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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-Q/A
(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, 2002
--------------
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 April 15, 2002
---------------------------- -------------------------------
Common Stock, Par Value $.10 25,599,140
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- 1 -
Explanatory Note:
-----------------
This form 10-Q/A amends our Quarterly Report on Form 10-Q filed on April
19, 2002. We have included certain changes in this Form 10-Q/A in order to
correct the presentation of comprehensive income for the three month periods
ended March 31, 2002 and 2001, to properly reflect amounts associated with
hedging activities (see Note 1 to the accompanying financial statements). This
correction had no effect on the Company's previously reported net income,
earnings per share or cash flows, nor did it have any impact on the Company's
balance sheet. Except as set forth in the preceding sentences, we have not
materially updated or revised the information in our Quarterly Report.
- 2 -
PART I
FINANCIAL INFORMATION
- 3 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
March 31, December 31,
2002 2001
-------------- ------------
($ in thousands)
Current Assets
Cash $ 1,315 $ 3,641
Accounts receivable 41,771 42,763
Inventories, at average cost 24,547 26,606
Hedging asset - SFAS No.133 4,008 9,381
Regulatory asset - hedges - 5,817
Other 4,318 4,996
--------- ---------
Total current assets 75,959 93,204
--------- ---------
Investments 15,338 15,538
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 990,528 970,680
Gas distribution systems 193,567 192,784
Gas in underground storage 27,999 32,046
Other 30,339 30,110
--------- ---------
1,242,433 1,225,620
Less: Accumulated depreciation,
depletion and amortization 619,581 605,790
--------- ---------
622,852 619,830
--------- ---------
Other Assets 13,533 14,551
--------- ---------
Total Assets $ 727,682 $ 743,123
========= =========
The accompanying notes are an integral part
of the financial statements.
- 4 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
March 31, December 31,
2002 2001
------------- ------------
($ in thousands)
Current Liabilities
Accounts payable 29,403 41,644
Taxes payable 4,494 4,400
Interest payable 6,604 2,653
Customer deposits 4,889 4,845
Hedging liability - SFAS No. 133 12,641 6,990
Over-recovered purchased gas costs 7,953 8,184
Other 3,726 2,752
--------- ---------
Total current liabilities 69,710 71,468
--------- ---------
Long-Term Debt 342,700 350,000
--------- ---------
Other Liabilities
Deferred income taxes 117,815 122,381
Other 6,969 3,187
--------- ---------
124,784 125,568
--------- ---------
Commitments and Contingencies
Minority Interest in Partnership 13,294 13,001
--------- ---------
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 19,358 19,764
Retained earnings 190,392 183,677
Accumulated other comprehensive
income (loss) (7,825) 5,763
--------- ---------
204,699 211,978
Less: Common stock in treasury, at cost,
2,158,379 shares in 2002 and
2,261,766 shares in 2001 24,045 25,196
Unamortized cost of 422,203
restricted shares in 2002
and 416,537 restricted shares
in 2001, issued under stock
incentive plan 3,460 3,696
--------- ---------
177,194 183,086
--------- ---------
Total Liabilities and Shareholders' Equity $ 727,682 $ 743,123
========= =========
The accompanying notes are an integral part
of the financial statements.
- 5 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
Three Months Ended
March 31,
-------------------------
2002 2001
---------- ----------
($ in thousands, except
per share amounts)
Operating Revenues
Gas sales $ 66,986 $ 95,385
Gas marketing 9,702 35,189
Oil sales 3,183 4,162
Gas transportation and other 1,787 2,393
---------- ----------
81,658 137,129
---------- ----------
Operating Costs and Expenses
Gas purchases - utility 24,768 41,128
Gas purchases - marketing 8,673 33,735
Operating expenses 9,558 10,463
General and administrative expenses 5,790 4,827
Depreciation, depletion and amortization 13,870 11,637
Taxes, other than income taxes 2,160 2,740
---------- ----------
64,819 104,530
---------- ----------
Operating Income 16,839 32,599
---------- ----------
Interest Expense
Interest on long-term debt 5,354 6,867
Other interest charges 322 291
Interest capitalized (291) (436)
---------- ----------
5,385 6,722
---------- ----------
Other Income (Expense) (242) 380
---------- ----------
Income Before Income Taxes &
Minority Interest 11,212 26,257
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Minority Interest in Partnership (293) -
---------- ----------
Income Before Income Taxes 10,919 26,257
---------- ----------
Income Tax Provision
Current - -
Deferred 4,204 10,244
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4,204 10,244
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Net Income $ 6,715 $ 16,013
========== ==========
Basic Earnings Per Share $0.26 $0.64
========== ==========
Basic Average Common Shares Outstanding 25,499,294 25,187,103
========== ==========
Diluted Earnings Per Share $0.26 $0.63
========== ==========
Diluted Average Common Shares Outstanding 25,859,247 25,495,585
========== ==========
The accompanying notes are an integral part
of the financial statements.
- 6 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Three Months Ended
March 31,
--------------------
2002 2001
-------- --------
($ in thousands)
Cash Flows From Operating Activities
Net income $ 6,715 $ 16,013
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 14,472 12,012
Deferred income taxes 4,204 10,244
Equity in loss of NOARK partnership 200 305
Minority interest in partnership 293 -
Change in assets and liabilities:
Accounts receivable 803 8,248
Inventories 2,059 (789)
Accounts payable (12,241) (12,916)
Taxes payable 94 2,117
Interest payable 3,951 3,258
Other current assets and liabilities 802 1,915
-------- --------
Net cash provided by operating activities 21,352 40,407
-------- --------
Cash Flows From Investing Activities
Capital expenditures (21,369) (15,314)
Change in gas stored underground 4,047 2,534
Other items 944 1,806
-------- --------
Net cash used in investing activities (16,378) (10,974)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt (7,300) (29,200)
-------- --------
Net cash used in financing activities (7,300) (29,200)
-------- --------
Increase (decrease) in cash (2,326) 233
Cash at beginning of year 3,641 2,386
-------- --------
Cash at end of period $ 1,315 $ 2,619
======== ========
The accompanying notes are an integral part
of the financial statements.
- 7 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
Three Months Ended
March 31,
--------------------
2002* 2001*
-------- --------
($ in thousands)
Net income $ 6,715 $ 16,013
Other comprehensive income (loss):
Transition adjustment from adoption of
SFAS No. 133 - (36,963)
Change in value of derivative instruments (13,588) 24,790
-------- --------
Comprehensive Income (Loss) $ (6,873) $ 3,840
======== ========
Reconciliation of Accumulated Other Comprehensive
Income (Loss):
Balance, Beginning of Period $ 5,763 $ -
Cumulative effect of adoption of SFAS No. 133 - (36,963)
Current period reclassification to earnings (1,776) 20,546
Current period change in derivative instruments (11,812) 4,244
-------- --------
Balance, End of Period $ (7,825) $(12,173)
======== ========
* The 2002 and 2001 Consolidated Statements of Comprehensive Income (Loss) were
restated to correct the presentation of comprehensive income, as discussed in
Footnote 1 to Consolidated Financial Statements.
The accompanying notes are an integral part
of the financial statements.
- 8 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2002
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 2001
Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial
Statements.
Southwestern, in the accompanying financial statements, has corrected
its presentation of comprehensive income for the quarters ended March
31, 2002 and March 31, 2001, to properly reflect amounts associated
with hedging activities. This change resulted in a decrease of $1.8
million to previously reported comprehensive income for the three
months ended March 31, 2002 and an increase of $20.5 million to
previously reported comprehensive income for the three months ended
March 31, 2001. This correction had no effect on the Company's
previously reported net income, earnings per share or cash flows, nor
did it have any impact on the Company's balance sheet.
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. Any costs in excess of
this ceiling are written off as a non-cash expense. The expense may not
be reversed in future periods, even though higher oil and gas prices
may subsequently increase the ceiling. At March 31, 2002, 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.
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 1,033,634 shares of common stock
with a weighted average exercise price of $13.68 per share at March 31,
2002, and options for 1,109,882
- 9 -
shares with an average exercise price of $13.55 per share at March 31,
2001, that were not included in the calculation of diluted shares
because they would have had an antidilutive effect.
4. 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 $155 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 4.59%, including
the effects of interest rate swaps, at March 31, 2002. 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 70% 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 interest expense of at least 3.75 or higher through December 31,
2002. These covenants change over the term of the credit facility and
generally become more restrictive. At March 31, 2002, the Company's
revolving credit facility had a balance of $117.7 million and was
classified as long-term debt in the Company's balance sheet. The
Company has also entered into interest rate swaps for calendar year
2002 that allow the Company to pay a fixed interest rate of 4.8% (based
upon current rates under the revolving credit facility) on $100.0
million of its outstanding revolving debt.
5. 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 all derivatives 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 to offset related results on the hedged item in the income
statement.
At March 31, 2002, the Company's net liability related to its cash flow
hedges was $12.4 million. Additionally, at March 31, 2002, the Company
had recorded a net of tax cumulative loss to other comprehensive income
(equity section of the balance sheet) of $7.8 million. The amount
recorded in other comprehensive income will be relieved over time and
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.
6. 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 retail
transportation and sale of
- 10 -
natural gas. 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 March 31, 2002:
----------------------------------
Revenues from external customers $ 23,564 $ 48,392 $ 9,702 $ -- $ 81,658
Intersegment revenues 4,856 65 16,921 112 21,954
Operating income 7,330 8,663 781 65 16,839
Depreciation, depletion and
amortization expense 12,280 1,565 2 23 13,870
Interest expense (1) 4,253 904 -- 228 5,385
Provision (benefit) for income taxes (1) 1,074 2,967 307 (144) 4,204
Assets 534,314 156,952 9,380 27,036(2) 727,682
Capital expenditures 19,881(3) 1,348 -- 140 21,369(3)
Three months ended March 31, 2001:
----------------------------------
Revenues from external customers $ 20,577 $ 81,363 $ 35,189 $ -- $ 137,129
Intersegment revenues 20,163 129 35,843 112 56,247
Operating income 21,988 9,398 1,143 70 32,599
Depreciation, depletion and
amortization expense 10,046 1,551 17 23 11,637
Interest expense (1) 5,322 1,092 33 275 6,722
Provision (benefit) for income taxes (1) 6,501 3,403 433 (93) 10,244
Assets 464,260 184,697 18,523 36,043(2) 703,523
Capital expenditures 14,299 909 -- 106 15,314
(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.
(3) Capital expenditures for the Exploration and Production segment
includes $2.7 million for the three months ended March 31, 2002,
related to the consolidated results of a limited partnership.
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.
7. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented. Interest payments include amounts paid or received
for the settlement of interest rate hedges.
- 11 -
Quarters Ended March 31 2002 2001
-----------------------------------------------------------------------
(in thousands)
Interest payments $1,405 $3,615
Income tax payments $ -- $ --
8. MINORITY INTEREST IN PARTNERSHIP
In the second quarter of 2001, the Company's subsidiary, Southwestern
Energy Production Company (SEPCO) formed a limited partnership, Overton
Partners, L.P., with an investor to drill and complete the first 14
development wells in SEPCO's Overton Field located in Smith County,
Texas. Because SEPCO is the sole general partner and owns a majority
interest in 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. SEPCO contributed
50% of the capital required to drill the first 14 wells. Revenues and
expenses are allocated 65% to SEPCO prior to payout of the investor's
initial investment and 85% thereafter.
9. 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 March 31, 2002 and December 31, 2001, the principal
outstanding for these Notes was $73.0 million. 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 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 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 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.
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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, 2001,
and analyzes the changes in the results of operations between the three
month period ended March 31, 2002, and the comparable period of 2001.
RESULTS OF OPERATIONS
Southwestern reported net income of $6.7 million, or $.26 per share on a
fully diluted basis, for the three months ended March 31, 2002, compared to
$16.0 million, or $.63 per share, for the same period in 2001. The decrease
in earnings primarily resulted from lower natural gas prices experienced by
the Company's exploration and production segment, partially offset by an
increase in production volumes.
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
Ended March 31,
-------------------------
2002 2001
-------------------------
Revenues (in thousands) $28,420 $40,740
Operating income (in thousands) $7,330 $21,988
Gas production (MMcf) 9,231 8,026
Oil production (MBbls) 182.8 161.0
Total production (MMcfe) 10,329 8,992
Average gas price per Mcf $2.76 $4.48
Average oil price per Bbl $17.41 $25.82
Operating expenses per Mcfe
Production expenses $0.43 $0.51
Production taxes $0.15 $0.23
General & administrative expenses $0.27 $0.22
Full cost pool amortization $1.16 $1.08
- 13 -
Revenues and Operating Income
Revenues for the exploration and production segment were down 30% for the
three-month period ended March 31, 2002 compared to the same period in
2001. The decrease was due to lower gas and oil prices received for the
Company's production, partially offset by increased production volumes.
Operating income for the exploration and production segment was down $14.7
million for the three months ended March 31, 2002, compared to the same
period in 2001. The decrease in operating income resulted from the decline
in revenues and an increase in depreciation, depletion and amortization
expense.
Production
Gas and oil production during the first quarter of 2002 was 10.3 billion
cubic feet (Bcf) equivalent, up from 9.0 Bcf equivalent for the same period
in 2001. The increase in production resulted from the Company's continued
development of its South Louisiana properties and its Overton Field in East
Texas. Gas production was 9.2 Bcf for the first three months of 2002,
compared to 8.0 Bcf for the same period in 2001. The Company's sales to its
gas distribution systems were 1.9 Bcf during the three months ended March
31, 2002, compared to 2.3 Bcf for the same period in 2001. The Company's
oil production was 182.8 thousand barrels (MBbls) during the first quarter
of 2002, up from 161.0 MBbls for the same period of 2001.
Commodity Prices
The Company received an average price of $2.76 per thousand cubic feet
(Mcf) for its gas production for the three months ended March 31, 2002,
down from $4.48 per Mcf for the same period of 2001. The Company hedged 4.7
Bcf of gas production in the first three months of 2002 through fixed-price
swaps and zero-cost collars which had the effect of increasing the average
gas price realized during the period by $.44 per Mcf. On a comparative
basis, the average price during the first three months of 2001 included the
negative effect of hedges that decreased the average price by $2.73 per
Mcf.
For the remainder of the year 2002, the Company has 9.4 Bcf of gas
production hedged with collars having an average NYMEX floor price of $3.24
per Mcf and an average NYMEX ceiling price of $4.07 per Mcf. The Company
also has 12.2 Bcf of gas production for the remainder of 2002 hedged with
fixed price swaps at an average NYMEX price of $2.82 per Mcf. For 2003 and
2004, the Company has 23.1 Bcf hedged under zero-cost collars and
fixed-price swaps. 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 $17.41 per barrel for its oil
production during the three months ended March 31, 2002, down from $25.82
per barrel for the same period of 2001. For the remainder of 2002, the
Company has a hedge on 249,750 barrels at an average NYMEX price of $20.07
per barrel.
Operating Costs and Expenses
Operating costs and expenses for the exploration and production segment
increased in the first three months of 2002 due to increased depreciation,
depletion and amortization expense and higher general and administrative
expenses, partially offset by a decrease in production costs and severance
taxes. The increase in depreciation, depletion and amortization expense was
due to the increase in production and an increase in the amortization rate
per unit of production. The full cost pool amortization rate
- 14 -
averaged $1.16 per Mcf equivalent for the first three months of 2002,
compared to $1.08 per Mcf equivalent in the first three months of 2001. The
increase in general and administrative expenses in 2002 resulted from
increases in compensation expense and corporate overhead costs. The
decrease in production costs was primarily due to a decrease in workover
expenses as compared to 2001. Severance taxes decreased during the quarter
due to lower average prices received for the Company's production.
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. Any costs in excess of this ceiling are written off as
a non-cash expense. The expense may not be reversed in future periods, even
though higher oil and gas prices may subsequently increase the ceiling. At
March 31, 2002, 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.
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 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
Ended March 31,
-------------------------
2002 2001
-------------------------
($ in thousands, except for Mcf amounts)
Revenues $48,457 $81,492
Gas purchases $29,618 $61,289
Operating costs and expenses $10,176 $10,805
Operating income $8,663 $9,398
Deliveries (Bcf)
Sales and end-use transportation 10.1 10.5
Off-system transportation -- --
- 15 -
Average number of customers 138,071 136,621
Average sales rate per Mcf $5.98 $9.32
Heating weather - degree days 2,049 2,161
- percent of normal 95% 100%
Revenues and Operating Income
Gas distribution revenues fluctuate due to the pass-through of gas supply
cost changes and the effects of weather. Because of the corresponding
changes in purchased gas costs, the revenue effect of the pass-through of
gas cost changes has not materially affected net income.
Revenues for the three months ended March 31, 2002 are down from the
comparable period of 2001 primarily due to the significant drop in the cost
of the utility's gas supply from the record high levels experienced during
the first quarter of 2001. The decrease in gas cost was reflected in the
Company's average rate for its utility sales which decreased during the
first three months of 2002 to $5.98 per Mcf, down from $9.32 per Mcf for
the same period in 2001. Costs paid for purchases of natural gas are passed
through to customers under automatic adjustment clauses.
Operating income of the gas distribution segment decreased 8% in the first
quarter of 2002, as compared to the same period of 2001. The decrease was
primarily due to warmer weather. Weather during the first quarter of 2002
was 5% warmer than both normal and the same period of 2001. The weather
normalization clause in the Company's rates lessens the impacts of revenue
increases and decreases that might result from weather variations during
the winter heating season.
Deliveries
The utility systems delivered 10.1 Bcf to sales and end-use transportation
customers during the three months ended March 31, 2002, down from 10.5 Bcf
for the same period in 2001. The decrease in deliveries was primarily due
to the effects of warmer weather.
Operating Costs and Expenses
The changes in purchased gas costs for the gas distribution segment reflect
volumes purchased, prices paid for supplies and the mix of purchases from
intercompany versus third-party sources. Other operating costs and expenses
of the gas distribution segment for the quarter ended March 31, 2002 were
lower than the comparable period of the prior year due primarily to a
decrease in the average cost of fuel purchased for compression operations.
Marketing and Other
-------------------
Three Months
Ended March 31,
-------------------------
2002 2001
-------------------------
Marketing revenues (in thousands) $26,623 $71,032
Marketing operating income (in thousands) $781 $1,143
Gas volumes marketed (Bcf) 12.3 11.0
- 16 -
Marketing
The decrease in gas marketing revenues for the quarter ended March 31,
2002, relates to a substantial decrease in natural gas commodity prices
from the prior year, and was largely offset by a comparable decrease in
purchased gas costs. Operating income for the marketing segment was $.8
million for the first three months of 2002, compared to $1.1 million for
the same period in 2001. The Company marketed 12.3 Bcf of gas in the first
three months of 2002, compared to 11.0 Bcf for the same period in 2001. The
increase in volumes marketed resulted from an increase in volumes marketed
for Southwestern's exploration and production subsidiaries.
NOARK Pipeline
The Company's share of the NOARK Pipeline System Limited Partnership
(NOARK) pretax loss included in other income was $.2 million for the first
quarter of 2002, compared to $.3 million for the same period in 2001.
Interest Expense
Interest expense decreased 20% for the first quarter of 2002, compared to
the same period in 2001, due to lower average borrowings and a lower
average interest rate, partially offset by a lower level of capitalized
interest. Interest is capitalized in the exploration and production segment
on costs that are unevaluated and excluded from amortization.
Income Taxes
The changes in the provision for deferred income taxes recorded in the
three months ended March 31, 2002, as compared to the same period in 2001,
resulted primarily from the decrease in the level of taxable income in
2002. 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 March 31, 2002, as compared
to December 31, 2001, primarily reflect changes in the Company's cash flow
from operating activities, the seasonal nature of the Company's gas
distribution segment, the timing of cash payments and receipts and the
effects of accounting for the Company's hedging activities as required by
SFAS No. 133.
The Company's cash flow from operating activities is highly dependent upon
market prices that the Company receives for its gas and oil production. The
price that the Company receives for its production is also influenced by
the Company's commodity hedging activities. Natural gas and oil prices are
subject to wide fluctuations and have declined significantly in the first
quarter of 2002 as compared to prices received during 2001.
Routine capital expenditures have predominantly been funded through cash
provided by operations. For the first three months of 2002 and 2001, cash
provided by operating activities was $21.4 million and $40.4 million,
respectively, and met or exceeded the total of these routine requirements.
Financing Requirements
In July 2001, the Company arranged a new unsecured revolving credit
facility with a group of banks
- 17 -
to replace a short-term credit facility that was put in place in July 2000.
The new revolving credit facility has a current capacity of $155 million
and expires in July 2004. The interest rate on the current facility is
137.5 basis points over the current London Interbank Offered Rate (LIBOR),
and was 4.59%, including the effects of interest rate swaps, at March 31,
2002. The 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 70% 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 interest expense of at least 3.75 or higher through December
31, 2002. These covenants change over the term of the credit facility and
generally become more restrictive. At March 31, 2002, the Company's
revolving credit facility had a balance of $117.7 million and was
classified as long-term debt in the Company's balance sheet. The Company
has also entered into interest rate swaps for calendar year 2002 that allow
the Company to pay an average fixed interest rate of 4.8% (based upon
current rates under the revolving credit facility) on $100.0 million of its
outstanding revolving debt.
During the first three months of 2002, the Company's total debt decreased
by $7.3 million. Total debt at March 31, 2002, accounted for 66% of the
Company's capitalization. The percentage of debt to capitalization at March
31, 2002, would be 65% without consideration of the $7.8 million of
accumulated other comprehensive loss recorded in the equity section of the
Company's balance sheet. The other comprehensive loss in the March 31, 2002
balance sheet resulted from the Company's hedging activities and was
recorded in accordance with the requirements of SFAS No. 133.
The Company's capital expenditures for the first three months of 2002 were
$21.4 million, compared to $15.3 million for the same period in 2001.
Capital investments during calendar year 2002 are currently expected to be
approximately $68.0 million. The Company may adjust its level of future
capital investments dependent upon the level of cash flow generated from
operations.
At March 31, 2002, the NOARK partnership had outstanding debt totaling
$73.0 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 slightly since December 31, 2001,
primarily due to the seasonality of the gas distribution segment's
operations. Changes in accounts payable, interest payable and other current
assets and liabilities since December 31, 2001 are due primarily to the
timing of expenditures and receipts. Over-recovered purchased gas costs for
the Company's gas distribution segment were $8.0 million at March 31, 2002,
compared to $8.2 million at December 31, 2001. 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. At March 31, 2002, the Company had a current hedging asset of
$4.0 million, a current hedging liability of $12.6 million, and a
regulatory liability of $.9 million recorded as a result of the provisions
of SFAS No. 133.
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
- 18 -
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.
- 19 -
PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risks relating to the Company's operations result primarily from the
volatility in commodity prices, basis differentials 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 and cash flow due to fluctuations in the prices of
natural gas and oil and 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 appropriate 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 3% of accounts receivable. See the discussion of credit risk
associated with commodities trading 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 interest rate swaps for calendar year 2002 that allow the
Company to pay an average fixed interest rate of 4.8% (based upon current
rates under the revolving credit facility) on $100.0 million of its
outstanding revolving debt. The Company's revolving debt was $125.0 million
at December 31, 2001, and had an average interest rate of 3.44%. At March
31, 2002, the Company's revolving debt was $117.7 million with an average
interest rate of 4.59%, including the effect of the interest rate swaps.
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 2001 Form 10-K.
The Company's interest rate swaps have a carrying amount of $2.7 million,
calculated as the contractual payments for interest on the notional amount
to be exchanged under futures contracts and does not represent amounts
recorded in the Company's financial statements. The fair value of $2.0
million represents the value for the same contracts using comparable market
prices at March 31, 2002. At March 31, 2002, the "Carrying Amount" exceeded
the "Fair Value" of interest rate swaps by $.7 million.
Commodities Risk
The Company uses over-the-counter natural gas and crude oil swap agreements
and options to hedge sales of Company production, to hedge activity in its
marketing segment, and to hedge the purchase of gas in its 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
- 20 -
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 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 risks related to the Company's derivative contracts are
the volatility in market prices and basis differentials for natural gas and
crude oil. However, the market price risk is offset by the gain or loss
recognized upon the related sale or purchase of the natural gas or sale of
the 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 is calculated as the contractual payments for the
quantity of gas or oil to be exchanged under futures contracts and does 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, 2002. At March 31, 2002, the "Carrying Amount" exceeded
the "Fair Value" of these financial instruments by $11.7 million.
Expected Maturity Date
--------------------------------------------------------
2002 2003 2004
----------- ----------- ------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
-------- ----- -------- ----- -------- -----
Natural Gas:
------------
Swaps with a fixed price receipt
Contract volume (Bcf) 12.2 9.2 -
Weighted average price per Mcf $2.82 $3.18 -
Contract amount (in millions) $34.5 $27.2 $29.3 $24.8 - -
Swaps with a fixed price payment
Contract volume (Bcf) .1 - -
Weighted average price per Mcf $2.19 - -
Contract amount (in millions) $.2 $.3 - - - -
Price collar
Contract volume (Bcf) 9.4 9.9 4.0
Weighted average floor price
per Mcf $3.24 $3.11 $3.25
Contract amount of floor
(in millions) $30.6 $34.3 $30.6 $34.2 $13.0 $14.8
Weighted average ceiling price
per Mcf $4.07 $4.71 $4.75
Contract amount of ceiling
- 21 -
(in millions) $38.4 $35.9 $46.4 $42.2 $19.0 $17.3
Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 250 - -
Weighted average price per Bbl $20.07 - -
Contract amount (in millions) $5.6 $4.0 - - - -
Natural Gas Purchases:
Swaps with a fixed price payment
Contract volume (Bcf) .3 .7 -
Weighted average price per Mcf $2.91 $2.91 -
Contract amount (in millions) $1.0 $1.3 $1.9 $2.5 - -
- 22 -
PART II
OTHER INFORMATION
Items 1 - 6(a)
No developments required to be reported under Items 1 - 6(a) occurred
during the quarter ended March 31, 2002.
Item 6(b)
On February 19, 2002, the Company filed a current report on Form 8-K
containing the transcript of the Company's conference call on February 15,
2002 discussing the Company's results for the fourth quarter and year-ended
December 31, 2001.
On March 21, 2002, the Company filed a current report on Form 8-K
containing the Company's slide presentation made to investors on March 20,
2002 at the CIBC World Markets Annual Energy Conference in New York, New
York, and discussing the Company's 2001 results and outlook and business
strategy for 2002.
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: September 24, 2002 /s/ GREG D. KERLEY
--------------------- -----------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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CERTIFICATION
-------------
I, Harold M. Korell, Chief Executive Officer of Southwestern Energy
Company, certify that:
1. I have reviewed this amended quarterly report on Form 10-Q/A of
Southwestern Energy Company;
2. Based on my knowledge, this amended quarterly report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amended quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this amended quarterly report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amended quarterly report.
Date: September 24, 2002
/s/ HAROLD M. KORELL
----------------------------
Harold M. Korell
Chief Executive Officer
- 24 -
CERTIFICATION
-------------
I, Greg D. Kerley, Chief Financial Officer of Southwestern Energy Company,
certify that:
1. I have reviewed this amended quarterly report on Form 10-Q/A of
Southwestern Energy Company;
2. Based on my knowledge, this amended quarterly report does not
contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made, in light of the
circumstances under which such statements were made, not misleading with
respect to the period covered by this amended quarterly report; and
3. Based on my knowledge, the financial statements, and other
financial information included in this amended quarterly report, fairly
present in all material respects the financial condition, results of
operations and cash flows of the registrant as of, and for, the periods
presented in this amended quarterly report.
Date: September 24, 2002
/s/ GREG D. KERLEY
----------------------------
Greg D. Kerley
Chief Financial Officer
- 25 -