales and end-use transportation customers,
compared to 20.7 Bcf for the same period in 2000. The decrease in deliveries for
the first nine months of 2001 was due to the sale of the Missouri properties.
Operating Costs and Expenses
The changes in purchased gas costs for the gas distribution segment reflect
volumes purchased, prices paid for supplies, the mix of purchases from
intercompany versus third party sources and the sale of the Missouri assets as
discussed above. Other operating costs and expenses of the gas
- 19 -
distribution segment for the three months ended September 30, 2001 were higher
due to an increase in the level of uncollectable accounts that resulted from the
exceptionally high gas costs during the previous winter heating season, and from
general inflationary increases. Other operating costs and expenses for the nine
months ended September 30, 2001 were lower than the comparable period in 2000
primarily due to the sale of the Missouri assets.
Marketing and Other
Three Months Nine Months
Ended September 30, Ended September 30,
------------------- -------------------
2001 2000 2001 2000
------------------- -------------------
Marketing revenues (in thousands) $36,480 $58,906 $162,140 $152,947
Marketing operating income (in thousands) $640 $464 $2,227 $2,001
Gas volumes marketed (Bcf) 13.5 14.6 36.9 48.5
Marketing
The decrease in gas marketing revenues in the third quarter of 2001 was due to a
decrease in both gas prices and volumes marketed. The increase in gas marketing
revenues for the nine months ended September 30, 2001, relates to a substantial
increase in natural gas commodity prices from the prior year, and was largely
offset by a comparable increase in purchased gas costs. Operating income for the
marketing segment was $.6 million for the third quarter of 2001 and $2.2 million
for the first nine months of 2001, compared to $.5 million and $2.0 million for
the comparable periods in 2000. The Company marketed 13.5 Bcf of gas in the
third quarter of 2001 and 36.9 Bcf in the first nine months of 2001, compared to
14.6 Bcf and 48.5 Bcf for the same periods in 2000. The decreases in volumes
marketed resulted from a planned decrease in volumes marketed for unaffiliated
third parties.
NOARK Pipeline
The Company's share of the NOARK pre-tax loss included in other income was $1.0
million for the first nine months of 2001, compared to $1.5 million for the same
period in 2000.
Interest Expense
Interest expense decreased 17% in the third quarter of 2001 and increased 10%
for the first nine months of 2001, both as compared to the same periods in 2000.
The decrease in third quarter interest expense resulted from lower average
borrowings and a lower average interest rate. The increase in interest expense
for the first nine months of 2001 was due to higher average borrowings caused by
the payment of the Hales judgment in July 2000, 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.
- 20 -
Income Taxes
The changes in the provisions for current and deferred income taxes recorded in
the three and nine month periods ended September 30, 2001, as compared to the
same periods in 2000, resulted primarily from the increase in the level of
taxable income in 2001. Also impacting deferred taxes is 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 September 30, 2001, as compared
to December 31, 2000, primarily reflect the seasonal nature of the Company's gas
distribution segment and the effects of the adoption of SFAS No. 133 (See Note 5
to Consolidated Financial Statements in this Form 10-Q).
Routine capital expenditures and scheduled debt retirements have predominantly
been funded through cash provided by operations. For the first nine months of
2001, cash provided by operating activities was $114.7 million and exceeded the
total of these routine requirements. For the nine months ended September 30,
2000, cash used in operating activities was $53.0 million due to the funding of
the Hales judgment. The Hales judgment, as well as routine capital expenditures,
cash dividends and debt retirements for the first nine months of 2000 were
funded through a combination of cash provided by operating activities and
additional borrowings, as discussed in Financing Requirements.
Financing Requirements
In July 2001, the Company arranged a new unsecured revolving credit facility
with a group of banks to replace the existing short-term credit facility. The
short-term facility was put in place in July 2000 to fund the Hales judgment of
$109.3 million, pay off the existing revolver balance and retire $22.0 million
of private placement debt. The new revolving credit facility has a capacity of
$160 million and a three-year term. The interest rate on the new facility is
137.5 basis points over the current London Interbank Offered Rate (LIBOR), and
was 4.9% at September 30, 2001. The new credit facility contains covenants which
impose certain restrictions on the Company. Under the credit agreement, the
Company may not issue total debt in excess of 75% of its total capital, must
maintain a certain level of shareholders' equity, and the Company must maintain
a ratio of earnings before interest, taxes, depreciation and amortization
(EBITDA) to fixed charges of at least 3.75 or higher through March 30, 2002.
These covenants change over the term of the credit facility and generally become
more restrictive. At September 30, 2001, the Company's revolving credit facility
had a balance of $131.3 million and was classified as long-term debt in the
Company's balance sheet.
- 21 -
During the first nine months of 2001, the Company's total debt decreased by
$39.7 million, as increased cash flow generated from operations exceeded the
Company's capital requirements. Total debt at September 30, 2001, accounted for
67% of the Company's capitalization, down from 74% at December 31, 2000, and the
Company's ratio of EBITDA to fixed charges for the twelve months ended September
30, 2001 was 5.5. Excluding the effects of SFAS No. 133, the percentage of debt
to total capitalization would have been 68% at September 30, 2001.
The Company's capital expenditures for the first nine months of 2001 were $77.1
million, compared to $57.4 million for the same period in 2000. The Company's
reported capital investments include the gross expenditures of the Overton
partnership. The minority interest partner in Overton funded $6.4 million of the
Company's reported expenditures during the period. Additionally, the Company's
capital expenditures during 2001 included $5.8 million to purchase overriding
royalty interests in a group of the Company's Arkoma Basin properties. This
acquisition was made in connection with the settlement of litigation. Planned
capital investments during calendar year 2001 are currently expected to be
approximately $100 million, including approximately $12 million which will be
funded by the minority interest partner in Overton.
At September 30, 2001, NOARK had outstanding debt totaling $74.0 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 have declined since December 31, 2000, due to the seasonal
nature of the Company's gas distribution segment and a decrease in the amounts
owed to the Company's exploration and production segment for oil and gas
production due to lower commodity prices. Under-recovered purchased gas costs
for the Company's gas distribution segment were $2.1 million at September 30,
2001, compared to $12.9 million at December 31, 2000. Purchased gas costs are
recovered from the Company's utility customers in subsequent months through
automatic cost of gas adjustment clauses included in the utility's filed rate
tariffs. Inventories have increased due to the injection of gas into the
Company's gas storage facilities. At September 30, 2001, the Company recorded a
current hedging asset of $8.5 million and a current deferred income tax payable
of $3.3 million under the provisions of SFAS No. 133.
Accounts payable has decreased since December 31, 2000, due primarily to
decreases in gas purchase costs in the gas distribution and marketing segments
and to the timing of expenditures. Other changes in current assets and current
liabilities between periods resulted primarily from the timing of expenditures
and receipts.
- 22 -
FORWARD LOOKING INFORMATION
All statements, other than historical financial information, 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, property acquisition or divestiture activities that may occur, the
effects of weather and regulation on the Company's gas distribution segment,
increased competition, legal and economic factors, governmental regulation, the
financial impact of accounting regulations for derivative instruments, 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. A discussion of these and other factors affecting
the Company's performance is included in the Company's periodic reports filed
with the Securities and Exchange Commission including its Annual Report on Form
10-K for the year ended December 31, 2000.
- 23 -
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 and
interest rate swaps to reduce the volatility of earnings, cash flow and the cost
of purchased gas due to fluctuations in the prices of natural gas and oil and
fluctuations in interest rates. The Board of Directors has approved risk
management policies and procedures to utilize financial products for the
reduction of defined commodity price and interest rate 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
5% of accounts receivable. See the discussion of commodities risk below.
Interest Rate Risk
The Company's revolving 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. The Company has entered into an
interest rate swap for calendar year 2002 that allows the Company to pay a fixed
interest rate of 5.7% on $50 million of its outstanding revolving debt. The
Company's revolving debt was $171.0 million at December 31, 2000, and had an
average interest rate of 7.8%. At September 30, 2001, the Company's revolving
debt was $131.3 million with an average interest rate of 4.9%. Other than the
Company's revolving debt, there have been no material changes in the interest
rate risk information that was presented in the Company's 2000 Form 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, activity in its marketing segment,
and gas purchases in the utility segment 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
and options 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),
(2) transactions in which parties agree to pay a price based on two different
indices (referred to as basis swaps), and (3) the purchase and sale of
index-related puts and calls (collars) that provide a "floor" price below which
the counterparty pays (production hedge) or receives (gas purchase hedge) funds
equal to the
- 24 -
amount by which the price of the commodity is below the contracted floor, and a
"ceiling" price above which the Company pays to (production hedge) or receives
from (gas purchase hedge) the counterparty the amount by which the price of the
commodity is above the contracted ceiling.
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 or purchase 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 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) and MBbls (thousand
barrels), 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,
2001. At September 30, 2001, the "Fair Value" exceeded the "Carrying Amount" of
these financial instruments by $10.6 million.
Expected Maturity Date
----------------------------------------------------------
2001 2002 2003
----------------- ---------------- -----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Production and Marketing
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) .5 13.0 9.2
Weighted average price per Mcf $3.05 $2.88 $3.18
Contract amount (in millions) $1.4 $1.8 $37.4 $37.0 $29.3 $29.2
Swaps with a fixed price payment
Contract volume (Bcf) .2 .2 -
Weighted average price per Mcf $2.97 $2.99 -
Contract amount (in millions) $.6 $.4 $.6 $.6 - -
- 25 -
Expected Maturity Date
----------------------------------------------------------
2001 2002 2003
----------------- ---------------- -----------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Price collar
Contract volume (Bcf) 6.2 6.0 -
Weighted average floor price
per Mcf $4.06 $4.00 -
Contract amount of floor
(in millions) $25.4 $36.8 $24.0 $31.6 - -
Weighted average ceiling price
per Mcf $4.95 $4.72 -
Contract amount of ceiling
(in millions) $31.0 $31.0 $28.3 $27.6 - -
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 24 - -
Weighted average price per Bbl $17.49 - -
Contract amount (in millions) $.4 $.3 - - - -
Price collar
Contract volume (MBbls) 75 - -
Weighted average floor price
Per Bbl $27.40 - -
Contract amount of floor
(in millions) $2.1 $2.4 - - - -
Weighted average ceiling price
Per Bbl $29.95 - -
Contract amount of ceiling
(in millions) $2.2 $2.2 - - - -
Natural Gas Purchases
Swaps with a fixed price payment
Contract volume (Bcf) 1.6 3.3 -
Weighted average price per Mcf $4.11 $4.20 -
Contract amount (in millions) $6.4 $3.7 $13.9 $9.0 - -
- 26 -
PART II
OTHER INFORMATION
Items 1 - 6(a)
No developments required to be reported under Items 1 - 6(a) occurred during the
quarter ended September 30, 2001.
Item 6(b)
On July 30, 2001, the Company filed a current report on Form 8-K containing the
transcript of the Company's conference call on July 26, 2001 discussing the
Company's results for the second quarter of 2001.
All other filings on Form 8-K during the quarter ended September 30, 2001 have
been previously disclosed in the Company's Form 10-Q for the second quarter of
2001.
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: October 12, 2001 /s/ GREG D. KERLEY
----------------------- ---------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
- 27 -
Southwestern Energy Company
P.O. Box 1408
Fayetteville, AR 72702-1408
October 12, 2001
Securities and Exchange Commission
ATTN: Filing Desk, Stop 1-4
450 Fifth Street, N.W.
Washington, DC 20549-1004
Gentlemen:
Pursuant to regulations of the Securities and Exchange Commission,
submitted herewith for filing on behalf of Southwestern Energy Company is
the Quarterly Report on Form 10-Q for the quarter ended September 30, 2001.
This filing is being effected by direct transmission to the Commission's
EDGAR System.
Very truly yours,
Stan Wilson
Controller