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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------------
FORM 10-Q
(Mark one)
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the quarterly period ended March 31, 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 May 2, 2001
---------------------------- --------------------------
Common Stock, Par Value $.10 25,189,211
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- 1 -
PART I
FINANCIAL INFORMATION
- 2 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
ASSETS
March 31, December 31,
2001 2000
------------- ------------
($ in thousands)
Current Assets
Cash $ 2,619 $ 2,386
Accounts receivable 68,793 77,041
Inventories, at average cost 17,790 17,000
Under-recovered purchased gas costs 12,225 12,942
Deferred income tax benefit 6,645 -
Other 4,025 3,486
--------- ---------
Total current assets 112,097 112,855
--------- ---------
Investments 15,269 15,574
--------- ---------
Property, Plant and Equipment, at cost
Gas and oil properties, using the
full cost method 884,804 872,023
Gas distribution systems 191,412 190,893
Gas in underground storage 25,333 27,867
Other 28,112 27,940
--------- ---------
1,129,661 1,118,723
Less: Accumulated depreciation,
depletion and amortization 566,093 554,616
--------- ---------
563,568 564,107
--------- ---------
Other Assets 12,589 12,842
--------- ---------
Total Assets $ 703,523 $ 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
March 31, December 31,
2001 2000
------------- ------------
($ in thousands)
Current Liabilities
Short-term debt $ 141,800 $ 171,000
Accounts payable 41,389 54,304
Hedging liability-SFAS No. 133 16,962 -
Taxes payable 6,463 4,346
Interest payable 6,064 2,806
Customer deposits 4,761 4,799
Other 4,403 2,629
--------- ---------
Total current liabilities 221,842 239,884
--------- ---------
Long-Term Debt, less current portion above 225,000 225,000
--------- ---------
Other Liabilities
Deferred income taxes 106,532 97,431
Long-term hedging liability-SFAS No. 133 2,994 -
Other 1,793 1,772
--------- ---------
111,319 99,203
--------- ---------
Commitments and Contingencies
Shareholders' Equity
Common stock, $.10 par value; authorized
75,000,000 shares, issued 27,738,084
shares 2,774 2,774
Additional paid-in capital 20,208 20,220
Retained earnings 164,365 148,353
Accumulated other comprehensive loss (12,173) -
--------- ---------
175,174 171,347
Less: Common stock in treasury, at cost,
2,550,373 shares in 2001 and
2,556,908 shares in 2000 28,451 28,485
Unamortized cost of 228,686
restricted shares in 2001
and 241,452 restricted shares
in 2000, issued under stock
incentive plan 1,361 1,571
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145,362 141,291
--------- ---------
Total Liabilities and Shareholders' Equity $ 703,523 $ 705,378
========= =========
The accompanying notes are an integral part
of the financial statements.
- 4 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
Quarter Ended
March 31,
-------------------------
2001 2000
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($ in thousands, except
per share amounts)
Operating Revenues
Gas sales $ 95,385 $ 60,292
Gas marketing 35,189 30,004
Oil sales 4,162 3,579
Gas transportation and other 2,393 3,038
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137,129 96,913
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Operating Costs and Expenses
Gas purchases - utility 41,128 19,263
Gas purchases - marketing 33,735 28,663
Operating expenses 10,463 8,866
General and administrative expenses 4,827 5,920
Depreciation, depletion and amortization 11,637 11,091
Taxes, other than income taxes 2,740 2,054
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104,530 75,857
---------- ----------
Operating Income 32,599 21,056
---------- ----------
Interest Expense
Interest on long-term debt 6,867 5,201
Other interest charges 291 192
Interest capitalized (436) (637)
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6,722 4,756
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Other Income (Expense) 380 (1,241)
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Income Before Income Taxes 26,257 15,059
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Income Tax Provision
Current - 872
Deferred 10,244 5,001
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10,244 5,873
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Net Income $ 16,013 $ 9,186
========== ==========
Basic Earnings Per Share $0.64 $0.37
========== ==========
Basic Average Common Shares Outstanding 25,187,103 25,037,508
========== ==========
Diluted Earnings Per Share $0.63 $0.37
========== ==========
Diluted Average Common Shares Outstanding 25,495,585 25,037,508
========== ==========
Dividends Declared Per Share Payable 5/5/00 - $ .06
========== ==========
The accompanying notes are an integral part
of the financial statements.
- 5 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Quarter Ended
March 31,
--------------------
2001 2000
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($ in thousands)
Cash Flows From Operating Activities
Net income $ 16,013 $ 9,186
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization 12,012 11,394
Deferred income taxes 10,244 5,001
Equity in loss of partnership 305 634
Change in assets and liabilities:
Accounts receivable 8,248 1,150
Inventories (789) 8,034
Accounts payable (12,916) (6,020)
Taxes payable 2,117 1,222
Interest payable 3,258 4,634
Other current assets and liabilities 1,915 340
-------- --------
Net cash provided by operating activities 40,407 35,575
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Cash Flows From Investing Activities
Capital expenditures (15,314) (14,557)
Decrease in gas stored underground 2,534 2,878
Other items 1,806 1,420
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Net cash used in investing activities (10,974) (10,259)
-------- --------
Cash Flows From Financing Activities
Net change in revolving long-term debt (29,200) (16,300)
Payment on revolving short-term note - (7,500)
Cash dividends - (1,502)
-------- --------
Net cash used in financing activities (29,200) (25,302)
-------- --------
Increase in cash 233 14
Cash at beginning of year 2,386 1,240
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Cash at end of period $ 2,619 $ 1,254
======== ========
The accompanying notes are an integral part
of the financial statements.
- 6 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
Quarter Ended
March 31,
--------------------
2001 2000
-------- --------
($ in thousands)
Net income $ 16,013 $ 9,186
Other comprehensive income:
Unrealized gain on derivative instruments 4,244 -
-------- --------
Comprehensive Income $ 20,257 $ 9,186
======== ========
Reconciliation of Accumulated Other Comprehensive
Income (Loss):
Balance, Beginning of Period $ - $ -
Cumulative effect of adoption of SFAS No. 133 (36,963) -
Current period reclassification to earnings 20,546 -
Current period change in derivative instruments 4,244 -
-------- --------
Balance, End of Period $(12,173) $ -
======== ========
The accompanying notes are an integral part
of the financial statements.
- 7 -
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2001
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 2000
Annual Report on Form 10-K, Item 8, Notes to Consolidated Financial
Statements.
2. EARNINGS PER SHARE
Basic earnings per common share is computed by dividing net income by
the weighted average number of common shares outstanding during each
year. The diluted earnings per share calculation adds to the weighted
average number of common shares outstanding the incremental shares that
would have been outstanding assuming the exercise of dilutive stock
options. The Company had options for 1,109,882 shares of common stock
with a weighted average exercise price of $13.55 per share at March 31,
2001, and options for 1,582,916 shares with an average exercise price
of $11.85 per share at March 31, 2000, that were not included in the
calculation of diluted shares because they would have had an
antidilutive effect.
3. 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.
4. 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.
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 in
place that are used to reduce the volatility in commodity prices for
the Company's forecasted oil and gas production. At March 31, 2001, the
Company's liability related to its commodity cash flow hedges was $20.0
million. Additionally, at March 31, 2001, the Company had recorded a
net of tax
- 8 -
cumulative loss to other comprehensive income (equity section of the
balance sheet) of $12.2 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.
5. 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
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
Depreciation, depletion
and amortization expense 10,046 1,551 17 23 11,637
Operating income 21,988 9,398 1,143 70 32,599
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
Three months ended
March 31, 2000:
Revenues from external
customers $ 13,715 $ 53,194 $ 30,004 $ -- $ 96,913
Intersegment revenues 11,046 54 13,241 112 24,453
Depreciation, depletion
and amortization expense 9,240 1,810 18 23 11,091
Operating income 8,688 11,370 965 33 21,056
Interest expense (1) 3,238 1,253 -- 265 4,756
Provision (benefit) for
income taxes (1) 1,902 3,930 379 (338) 5,873
Assets 431,829 179,854 14,598 33,344(2) 659,625
Capital expenditures 13,111 1,280 -- 166 14,557
(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.
Intersegment sales by the exploration and production segment and
marketing segment to
-9-
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.
6. INTEREST AND INCOME TAXES PAID
The following table provides interest and income taxes paid during each
period presented.
Quarters Ended March 31 2001 2000
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(in thousands)
Interest payments $3,615 $ 606
Income tax payments $ -- $ --
7. Contingencies and Commitments
In the Company's Form 8-K filed July 2, 1996, it previously disclosed
that a lawsuit relating to overriding royalty interests in certain
Arkansas oil and gas properties had been filed. The Company also
reported in its second quarter 2000 Form 10-Q that this matter had gone
to a non-jury trial as to liability in January 2000 and that the
Company was awaiting the court's findings. The court in this matter has
issued Findings of Fact and Conclusions of Law that find no fraud was
committed. The court also found that any override royalty interests
that may ultimately be found to be subject to the plaintiff's claim for
additional override royalties accrued after March 1, 1990. All claims
prior to March 1, 1990 have been barred by the statute of limitations.
The ultimate measure of damages will be determined during the damages
phase of the non-jury proceedings that is scheduled to occur June 11,
2001. While the Company anticipates that it will owe some additional
override royalties to plaintiffs, it does not believe that its
liability will be material to its financial condition, but in any one
period it could be significant to its results of operations.
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, 2001 and December 31, 2000, the principal
outstanding for these Notes was $75.0 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. The proceeds
from the issuance of the Notes were used to repay temporary financing
provided by the other general partner and outstanding amounts under an
unsecured revolving credit agreement. The temporary financing provided
by the other general partner was incurred in connection with the
prepayment in early 1998 of NOARK's 9.74% Senior Secured notes. Under
the several guarantee, the Company is required to fund its share of
NOARK's debt service which is not funded by operations of the pipeline.
As a result of the integration of NOARK Pipeline with the Ozark Gas
Transmission System, management of the Company believes that it will
realize its investment in NOARK over the life of the system. Therefore,
no provision for any loss has been made in the accompanying financial
statements. Additionally, the Company's gas distribution subsidiary has
transportation contracts for firm capacity of 66.9 MMcfd on NOARK's
integrated pipeline system. These contracts expire in 2002 and
-10-
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 other litigation and claims that have arisen
in the ordinary course of business. The Company accrues for such items
when a liability is both probable and the amount can be reasonably
estimated. In the opinion of management, the results of such litigation
and claims will not have a material effect on the results of operations
or the financial position of the Company.
-11-
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following updates information as to the Company's financial condition
provided in the Company's Form 10-K for the year ended December 31, 2000, and
analyzes the changes in the results of operations between the three month period
ended March 31, 2001, and the comparable period of 2000.
RESULTS OF OPERATIONS
Net income for the three months ended March 31, 2001 was $16.0 million, or $.64
of basic earnings per share, compared to net income of $9.2 million, or $.37 per
share, in 2000. Earnings per share for 2001 on a diluted basis were $.63 per
share. 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.
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
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2001 2000
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Revenues (in thousands) $40,740 $24,761
Operating income (in thousands) $21,988 $8,688
Gas production (Bcf) 8.0 7.8
Oil production (MBbls) 161.0 155.0
Total production (Bcfe) 9.0 8.7
Average gas price per Mcf $4.48 $2.62
Average oil price per Bbl $25.82 $23.03
Operating expenses per Mcfe
Production expenses $0.51 $0.38
Production taxes $0.23 $0.13
General & administrative expenses $0.22 $0.27
Full cost pool amortization $1.08 $1.03
-12-
Revenues and Operating Income
Revenues for the exploration and production segment were up 65% for the three
month period ended March 31, 2001 compared to the same period in 2000. The
increases were due to both higher gas and oil prices and increased gas and oil
production.
Operating income for the exploration and production segment was up $13.3 million
for the three months ended March 31, 2001, compared to the same period in 2000.
The improvements in operating income were also due to higher prices received and
increased production.
Production
Gas and oil production during the first quarter of 2001 was 9.0 billion cubic
feet (Bcf) equivalent, up 3% from 8.7 Bcf equivalent for the same period in
2000. The increase in production resulted from new wells added in 2000 and 2001
in the Company's Arkoma Basin and Gulf Coast operating areas. Gas production was
8.0 Bcf for the first three months of 2001, compared to 7.8 Bcf for the same
period in 2000. The Company's sales to its gas distribution systems were 2.3 Bcf
during the three months ended March 31, 2001, compared to 3.5 Bcf for the same
period in 2000. The Company's oil production was 161 thousand barrels (MBbls)
during the first quarter of 2001, up from 155 MBbls for the same period of 2000.
Commodity Prices
The Company received an average price of $4.48 per thousand cubic feet (Mcf) for
its gas production for the three months ended March 31, 2001, up from $2.62 per
Mcf for the same period of 2000. The Company hedged 6.5 Bcf of gas production in
the first three months of 2001 primarily through zero-cost collars which had the
effect of reducing the average gas price realized during the period by $2.73 per
Mcf. On a comparative basis, the average price during the first three months of
2000 included the negative effect of hedges that decreased the average price by
$.06 per Mcf. Additionally, the Company receives monthly demand charges related
to the no-notice service it makes available to the utility segment which
increases the Company's average gas price received.
For the remainder of the year 2001, the Company has 19.2 Bcf of gas production
hedged with collars having an average NYMEX floor price of $3.78 per Mcf and an
average NYMEX ceiling price of $4.66 per Mcf. The Company also has 1.6 Bcf of
gas production for the remainder of 2001 hedged with fixed price swaps at an
average NYMEX price of $3.55 per Mcf. For the years 2002 and 2003 combined, the
Company has 7.2 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 $25.82 per barrel for its oil
production during the three months ended March 31, 2001, up from $23.03 per
barrel for the same period of 2000. For the remainder of 2001, the Company has a
collar on 225,000 barrels with an average floor of $27.40 per barrel, and an
average ceiling of $29.95 per barrel, and a hedge on 54,000 barrels at an
average NYMEX price of $17.49 per barrel.
-13-
Operating Costs and Expenses
Operating costs and expenses for the exploration and production segment
increased in the first three 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 increase in exploration
and production related costs that have resulted from an overall increase in the
activity level of the domestic oil and gas industry will continue in the near
future. 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 $1.08 per Mcf equivalent for the first three months of 2001, compared
to $1.03 per Mcf equivalent in the first three 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 March 31, 2001, 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.
-14-
Three Months
--------------------------
2001 2000
--------------------------
($ in thousands, except
for Mcf amounts)
Revenues $81,492 $53,248
Gas purchases $61,289 $30,310
Operating costs and expenses $10,805 $11,568
Operating income $9,398 $11,370
Deliveries (Bcf)
Sales and end-use transportation 10.5 12.1
Off-system transportation -- 1.6
Average number of customers 136,621 182,047
Average sales rate per Mcf $9.32 $5.47
Heating weather - degree days 2,161 1,689
- percent of normal 101% 79%
Note: Amounts and statistics for the three months ended March 31, 2000,
include the operations of the Company's Missouri properties that were
sold in May 2000.
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 March 31, 2001 are up from the comparable
period of 2000 primarily due to the cost of gas supply that has more than
doubled when compared to the prior year's first quarter. The high cost of gas
supply is reflected in the Company's average rate for its utility sales which
increased during the first three months of 2001 to $9.32 per Mcf, up from $5.47
per Mcf for the same period in 2000. The higher prices paid for purchases of
natural gas are passed through to customers under automatic adjustment clauses.
Operating income of the gas distribution segment decreased 17% in the first
quarter of 2001, as compared to the same period of 2000. The decrease in
operating income was due to the impact of the sale of the Company's Missouri gas
distribution assets in May 2000. Weather during the first quarter of 2001 was 1%
colder than normal and 28% colder than in the same period of 2000.
-15-
Operating results for the first quarter of 2000, excluding the Missouri
operations, were approximately even with 2001 due primarily to the Company's
weather normalization clause in its rates. The weather normalization clause
lessens the impacts of revenue increases and decreases that might result from
weather variations during the winter heating season.
Deliveries
The utility systems delivered 10.5 Bcf to sales and end-use transportation
customers during the three months ended March 31, 2001, down from 12.1 Bcf for
the same period in 2000. The decrease in deliveries was due to the sale of the
Missouri operations in May 2000, offset by increased deliveries due to colder
weather. Excluding the effect of the Missouri operations from the three months
ended March 31, 2000, deliveries to sales and end-use transportation customers
were 9.3 Bcf.
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 distribution
segment for the quarter ended March 31, 2001 were lower than the comparable
periods of the prior year due primarily to the sale of the Missouri assets.
Marketing and Other
Three Months
-----------------------
2001 2000
-----------------------
Marketing revenues (in thousands) $71,032 $43,245
Marketing operating income (in thousands) $1,143 $965
Gas volumes marketed (Bcf) 11.0 18.2
Marketing
The increase in gas marketing revenues for the three month period ended March
31, 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 $1.1 million for the first
three months of 2001, compared to $1.0 million for the same period in 2000. The
Company marketed 11.0 Bcf of gas in the first three months of 2001, compared to
18.2 Bcf for the same period in 2000. The decrease in volumes marketed resulted
from a decline in volumes marketed for unaffiliated third parties.
NOARK Pipeline
The Company's share of the NOARK Pipeline System Limited Partnership (NOARK)
pre-tax loss included in other income was $.3 million for the first quarter of
2001, compared to $.6 million for the same period in 2000.
-16-
Interest Expense
Interest expense increased 41% for the first quarter of 2001, compared to the
same period in 2000, 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.
Income Taxes
The changes in the provisions for current and deferred income taxes recorded in
the three months ended March 31, 2001, as compared to the same period in 2000,
resulted primarily from the increase in the level of taxable income in 2001.
Also impacting deferred taxes recorded in the three month period ended March 31,
2001, 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, 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 4
to Consolidated Financial Statements in this Form 10-Q).
Routine capital expenditures, cash dividends and scheduled debt retirements have
predominantly been funded through cash provided by operations. For the first
three months of 2001 and 2000, cash provided by operating activities was $40.4
and $35.6 million, respectively, and exceeded the total of these routine
requirements.
Financing Requirements
In July 2000, the Company replaced its existing revolving credit facilities that
had previously provided the Company access to $80.0 million of variable rate
capital with a new revolving credit facility that has a capacity of $180.0
million. This new facility was used 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 credit facility is also being used to fund
normal working capital needs. The interest rate on the new facility is 112.5
basis points over the LIBOR rate. The new credit facility has a term of 364 days
and the Company intends to renew or replace the facility prior to its
termination. At March 31, 2001, the revolving credit facility had a balance of
$141.8 million and was classified as a current liability in the Company's
balance sheet.
During the first three months of 2001, the Company's total debt decreased by
$29.2 million, due to cash flow generated from operations. Total debt at March
31, 2001, accounted for 72% of the Company's capitalization, down from 74% at
December 31, 2000. The percentage of debt to capitalization at March 31, 2001,
would be 70% without consideration of the $12.2 million of
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accumulated other comprehensive loss recorded in the equity section of the
Company's balance sheet. The other comprehensive loss was recorded as a result
of the adoption of SFAS No. 133 in 2001. The Company expects its borrowings to
continue to decrease during 2001, as a result of its anticipated cash flow from
operating activities.
The Company's capital expenditures for the first three months of 2001 were $15.3
million, compared to $14.6 million for the same period in 2000. Planned capital
investments during calendar year 2001 are currently expected to be approximately
$81.6 million.
At March 31, 2001, the NOARK partnership had outstanding debt totaling $75.0
million. The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on the NOARK debt. The Company's
share of the several guarantee is 60%.
Working Capital
Accounts receivable has declined since December 31, 2000, due to a decrease in
the amounts owed the Company's exploration and production segment for its March
2001 production. The decrease was due to lower commodity prices realized.
Under-recovered purchased gas costs for the Company's gas distribution segment
were $12.2 million at March 31, 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. At March 31, 2001, the Company had a deferred
income tax benefit of $6.6 million and a current hedging liability of $17.0
million resulting from entries recorded as a result of 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. The increase in other current liabilities is
primarily due to advances received from joint venture partners for exploration
and development projects where the Company is the operator. Other changes in
current assets and current liabilities between periods resulted primarily from
the timing of expenditures and receipts and the sale of the Missouri gas
distribution assets in 2000.
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
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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 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.
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PART I
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Market risks relating to the Company's operations result primarily from
changes in commodity prices and interest rates, as well as credit risk
concentrations. The Company uses natural gas and crude oil swap agreements and
options to reduce the volatility of earnings and cash flow due to fluctuations
in the prices of natural gas and oil. The Board of Directors has approved risk
management policies and procedures to utilize financial products for the
reduction of defined commodity price risks. These policies prohibit speculation
with derivatives and limit swap agreements to counterparties with acceptable
credit standings.
Credit Risks
The Company's financial instruments that are exposed to concentrations of
credit risk consist primarily of trade receivables and derivative contracts
associated with commodities trading. Concentrations of credit risk with respect
to receivables are limited due to the large number of customers and their
dispersion across geographic areas. No single customer accounts for greater than
3% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
Interest Rate Risk
The Company's short-term debt obligations are sensitive to changes in
interest rates. The Company's policy is to manage interest rates through use of
a combination of fixed and floating rate debt. Interest rate swaps may be used
to adjust interest rate exposures when appropriate. There were no interest rate
swaps outstanding at March 31, 2001. The Company's short-term debt was $171.0
million at December 31, 2000 and had an average interest rate of 7.83%. At March
31, 2001, the Company's short-term debt was $141.8 million with an average
interest rate of 6.30%. Other than the Company's short-term 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 and marketing activity against
the inherent price risks of adverse price fluctuations or locational pricing
differences between a published index and the NYMEX (New York Mercantile
Exchange) futures market. These swaps 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 the Company the
amount by which the price of the commodity is below the contracted floor and a
"ceiling" price above which the Company pays the counterparty the amount by
which the price of the commodity is above the contracted ceiling.
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The primary market risk related to these derivative contracts is the
volatility in market prices for natural gas and crude oil. However, this market
risk is offset by the gain or loss recognized upon the related sale of the
natural gas or oil that is hedged. Credit risk relates to the risk of loss as a
result of non-performance by the Company's counterparties. The counterparties
are primarily major investment and commercial banks which management believes
present minimal credit risks. The credit quality of each counterparty and the
level of financial exposure the Company has to each counterparty are
periodically reviewed to ensure limited credit risk exposure.
The following table provides information about the Company's financial
instruments that are sensitive to changes in commodity prices. The table
presents the notional amount in Bcf (billion cubic feet), the weighted average
contract prices, and the total dollar contract amount by expected maturity
dates. The "Carrying Amount" for the contract amounts are calculated as the
contractual payments for the quantity of gas or oil to be exchanged under
futures contracts and do not represent amounts recorded in the Company's
financial statements. The "Fair Value" represents values for the same contracts
using comparable market prices at March 31, 2001. At March 31, 2001, the
"Carrying Amount" of these financial instruments exceeded the "Fair Value" by
$20.0 million, which represents the total obligation recorded by the Company at
March 31, 2001.
Expected Maturity Date
2001 2002 2003
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
Natural Gas:
Swaps with a fixed price receipt
Contract volume (Bcf) 1.6 1.0 .2
Weighted average price per Mcf $3.55 $2.65 $2.75
Contract amount (in millions) $5.6 $3.0 $2.6 $.7 $.6 $.3
Swaps with a fixed price payment
Contract volume (Bcf) .2 - - -
Weighted average price per Mcf $4.80 - -
Contract amount (in millions) $1.0 $1.0 - - - -
Price collar
Contract volume (Bcf) 19.1 6.0 -
Weighted average floor price
per Mcf $3.78 $4.00 -
Contract amount of floor
(in millions) $72.3 $75.4 $24.0 $26.5 - -
Weighted average ceiling price
per Mcf $4.66 $4.72 -
Contract amount of ceiling
(in millions) $89.2 $72.6 $28.3 $24.2 - -
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Oil:
Swaps with a fixed price receipt
Contract volume (MBbls) 54 -
Weighted average price per Bbl $17.49 -
Contract amount (in millions) $.9 $.4 - -
Price collar
Contract volume (MBbls) 225 - - - - -
Weighted average floor price
Per Bbl $27.4 - - - - -
Contract amount of floor
(in millions) $6.2 $6.8
Weighted average ceiling price
Per Bbl $29.95 - - - - -
Contract amount of ceiling
(in millions) $6.7 $6.5 - - - -
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PART II
OTHER INFORMATION
Item 1
In the Company's Form 8-K filed July 2, 1996, it previously disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed. The Company also reported in its second quarter 2000
Form 10-Q that this matter had gone to a non-jury trial as to liability in
January 2000 and that the Company was awaiting the court's findings. The court
in this matter has issued Findings of Fact and Conclusions of Law that find no
fraud was committed. The court also finds that any override royalty interests
that may ultimately be found to be subject to the plaintiff's claim for
additional override royalties accrued after March 1, 1990. All claims prior to
March 1, 1990 have been barred by the statute of limitations. The ultimate
measure of damages will be determined during the damages phase of the non-jury
proceedings that is scheduled to occur June 11, 2001. While the company
anticipates that it will owe some additional override royalties to plaintiffs,
it does not believe that its liability will be material to its financial
condition, but in any one period it could be significant to its results of
operations.
Items 2 - 6(a)
No developments required to be reported under Items 2 - 6(a) occurred during the
quarter ended March 31, 2001.
Item 6(b)
On February 2, 2001, the Company filed a current report on Form 8-K announcing
the Company's 2000 year-end oil and gas reserve results.
On February 16, 2001, the Company filed a current report on Form 8-K containing
the transcript of the Company's conference call on February 15, 2001 discussing
the Company's results for the year 2000.
On March 14, 2001, the Company filed a current report on Form 8-K containing the
Company's slide presentation made to investors on March 13, 2001 at the CIBC
World Markets Annual Energy Conference in Boston, Massachusetts, and discussing
the Company's 2000 results and outlook and business strategy for 2001.
On April 18, 2001, the Company filed a current report on Form 8-K containing the
Company's slide presentation to investors made April 18, 2001 at the 2001 IPAA
Oil and Gas Investment Symposium in New York, New York.
On May 3, 2001, the Company filed a current report on Form 8-K containing the
transcript of the Company's conference call on May 1, 2001, discussing the
Company's first quarter 2001 results.
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Signatures
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
--------------------------------
Registrant
DATE: May 3, 2001 /s/ GREG D. KERLEY
------------------ --------------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
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Southwestern Energy Company
P.O. Box 1408
Fayetteville, AR 72702-1408
May 3, 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 March 31, 2001.
This filing is being effected by direct transmission to the Commission's
EDGAR System.
Very truly yours,
Stan Wilson
Controller