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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
Form 10-K
(Mark one)
(x) Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934
For the fiscal year ended December 31, 2000
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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 or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2350 N. Sam Houston Parkway East, Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code: (281) 618-4700
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock - Par Value $.10 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
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 12 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 by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. X
---
The aggregate market value of the voting stock held by non-affiliates
of the Registrant was $271,006,029 based on the New York Stock Exchange --
Composite Transactions closing price on March 8, 2001, of $10.95.
The number of shares outstanding as of March 8, 2001, of the
Registrant's Common Stock, par value $.10, was 25,188,574.
DOCUMENTS INCORPORATED BY REFERENCE
Document incorporated by reference and the Part of the Form 10-K into
which the document is incorporated: Definitive Proxy Statement to holders of the
Registrant's Common Stock in connection with the solicitation of proxies to be
used in voting at the Annual Meeting of Shareholders on May 17, 2001 - PART III.
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SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT on FORM 10-K
For the Year Ended December 31, 2000
TABLE OF CONTENTS Page
Part I
Item 1. Business 3
Business Strategy 3
Exploration and Production 3
Natural Gas Distribution 11
Marketing and Transportation 14
Other Items 16
Item 2. Properties 17
Item 3. Legal Proceedings 18
Item 4. Submission of Matters to a Vote of Security Holders 19
Executive Officers of the Registrant 20
Part II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters 21
Item 6. Selected Financial Data 22
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 24
Item 7.A. Quantitative and Qualitative Disclosure About Market Risks 34
Item 8. Financial Statements and Supplementary Data 37
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 60
Part III
Item 10. Directors and Executive Officers of the Registrant 60
Item 11. Executive Compensation 60
Item 12. Security Ownership of Certain Beneficial Owners
and Management 61
Item 13. Certain Relationships and Related Transactions 61
Part IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K 61
2
Part I
ITEM 1. BUSINESS
Southwestern Energy Company (the "Company" or "Southwestern") is an
energy company primarily focused on natural gas. The Company was incorporated in
Arkansas in 1929 as a local gas distribution company. Today, Southwestern is an
exempt holding company under the Public Utility Holding Company Act of 1935 and
derives the vast majority of its operating income and cash flow from its oil and
gas exploration and production business. The Company is involved in the
following business segments:
1. Exploration and Production - Engaged in natural gas and oil
exploration, development and production, with operations principally
located in Arkansas, Oklahoma, Texas, New Mexico, and Louisiana. This
represents the Company's primary business.
2. Natural Gas Distribution - Engaged in the gathering, distribution and
transmission of natural gas to approximately
136,000 customers in Arkansas.
3. Marketing and Transportation - Provides marketing and transportation
services in the Company's core areas of operation and owns a 25%
interest in the NOARK Pipeline System, Limited Partnership (NOARK).
This Report on Form 10-K includes certain statements that may be deemed
to be "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations" in Part II, Item 7 of this Report for a discussion of factors that
could cause actual results to differ materially from any such forward-looking
statements.
Business Strategy
The Company's business strategy is to provide long-term growth through
focused exploration and production of oil and natural gas. The Company seeks to
maximize cash flow and earnings and provide consistent growth in oil and gas
production and reserves through the discovery, production and marketing of high
margin reserves from a balanced portfolio of drilling opportunities. This
balanced portfolio includes low risk development drilling in the Arkoma Basin,
moderate risk exploration and exploitation in the Permian Basin and east Texas,
and high potential exploration opportunities in the onshore Gulf Coast.
Additionally, the Company creates additional value through its natural
gas distribution, marketing and transportation activities. During 2000,
Southwestern announced its intent to sell its gas distribution business.
However, the Company has not received an offer that it believes reflects the
true value of the utility system. Accordingly, Southwestern will continue to
hold and operate these assets. The Company further enhances shareholder value by
creating and capturing additional value beyond the wellhead through its
marketing and transportation activities.
EXPLORATION AND PRODUCTION
In 1943, the Company commenced a program of exploration and development
of natural gas reserves in Arkansas for supply to its utility customers. In
1971, the Company initiated an exploration and development program outside
Arkansas, unrelated to the utility's requirements. Since that time, the
Company's exploration and development activities outside Arkansas have expanded
substantially.
3
During 1998, Southwestern brought in new senior operating management
and replaced over 50% of its professional technical staff to refocus its
exploration and production segment. Additionally in 1998, the Company closed its
Oklahoma City office and moved these operations to its Houston office in an
effort to increase future profitability. The segment was also reorganized into
asset management teams to provide an area specific focus in exploration and
development projects and a new incentive compensation system was put in place to
more closely align its employees' efforts with the interests of its
shareholders. As a result of these changes, the operating results of this
business segment have improved substantially, with results in 2000 some of the
best in the Company's history.
At December 31, 2000, the Company had proved oil and gas reserves of
380.5 billion cubic feet (Bcf) equivalent, including proved natural gas reserves
of 331.8 Bcf and proved oil reserves of 8,130 thousand barrels (MBbls). The
Company's reserve life index approximated 10.7 years at year-end 2000, with 82%
of total reserves classified as proved developed. All of the Company's reserves
are located entirely within the United States. Revenues of the exploration and
production subsidiaries are predominately generated from production of natural
gas. Sales of gas production accounted for 82% of total operating revenues for
this segment in 2000, 87% in 1999 and 89% in 1998.
Areas of Operation
Southwestern engages in gas and oil exploration and production through
its subsidiaries, SEECO, Inc. (SEECO), Southwestern Energy Production Company
(SEPCO), and Diamond "M" Production Company (Diamond M). SEECO operates
exclusively in the state of Arkansas and holds a large base of both developed
and undeveloped gas reserves and conducts an ongoing drilling program in the
historically productive Arkansas part of the Arkoma Basin. SEPCO conducts
development drilling and exploration programs in the Oklahoma portion of the
Arkoma Basin, the Permian Basin of Texas and New Mexico, the Anadarko Basin of
Oklahoma, Louisiana, and Texas. Diamond M operates properties in the Permian
Basin of Texas.
The following table provides December 31, 2000 information as to proved
reserves, well count, and gross and net acreage, and 2000 annual information as
to production, capital expenditures and reserve additions for each of the
Company's core operating areas.
Texas/
Arkoma Mid-Continent New Mexico Louisiana Total
-------------------------------------------------------------
Proved Reserves:
Gas (Bcf) 200.3 24.4 82.2 24.9 331.8
Oil (MBbls) - 1,759 5,176 1,195 8,130
Total Reserves (Bcfe) 200.3 34.9 113.2 32.1 380.5
Capital Expenditures (in millions) $17.6 - $27.7 $23.9 $69.2
Production (Bcfe) 19.9 3.5 9.9 2.4 35.7
Reserve Additions (Bcfe) 18.4 1.2 30.6 19.9 70.1
Total Gross Wells 808 564 401 32 1,805
Percent Operated 44% 28% 37% 44% 37%
Gross Acreage 387,633 164,455 436,519 102,027 1,090,634
Net Acreage 249,267 57,699 136,125 31,836 474,927
4
Arkoma Basin. The Arkoma Basin provides a solid foundation for the
Company's exploration and production program and represents the primary source
of production and reserves for the Company. At December 31, 2000, the Company
had approximately 200.3 Bcf of natural gas reserves in the Arkoma Basin,
representing 60% of the Company's natural gas reserves and 53% of total reserves
on a Bcf equivalent (Bcfe) basis. The Company participated in 42 wells during
2000 with a 76% success ratio and an average working interest of 47%. The
Company's Arkoma drilling program added 18.4 Bcf of gas reserves at a finding
and development cost of $0.97 per thousand cubic feet (Mcf). Average net daily
production in 2000 was 54.6 million cubic feet (MMcf).
The Company's strategy in the Arkoma is to annually replace production
from the basin with new reserves at a finding cost of under $1.00 per Mcf. The
Company intends to continue that strategy by investing approximately $21 million
and drilling approximately 50 wells in the basin in 2001.
Southwestern's Arkoma Basin operations continue to generate a
significant amount of the Company's cash flow. Production, or lifting, costs in
the basin continued to be extremely low during 2000 at $.24 per Mcf (including
production taxes). After direct general and administrative expenses of $.14 per
Mcf, Southwestern's netback per Mcf after cash operating expenses was 88% of the
average price it received for its Arkoma production in 2000.
Southwestern's traditional operating area over the years has been in
the "fairway" portion of the basin, which is primarily within the boundaries of
the Company's utility gathering system. The Company's strategy in this core
producing area is to delineate new geologic plays and extend previously
identified trends using Southwestern's extensive databank of regional structural
and stratigraphic maps. Southwestern completed five wells out of seven drilled
in the fairway in 2000 that added 6.1 Bcf of new reserves. The largest success
in this area was the Sexton #1-20 well in Johnson County, Arkansas. This well
was placed on production in February 2000 at 3.6 MMcf of gas per day (MMcfd) and
added 3.3 Bcf of new reserves in 2000. Southwestern plans to drill up to 13
wells in the fairway portion of the basin in 2001.
In recent years, Southwestern has extended its development program
outside of the traditional fairway area to continue its growth. In 1998,
Southwestern drilled its first exploratory well at its Ranger Anticline prospect
area, located in the southern edge of the Arkansas portion of the basin. This
prospect area features a complex series of thrusted anticlinal folds containing
deepwater Pennsylvanian sands. To date, the Company has successfully drilled six
out of nine wells in this prospect, adding 9.9 Bcf of reserves net to
Southwestern's interest at a finding cost of $.56 per Mcf. In December 2000, the
Company secured 20,200 net federal acres with a 10-year lease term to further
develop this play. Southwestern plans to drill up to six wells here in 2001.
In 2000, Southwestern built on its initial drilling success in new
discovery areas such as Cherokee and Haileyville in eastern Oklahoma. In the
Cherokee prospect area in LeFlore County, the Company successfully drilled eight
wells out of nine in 2000. At Haileyville, three wells out of the four drilled
were completed, including the Collins #1-13 well, which is currently producing
over 7.2 million cubic feet of gas per day (MMcfd). The Company believes there
is significant potential that is currently untapped in this area of the basin,
and these prospects will be focus areas in 2001.
Mid-Continent. The Company's activities in this region are primarily
focused on the Anadarko Basin of Oklahoma. At December 31, 2000, the Company had
approximately 24.4 Bcf of natural gas reserves and 1,759 MBbls of oil reserves
in the region, representing 7% and 22%, respectively, of the Company's total gas
and oil reserves. Average net daily production in 2000 for this region was 9.6
MMcf equivalent (MMcfe). Southwestern does not expect its
5
Mid-Continent operations to be a primary area of future growth, due to its
efforts to concentrate on those areas where it has a competitive advantage. The
Company intends to produce these properties to depletion, sell them or trade
them for properties in the Company's core areas of operation. During 2000, the
Company sold at auction a portion of its properties in the Mid-Continent area
with proved reserves of 13.8 Bcfe for approximately $13.1 million.
Texas/New Mexico. The Company has key operations in the states of Texas
and New Mexico, and is primarily focused here on the Permian Basin in west Texas
and southeast New Mexico, the onshore Texas Gulf Coast and a newly acquired
producing field in east Texas. At December 31, 2000, Southwestern had proved
reserves of 82.2 Bcf of gas and 5,176 MBbls of oil in the region, representing
25% and 64%, respectively, of the Company's total gas and oil reserves.
Over the past three years, Southwestern has made meaningful strides in
establishing itself as a significant player in the Permian Basin. At December
31, 2000, Southwestern had proved reserves of 38.2 Bcf of gas and 4,670 MBbls of
oil in the basin, or 66.2 Bcfe. The Company successfully completed 43 out of 57
wells drilled in the Permian in 2000, resulting in a success rate of 75%.
Southwestern's average working interest in the Permian during 2000 was 27%.
Average net daily production in the basin was 27.1 MMcfe and production costs,
including production taxes, averaged $.77 per Mcf equivalent (Mcfe) during 2000.
Southwestern continued to develop its Logan Draw prospect area in Eddy
County, New Mexico, successfully completing 10 out of 13 wells there in 2000.
Southwestern has an average working interest of 32% in the Logan Draw
development area, which is the combination of the Company's Top Dog, Amber, and
Freight Train prospects. To date, the Company has drilled 21 successful wells
out of 26 and has added 8.1 Bcfe of reserves at a finding cost of $.84 per Mcfe.
In late 1999, the Company entered into a joint exploration agreement
with Phillips Petroleum to explore for deeper formations under acreage that is
held-by-production in southeast New Mexico. This initial joint venture agreement
spawned the development of two more joint exploration agreements that were
consummated in late 2000, one with Energen Resources and a second agreement with
Phillips. In total, these agreements provide the Company access to an additional
98,700 gross acres to pursue drilling opportunities. Under each agreement,
Southwestern's partners have a deferred election clause at casing point,
allowing them to retain a pre-specified working interest share. Southwestern is
the operator of all wells under the agreements. These agreements have terms
ranging from 12 to 21 months, and each has continuous drilling options
thereafter. To date, the Company has drilled nine out of eleven successful wells
under these joint ventures, and plans to drill at least six wells under these
agreements in 2001.
One meaningful discovery resulting from the first Phillips joint
venture is the Company's oil discovery at its Bimini prospect in Lea County, New
Mexico. The Company was successful on five wells out of five drilled, and
together the wells are currently producing 450 barrels of oil per day (Bopd) and
480 MMcfd from the Blinebry formation. The discovery at Bimini has set up two
additional prospect areas with similar Blinebry potential that will be tested
during 2001. The Company also had discoveries in 2000 at its Heisman and Outland
prospects under this agreement with follow-up drilling planned for these areas.
The Company entered the prolific gas-producing area of east Texas with
the acquisition of producing properties in the Overton Field in Smith County,
Texas in April 2000. This transaction creates an additional low-risk multi-year
development drilling program for the Company and is discussed more fully below
under "Acquisitions."
6
Louisiana. Southwestern began its drilling program in south Louisiana
in 1996 and this area continues to be the main focus area of the Company's
high-impact exploration activities. At December 31, 2000, Southwestern had
proved reserves of 24.9 Bcf of gas and 1,195 MBbls of oil in the state,
representing 8% of the Company's total reserves on a gas equivalent basis.
Average net daily production in this area was 6.6 MMcfe and production costs
(including production taxes) averaged $.87 per Mcfe during 2000.
The Company has an extensive inventory of 3-D seismic data covering
over 1,230 miles in Louisiana. From this extensive 3-D database, Southwestern
has internally generated a multi-year inventory of exploration prospects to be
drilled in 2001 and beyond. The Company also continues to gain exposure to
additional 3-D seismic data for future drilling opportunities.
Southwestern has been successful in four out of its last five
exploration wells in this area, beginning with its first internally-generated
discovery in December 1999 at its Gloria prospect in Assumption Parish. The
Dugas & LeBlanc #1 well was placed on production in February 2000 and is
currently producing 9.6 MMcfd and 310 barrels of condensate per day (Bcpd).
Southwestern is the operator of the well and holds a 50% working interest.
The Company announced in February 2000 that it had made a significant
discovery at its North Grosbec prospect, also in Assumption Parish, which has
resulted in one of the largest discoveries in the Company's history. The
Brownell-Kidd #1 well was placed on production in May 2000 and is currently
producing 16.2 MMcfd and 575 Bcpd. The Company holds a 25% working interest in
this well which is operated by Petro-Hunt, L.L.C. Southwestern plans to drill up
to two additional development wells at North Grosbec in 2001 to facilitate
efficient depletion of the reservoir.
After drilling a dry hole at its Brigadoon prospect, the Company made
another gas discovery in its Eden 3-D project area. The Eden 3-D project was an
alliance formed with industry partners to jointly explore a 146-mile proprietary
3-D seismic survey in the Nodosaria Embayment area of Lafayette, St. Landry and
Acadia Parishes. The Company's first well drilled in the project, the Robertson
#1, was placed on production in late-December 2000 and is currently producing at
6.8 MMcfd and 317 Bcpd. Southwestern operates the well with a 27.5% working
interest. The Company plans to drill two additional exploratory tests in its
Eden 3-D project area in 2001 and has identified several additional prospect
leads for 2002.
In January 2001, Southwestern announced a discovery at its Malone
prospect, located south of the Company's Gloria discovery in Assumption Parish.
The SL 16626 #1 well encountered approximately 260 feet of gas pay in five
separate productive sands within the Miocene formation. Southwestern is
currently completing this well and plans to have it placed on production in
March. After drilling the initial discovery well, an offset development well was
immediately drilled and reached total depth in February. Logs indicate favorable
pay development and the Company expects this well to be placed on production by
May. Southwestern has a 33 percent working interest in this prospect and
believes that it represents a significant gas accumulation.
Acquisitions
In April 2000, the Company purchased the Overton Field in Smith County,
Texas, from Total Fina Elf for $6.1 million. Proved developed producing reserves
associated with the purchase were 7.5 Bcfe, for a purchase price of $.81 per
Mcfe. The purchase included 16 active gas wells in 13 spacing units, 8,800
contiguous acres in established units and 2,000 additional undeveloped acres
outside the units. The Overton Field represents a significant low-risk
development opportunity for Southwestern, as it is one of the last Cotton Valley
Sand fields in east Texas that has not been downspaced from original 640-acre
units. Currently, adjacent gas-producing fields in the area are spaced at
80-acre to 160-acre units.
7
Southwestern plans to drill between 8 and 14 wells in the field in 2001,
primarily targeting the Cotton Valley Taylor Sand formation above 12,000 feet.
Based on the well performance of the initial development phase, there is the
potential for 22 to 38 additional development locations to be drilled over the
next few years based upon 160-acre unit spacing.
In 1999, the Company purchased producing properties in the Permian
Basin with estimated proved reserves of 9.4 Bcf of gas and 576 MBbls, or 12.9
Bcfe. The properties were purchased from Petro-Quest Exploration, a privately
held company headquartered in Midland, Texas, for $9.4 million. The Company did
not make any producing property acquisitions in 1998 or 1997. In 1996, the
Company acquired approximately 32.7 Bcf of gas and 6,350 MBbls of oil located in
Texas and Oklahoma for $45.8 million. The Company's current strategy is to
pursue selective acquisitions that would complement its existing operations.
Capital Spending
The Company invested a total of $69.2 million in its exploration and
production program during 2000, and participated in a total of 105 wells, of
which 78 were successful. The Company's investments were balanced between the
Company's core areas of operations, with approximately $17.6 million invested in
the Arkoma Basin, $27.7 million in the Texas/ New Mexico region and $23.9
million for exploration, primarily in south Louisiana. Of these expenditures,
approximately $19.3 million was invested in exploration wells, $23.8 million in
development drilling and workovers, $5.1 million for land and leasehold
acquisition, $4.1 million in seismic expenditures, $6.7 million for producing
property acquisitions and $10.2 million in capitalized interest, expenses and
other technology-related expenditures.
In 2001, the Company's capital budget for exploration and production is
$75.0 million, with approximately 75% of this capital dedicated to drilling. As
in 2000, the Company's investments will again be balanced between the Company's
core areas of operations, with approximately $20.5 million allocated to the
Company's low-risk development activities in the Arkoma Basin, $30.3 million
allocated to medium-risk exploration and exploitation in the Texas/New Mexico
area, and $24.2 million allocated to high-potential exploration in south
Louisiana. Of the $75.0 million capital budget, approximately $23.7 million is
allocated to exploration wells, $32.3 million to development drilling, $4.7
million for land and leasehold acquisition, $3.3 million for seismic
expenditures, and $11.0 million in capitalized interest, expenses and
technology-related items. Although no capital was budgeted for acquisitions in
2001, the Company will continue to seek producing property acquisitions in its
core producing areas that would complement its overall strategy. The Company
expects to maintain its capital investments within the limits of internally
generated cash flow, and will adjust its capital program accordingly.
Sales and Major Customers
Natural gas equivalent production averaged 97.7 million cubic feet
equivalent per day (MMcfed) in 2000, compared to 90.2 MMcfed in 1999 and 101.1
MMcfed in 1998. The Company's gas production was 31.6 Bcf in 2000, compared to
29.4 Bcf in 1999, and 32.7 Bcf in 1998. The Company also produced 676,000
barrels of oil in 2000, compared to 578,000 barrels in 1999, and 703,000 barrels
in 1998. The decreases in production in 1999 were the result of lower
non-operated production due to the industry slowdown during late 1998 and early
1999, the decline in production from certain wells in the Gulf Coast area and
production losses from marginal properties that were sold during the year. The
Company expects its equivalent production in 2001 to increase approximately 7%
over the level in 2000.
The Company's natural gas production realized an average wellhead price
of $2.88 per Mcf in 2000, compared to $2.21 per Mcf in 1999 and $2.34 per Mcf in
1998. The Company's average oil price realized was $22.99 per barrel in 2000,
compared to $17.11 per barrel in 1999 and $13.60 per barrel in 1998.
Southwestern's largest single customer for sales of its gas production
is the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas
Western). Sales from SEECO to Arkansas Western accounted for approximately 24%
of
8
total exploration and production revenues in 2000, 31% in 1999 and 38% in 1998.
All of the Company's remaining sales are to unaffiliated purchasers. SEECO's
sales to Arkansas Western were 7.8 Bcf in 2000, compared to 8.2 Bcf in 1999 and
11.3 Bcf in 1998. The decrease in affiliated gas sales in 1999 was the result of
warmer weather in the utility's service territory combined with the loss of
certain intercompany gas supply contracts.
Gas volumes sold by SEECO to Arkansas Western for its northwest
Arkansas division (AWG) were 5.1 Bcf in 2000 and 1999, and 7.7 Bcf in 1998.
Through these sales, SEECO furnished 36% of the northwest Arkansas system's
requirements in 2000, 38% in 1999 and 55% in 1998. SEECO also delivered
approximately 2.8 Bcf in 2000, 2.6 Bcf in 1999 and 2.0 Bcf in 1998, directly to
certain large business customers of AWG through a transportation service of the
utility subsidiary.
Prior to 1999, most of the sales to AWG were pursuant to a twenty-year
contract between SEECO and AWG, entered into in July 1978, under which the price
was frozen between 1984 and 1994. This contract was amended in 1994 as a result
of a settlement reached to resolve certain gas cost issues before the Arkansas
Public Service Commission. This contract expired July 24, 1998 but continued on
a month-to-month basis through November 1998.
In March 1997, AWG filed a gas supply plan with the Arkansas Public
Service Commission (APSC) which projected system load growth patterns and
long-range gas supply needs for the utility's northwest Arkansas system. The gas
supply plan also addressed replacement supplies for AWG's long-term contract
with SEECO. After discussions with the APSC it was determined that the majority
of the utility's future gas supply needs should be provided through a
competitive bidding process. On October 1, 1998, AWG sent requests for proposals
to various suppliers requesting bids on seven different packages of gas supply
to be effective December 1, 1998. These bid requests included replacement of the
gas supply and no-notice service previously provided by the long-term gas supply
contract between AWG and SEECO. Eleven potential suppliers returned bids in late
October.
SEECO along with the Company's marketing subsidiary successfully bid on
five of the original seven packages with prices based on the NorAm East Index
plus a demand charge. The volumes of gas projected to be sold under these
contracts in their first year were approximately equal to the historical annual
volumes sold under the expired long-term contracts, assuming normal weather
patterns. However, the volumes to be sold under these contracts are not fixed
and will fluctuate with the weather-related requirements of AWG. These contracts
provide more of the gas needed during periods of colder weather, and less of
AWG's base system needs. As a result, periods of abnormally warmer weather, such
as in 1999 and 1998, result in lower deliveries to AWG by SEECO. However,
charges for no-notice service associated with these contracts are approximately
$6.0 million per year and are received by SEECO regardless of weather patterns.
Other sales to AWG are made under long-term contracts with flexible pricing
provisions. Two of the five original gas supplying packages have come up for
rebid since 1998 and were not awarded to SEECO. These packages provide
approximately 2.5 Bcf of AWG's annual gas supply. There were no demand fees
associated with the two contracts not renewed. In 2001, AWG will again perform a
competitive bidding process for its primary gas supply needs and the Company
expects its subsidiaries to aggressively bid to retain the contracts currently
in place.
SEECO's sales to Associated Natural Gas Company (Associated), a
division of Arkansas Western which operates a natural gas distribution system in
northeast Arkansas, were 2.7 Bcf in 2000, 3.1 Bcf in 1999 and 3.6 Bcf in 1998.
These deliveries accounted for approximately 51% of Associated's total
requirements in 2000, 42% in 1999 and 46% in 1998. The decrease in 2000 volumes
delivered was due to Southwestern's sale of its Missouri utility assets in May
2000, as discussed below in "Natural Gas Distribution," somewhat offset by
colder than normal weather in November and December 2000. The decrease in 1999
was due to record warm weather. Effective October 1990, SEECO entered into a
ten-year contract with Associated to supply a portion of its system requirements
at a price to be redetermined annually. For the contract period beginning
October 1, 1997, the contract was revised to redetermine the sales price monthly
based on an index
9
posting plus a reservation fee. Effective October 2000, Associated placed its
gas supply out for competitive bids. SEECO was successful in obtaining a
one-year bid to supply approximately 1.0 Bcf of gas, or approximately 40% of
Associated's annual requirement assuming normal weather patterns.
At present, SEECO's contracts for sales of gas to unaffiliated
customers consist of short-term sales made to customers of the utility
subsidiary's transportation program and spot sales into markets away from the
utility's distribution system. These sales are subject to seasonal price swings.
SEECO's sales to unaffiliated customers are also affected by the demand of the
utility for production on its gathering system. SEECO's sales to unaffiliated
purchasers accounted for approximately 29% of total exploration and production
revenues in 2000, 28% in 1999 and 19% in 1998.
The combined gas production of SEPCO and Diamond M was 13.8 Bcf in
2000, compared to 10.5 Bcf in 1999 and 13.2 Bcf in 1998. Oil production was 676
MBbls in 2000, compared to 578 MBbls in 1999 and 703 MBbls in 1998. SEPCO's and
Diamond M's gas and oil production is sold under contracts with unaffiliated
purchasers which reflect current short-term prices and which are subject to
seasonal price swings. SEPCO's and Diamond M's combined gas and oil sales
accounted for 47% of total exploration and production revenues in 2000, 41% in
1999 and 43% in 1998.
The Company periodically enters into hedging activities with respect to
a portion of its projected crude oil and natural gas production through a
variety of financial arrangements intended to support oil and gas prices at
targeted levels and to minimize the impact of price fluctuations. The Company's
policies prohibit speculation with derivatives and limit swap agreements to
counterparties with appropriate credit standings. At December 31, 2000, the
Company had hedges in place on 34.7 Bcf of future gas production and 697,000
barrels of future oil production. Subsequent to December 31, 2000, the Company
closed its position on 298,000 barrels of 2001 oil production with a floor price
of $18.00. The Company currently has hedges in place on approximately 80% of its
2001 anticipated gas production and approximately 50% of its 2001 anticipated
oil production. See Item 7.A. of this Form 10-K, "Quantitative and Qualitative
Disclosures About Market Risk," for further information regarding the Company's
hedge position at December 31, 2000.
Competition
All phases of the gas and oil industry are highly competitive.
Southwestern competes in the acquisition of properties, the search for and
development of reserves, the production and sale of gas and oil and the securing
of the labor and equipment required to conduct operations. Southwestern's
competitors include major gas and oil companies, other independent gas and oil
concerns and individual producers and operators. Many of these competitors have
financial and other resources that substantially exceed those available to
Southwestern. Gas and oil producers also compete with other industries that
supply energy and fuel. During 2000 the impact of inflation and competition
intensified as shortages in drilling rigs, third party services and qualified
labor developed due to an overall increase in the activity level of the domestic
oil and gas industry. The Company anticipates that inflationary pressures and
industry competition will continue to increase for the foreseeable future.
Competition in the state of Arkansas has increased in recent years, due
largely to the development of improved access to interstate pipelines. Due to
the Company's significant leasehold acreage position in Arkansas and its
long-time presence and reputation in this area, the Company believes it will
continue to be successful in acquiring new leases in Arkansas. While improved
intrastate and interstate pipeline transportation in Arkansas should increase
the Company's access to markets for its gas production, these markets will
generally be served by a number of other suppliers. Thus, the Company will
encounter competition that may affect both the price it receives and contract
terms it must offer. Outside Arkansas, the Company is less established and faces
competition from a larger number of other producers. The Company has in recent
years been successful in building its inventory of undeveloped leases and
obtaining participating interests in drilling prospects in its core areas of
operations.
10
NATURAL GAS DISTRIBUTION
The Company's subsidiary Arkansas Western Gas Company operates
integrated natural gas distribution systems concentrated primarily in northern
Arkansas. The APSC regulates the Company's utility rates and operations. The
Company serves approximately 136,000 customers and obtains a substantial portion
of the gas they consume through its Arkoma Basin gathering facilities.
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. The gas distribution statistics discussed below include the results from
the Company's Missouri utility operations through May 2000.
In June 2000, Southwestern announced its intent to sell its remaining
utility operations in Arkansas to fund a $109.3 million judgment against the
Company (Hales judgment). The Company hired Morgan Stanley Dean Witter as its
investment advisor to manage the auction process and the Company received
several serious expressions of interest from bona fide parties. However, to
date, the Company has not received an offer that it believes reflects the true
value of the utility system. Accordingly, Southwestern will continue to hold and
operate these assets. Absent a sale of its utility assets, the Company's
strategy is to utilize cash flow in excess of its capital requirements to reduce
the debt incurred as a result of the Hales judgment. As part of this strategy,
the Company has hedged approximately 80% of its 2001 anticipated gas production
and 50% of its 2001 anticipated oil production at attractive prices (as
discussed previously under "Exploration and Production") to ensure that it will
have cash flow available to reduce the debt level.
Arkansas Western consists of two operating divisions. The AWG division
gathers natural gas in the Arkansas River Valley of western Arkansas and
transports the gas through its own transmission and distribution systems,
ultimately delivering it at retail to approximately 115,000 customers in
northwest Arkansas. The Associated division receives its gas from transportation
pipelines and delivers the gas through its own transmission and distribution
systems, ultimately delivering it at retail to approximately 21,000 customers in
northeast Arkansas. Associated, formerly a wholly-owned subsidiary of Arkansas
Power and Light Company, was acquired and merged into Arkansas Western effective
June 1, 1988.
Gas Purchases and Supply
AWG purchases its system gas supply through a competitive bidding
process implemented in late 1998, as discussed above, and directly at the
wellhead under long-term contracts. SEECO furnished approximately 36% of AWG's
system requirements in 2000, 38% in 1999 and 55% in 1998. AWG also purchases gas
from unaffiliated producers under take-or-pay contracts. Currently, the Company
believes that it does not have a significant exposure to take-or-pay liabilities
resulting from these contracts. The Company expects to be able to continue to
satisfactorily manage its exposure to take-or-pay liabilities.
Associated purchases gas for its system supply from unaffiliated
suppliers accessed by interstate pipelines and from affiliates. Purchases from
unaffiliated suppliers are under firm contracts with terms between one and three
years. The rates charged by most suppliers include demand components to ensure
availability of gas supply, administrative fees, and a commodity component which
is based on monthly indexed market prices. Associated's gas purchases are
transported through four pipelines. The pipeline transportation rates include
demand charges to reserve pipeline capacity and commodity charges based on
volumes transported. Associated has also contracted with an interstate pipeline
for storage capacity to meet its peak seasonal demands. These contracts involve
demand charges based on the maximum deliverability, capacity charges based on
the maximum storage quantity, and charges for the quantities injected and
withdrawn.
11
AWG has no restriction on adding new residential or commercial
customers and will supply new industrial customers that are compatible with the
scale of its facilities. AWG has never denied service to new customers within
its service area or experienced curtailments because of supply constraints. In
addition, Associated has never denied service to new customers within its
service area or experienced curtailments because of supply constraints since the
acquisition date. Curtailment of large industrial customers of AWG and
Associated occurs only infrequently when extremely cold weather requires that
systems be dedicated exclusively to human needs customers.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual cost of purchased gas above or below the
level included in the base rates is permitted to be billed or is required to be
credited to customers. Each month, the difference between actual costs of
purchased gas and gas costs recovered from customers is deferred. The deferred
differences are billed or credited, as appropriate, to customers in subsequent
months.
Markets and Customers
The utility continues to capitalize on the healthy economies and
sustained customer growth found in its service territory. AWG and Associated
provide natural gas to approximately 119,000 residential, 16,300 commercial, and
225 industrial customers, while also providing gas transportation services to
approximately 40 end-use and off-system customers. Total gas throughput in 2000
was 33.5 Bcf, compared to 36.4 Bcf in 1999 and 32.8 Bcf in 1998. In 2000, the
loss of throughput associated with the sale of the utility's Missouri assets was
partially offset by colder weather. The increase in 1999 was the result of
higher off-system transportation volumes. Off-system transportation volumes were
3.1 Bcf in 2000, compared to 4.8 Bcf in 1999 and 1.1 Bcf transported in 1998.
Residential and Commercial. Approximately 85% of the utility's revenues
are from residential and commercial markets. Residential and commercial
customers combined accounted for 55% of total gas throughput for the gas
distribution segment in 2000, compared to 51% in 1999 and 57% in 1998. Gas
volumes sold to residential customers were 10.9 Bcf in 2000, compared to 10.8
Bcf in 1999 and 11.1 Bcf in 1998. Gas sold to commercial customers totaled 7.6
Bcf in 2000, 1999 and 1998. Weather during the calendar year 2000 was normal as
measured by degree days, however, deliveries were negatively impacted by the
sale of the Company's Missouri properties. The decrease in residential gas
volumes sold in 1999 was due to record warm weather. Weather during 1999 was 21%
warmer than normal and 8% warmer than in 1998.
The gas heating load is one of the most significant uses of natural gas
and is sensitive to outside temperatures. Sales, therefore, vary throughout the
year. Profits, however, have become less sensitive to fluctuations in
temperature recently as tariffs implemented in Arkansas contain a weather
normalization clause to lessen the impact of revenue increases and decreases
which might result from weather variations during the winter heating season.
Industrial and End-use Transportation. Deliveries to industrial
customers, which are generally smaller concerns using gas for plant heating or
product processing, accounted for 11.8 Bcf in gas deliveries in 2000, 13.1 Bcf
in 1999 and 13.0 Bcf in 1998. No industrial customer accounts for more than 8%
of Arkansas Western's total throughput. The decline in deliveries in 2000 was
primarily the result of the sale of the utility's Missouri operations.
Both AWG and Associated offer a transportation service that allows
larger business customers to obtain their own gas supplies directly from other
suppliers. A total of 39 customers are currently using the transportation
service, including AWG's 17 largest customers in northwest Arkansas and
Associated's 3 largest customers in northeast Arkansas.
12
Competition
AWG and Associated have experienced a general trend in recent years
toward lower rates of usage among their customers, largely as a result of
conservation efforts that the Company encourages. Competition is increasingly
being experienced from alternative fuels, primarily electricity, fuel oil, and
propane. A significant amount of fuel switching has not been experienced,
though, as natural gas has generally been the least expensive, most readily
available fuel in the service territories of AWG and Associated. This could
change, however, if natural gas prices continue to remain at their current high
levels.
The competition from alternative fuels and, in a limited number of
cases, alternative sources of natural gas have intensified in recent years.
Industrial customers are most likely to consider utilization of these
alternatives, as they are less readily available to commercial and residential
customers. In an effort to provide some pricing alternatives to its large
industrial customers with relatively stable loads, AWG offers an optional tariff
to its larger business customers and to any other large business customer which
shows that it has an alternate source of fuel at a lower price or that one of
its direct competitors has access to cheaper sources of energy. This optional
tariff enables those customers willing to accept the risk of price and supply
volatility to direct AWG to obtain a certain percentage of their gas
requirements in the spot market. Participating customers continue to pay the
non-gas cost of service included in AWG's present tariff for large business
customers and agree to reimburse AWG for any take-or-pay liability caused by
spot market purchases on the customer's behalf.
Regulation
The Company's utility rates and operations are regulated by the APSC.
The Company operates through municipal franchises that are perpetual by state
law. These franchises, however, are not exclusive within a geographic area.
As the regulatory focus of the natural gas industry shifts from the
federal level to the state level, utilities across the nation are being required
to unbundle their sales services from transportation services in an effort to
promote greater competition. Although no such legislation or regulatory
directives related to natural gas are presently pending in Arkansas, the Company
is aggressively controlling costs and constantly reviewing issues such as system
capacity and reliability, obligation to serve, rate design and stranded or
transition costs.
In Arkansas, the state legislature is now considering legislation that
would deregulate the retail sale of electricity in Arkansas as soon as 2002. At
this time, it is unknown whether or not such legislation will be adopted or if
it is adopted, what its final form will be. The Company is also unable to
predict the precise impact of any such legislation on its utility operations.
The Company's utility subsidiary has historically maintained a substantial price
advantage over electricity for most applications. However, if gas prices are at
high levels or if retail electric competition is implemented in Arkansas, it is
possible that some portion of this price advantage may be lost in some markets.
As described in the paragraph above, the Company is taking steps to preserve its
competitive advantage over alternative energy sources, including electricity. If
electric deregulation occurs in Arkansas, legislative or regulatory precedents
may be set that would also affect natural gas utilities in the future. These
issues may include further unbundling of services and the regulatory treatment
of stranded costs.
Gas distribution revenues in future years will be impacted by customer
growth and rate increases allowed by the APSC. In recent years, AWG has
experienced customer growth of approximately 2% to 3% annually, while Associated
has experienced customer growth of approximately 1% or less annually. Based on
current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue.
13
In December 1996, AWG received approval from the APSC for a rate
increase of $5.1 million annually. The December 1996 rate increase order issued
by the APSC also provided that AWG cause to be filed with the APSC an
independent study of its procedures for allocating costs between regulated and
non-regulated operations, its staffing levels and executive compensation. The
independent study was ordered by the APSC to address issues raised by the Office
of the Attorney General of the State of Arkansas. The study was conducted in
1999 with a final report issued in December 1999. The report found the Company's
costs to be reasonable in all categories and did not recommend any changes in
rates currently in effect.
The Company received approvals in December 1997 from the APSC and the
Missouri Public Service Commission for rate increases and tariff changes for
Associated which allowed the utility to collect an additional $3.0 million
annually. Of the $3.0 million increase, approximately $2.0 million was in the
form of base rate increases and $1.0 million was related to the increased cost
of service of the Company's gathering plant which is recovered through either
the purchased gas adjustment clause or through direct charges to transportation
customers. Rate increase requests that may be filed in the future will depend on
customer growth, increases in operating expenses, and additional investments in
property, plant and equipment. AWG's rates for gas delivered to its retail
customers are not regulated by the Federal Energy Regulatory Commission (FERC),
but its transmission and gathering pipeline systems are subject to the FERC's
regulations concerning open access transportation since AWG accepted a blanket
transportation certificate in connection with its merger with Associated.
In May 1999, the Staff of the APSC initiated a proceeding in which it
sought an annual reduction of approximately $2.3 million in the rates AWG
charges its customers in northwest Arkansas. Staff's position was based on
various adjustments to the utility's rate base, operating expenses, capital
structure and rate of return. A large portion of the proposed reduction was
based on a downward adjustment to the utility's current return on equity
authorized by the APSC in 1996. During the third quarter of 1999, the Company
reached agreement with the Staff and the APSC to resolve this issue and to close
several other open dockets. In the settlement agreement, the Company agreed to
reduce its rates collected from customers on a prospective basis in the amount
of $1.4 million annually, effective December 1, 1999. The agreement also
includes the resolution of a proceeding initiated in December 1998 by the Staff
of the APSC where the Staff had recommended the disallowance of approximately
$3.1 million of gas supply costs. As a part of the settlement, this docket was
closed with no negative adjustment to the Company.
In February 2001, the APSC approved a 90-day temporary tariff to
collect additional gas costs not yet billed to customers through the normal
purchased gas adjustment clause in the utility's approved tariffs. The Company
had under-recovered purchased gas costs of $12.9 million in its current assets
at December 31, 2000. The amount of under-recovered purchased gas costs had
increased to over $30.0 million during January 2001 as a result of rapidly
increasing gas costs. The temporary tariff allows the Company to bill customers
an additional $3.00 per Mcf of usage and is expected to generate $14.0 to $15.0
million of additional cash flow over the next few months allowing the Company
faster recovery of gas costs already incurred.
MARKETING AND TRANSPORTATION
Gas Marketing
The marketing group was formed in mid-1996 to better enable the Company
to capture downstream opportunities which arise through marketing and
transportation activity. Through utilization of Southwestern's existing asset
base, the group's focus is to create and capture value beyond the wellhead. The
merger of the NOARK Pipeline with the Ozark Gas Transmission System discussed
below afforded greater supply and market opportunities.
14
The Company's marketing operations include the marketing of
Southwestern's own gas production and third-party natural gas. Operating income
for this segment was $2.5 million in 2000, compared to $2.1 million in 1999 and
$1.8 million in 1998. The segment marketed 59.6 Bcf of natural gas in 2000,
compared to 63.1 Bcf in 1999 and 49.6 Bcf in 1998. Of the total volumes
marketed, purchases from the Company's exploration and production subsidiaries
accounted for 33% in 2000, 31% in 1999 and 24% in 1998.
NOARK Partnership
At December 31, 2000, the Company held a 25% general partnership
interest in the NOARK Pipeline System, Limited Partnership (NOARK). NOARK
Pipeline was a 258-mile long intrastate natural gas transmission system that
originated in western Arkansas and terminated in northeast Arkansas, crossing
three major interstate pipelines and interconnecting with the Company's
distribution systems. NOARK Pipeline was completed and placed in service in 1992
and has been operating below capacity and generating losses since it was placed
in service. The Company's share of the pretax loss from operations related to
its NOARK investment was $1.8 million in 2000, $2.0 million in 1999 and $3.1
million in 1998.
In January 1998, the Company entered into an agreement with Enogex Inc.
(Enogex), a subsidiary of OGE Energy Corp., to expand NOARK Pipeline and provide
access to Oklahoma gas supplies through an integration of NOARK Pipeline with
the Ozark Gas Transmission System (Ozark). Ozark was a 437-mile interstate
pipeline system that began in eastern Oklahoma and terminated in eastern
Arkansas. On July 1, 1998, the Federal Energy Regulatory Commission (FERC)
authorized the operation and integration of Ozark and NOARK Pipeline as a
single, integrated pipeline. The FERC order also authorized the purchase of
Ozark by a subsidiary of Enogex and the construction of integration facilities.
Enogex acquired Ozark and contributed the pipeline system to the NOARK
partnership and also acquired the NOARK partnership interests not held by
Southwestern. Enogex funded the acquisition of Ozark and the expansion and
integration with NOARK Pipeline which resulted in the Company's interest in the
partnership decreasing to 25% with Enogex owning a 75% interest. There are also
provisions in the agreement with Enogex which allow for future revenue
allocations to the Company above its 25% partnership interest if certain minimum
throughput and revenue assumptions are not met.
The merged pipeline system now has greater access to major gas
producing fields in Oklahoma. With access to greater regional production,
Southwestern expects the pipeline's additional throughput to create new
marketing and transportation opportunities and reduce the losses experienced on
the project in the past. The merged pipeline also provides the Company's utility
systems with additional access to gas supply.
The new integrated system, known as Ozark Pipeline, became operational
November 1, 1998, and includes 749 miles of pipeline with a total throughput
capacity of 330 MMcfd. Deliveries are currently being made by the pipeline to
portions of AWG's distribution system, to Associated, and to the interstate
pipelines with which it interconnects. The average daily throughput for the
pipeline was 188.2 MMcfd in 2000, compared to 167.5 MMcfd in 1999. Before the
integration with Ozark, NOARK Pipeline had an average daily throughput of 27.3
MMcfd in 1998. At December 31, 2000, AWG had transportation contracts with Ozark
Pipeline for 66.9 MMcfd of firm capacity. These contracts expire in 2002 and
2003 and are renewable annually thereafter until terminated with 180 days'
notice.
Competition
The Company's gas marketing activities are in competition with numerous
other companies offering the same services, many of which possess larger
financial and other resources than those of Southwestern. Some of these
competitors are affiliates of companies with extensive pipeline systems that are
used for transportation from producers to end-users. Other factors affecting
competition are cost and availability of alternative fuels, level of consumer
demand, and cost of and
15
proximity of pipelines and other transportation facilities. The Company believes
that its ability to effectively compete within the marketing segment in the
future depends upon establishing and maintaining strong relationships with
producers and end-users.
NOARK Pipeline previously competed with two interstate pipelines, one
of which was the Ozark system, to obtain gas supplies for transportation to
other markets. Because of the available transportation capacity in the Arkansas
portion of the Arkoma Basin, competition had been strong and had resulted in
NOARK Pipeline transporting gas for third parties on an interruptible basis at
rates well below the maximum tariffs presently allowed. The integration with
Ozark provides increased supplies to transport to both local markets and markets
served by the three major interstate pipelines that Ozark Pipeline connects with
in eastern Arkansas. As discussed below under "Regulation," FERC's Order No. 636
has generally increased competition in the transportation segment as end-users
are now acquiring their own supplies and independently arranging for the
transportation of those supplies. The Company believes that Ozark Pipeline will
provide the additional supplies necessary to compete more effectively for the
transportation of natural gas to end-users and markets served by the interstate
pipelines.
Regulation
Since the mid-1980's, the FERC has issued a series of orders,
culminating in Order No. 636 in April 1992, that have altered the marketing and
transportation of natural gas. Order No. 636 required interstate natural gas
pipelines to "unbundle," or segregate, the sales, transportation, storage and
other components of their existing sales services, and to separately state the
rates for each of the unbundled services. Order No. 636 and subsequent FERC
orders issued in individual pipeline proceedings have been the subject of
appeals, the results of which have generally been supportive of the FERC's open
access policy. Generally, Order No. 636 has eliminated or substantially reduced
the interstate pipelines' role as wholesalers of natural gas and has
substantially increased competition in natural gas markets.
Prior to the integration with Ozark, the operations of NOARK Pipeline
were regulated by the APSC. The APSC had established a maximum transportation
rate of approximately $.285 per dekatherm. The integration of NOARK Pipeline
with Ozark resulted in an interstate pipeline system subject to FERC regulations
and FERC approved tariffs. The APSC no longer has jurisdiction over NOARK
Pipeline's transportation rates and services. The FERC initially set the maximum
transportation rate of Ozark Pipeline at $.2455 per dekatherm. As the result of
a rate case filed in 2000, Ozark Pipeline's maximum transportation rate
increased to $.2867 per dekatherm, effective November 1, 2000. Also as a result
of the rate case, Ozark Pipeline plans to begin offering no-notice service to
its customers in September 2001.
OTHER ITEMS
Environmental Matters
The Company's operations are subject to extensive federal, state and
local laws and regulations, including the Comprehensive Environmental Response,
Compensation and Liability Act, the Clean Water Act, the Clean Air Act and
similar state statutes. These laws and regulations require permits for drilling
wells and the maintenance of bonding requirements in order to drill or operate
wells and also regulate the spacing and location of wells, the method of
drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled, the plugging and abandoning of wells, the prevention
and cleanup of pollutants and other matters. Southwestern maintains insurance
against costs of clean-up operations, but is not fully insured against all such
risks.
Compliance with environmental laws and regulations has had no material
effect on Southwestern's capital expenditures, earnings, or competitive
position. Although future environmental obligations are not expected to have a
material impact on the results of operations or financial condition of the
Company, there can be no assurance that
16
future developments, such as increasingly stringent environmental laws or
enforcement thereof, will not cause the Company to incur material environmental
liabilities or costs.
Real Estate Development
A. W. Realty Company (AWR) owns an interest in approximately 150 acres
of real estate, most of which is undeveloped. AWR's real estate development
activities are concentrated on a 130-acre tract of land located in northwest
Arkansas, which is the seventh fastest growing metropolitan area in the United
States. The Company has owned an interest in this land for many years. The
property is zoned for commercial, office, and multi-family residential
development. AWR continues to review with a joint venture partner various
options for developing this property that would minimize the Company's initial
capital expenditures, but still enable it to retain an interest in any
appreciation in value. This activity, however, does not represent a significant
portion of the Company's business.
Employees
At December 31, 2000, the Company had 536 employees, 31 of whom are
represented under a collective bargaining agreement. The Company believes that
its relations with its employees are good.
ITEM 2. PROPERTIES
For additional information about the Company's gas and oil operations,
refer to Notes 5 and 6 to the financial statements in Item 8 ("Financial
Statement and Supplementary Data"). For information concerning capital
expenditures, refer to page 32 ("Capital Expenditures" section of Item 7,
"Management's Discussion and Analysis of Financial Condition and Results of
Operations"). Also refer to Item 6 ("Selected Financial Data") for information
concerning gas and oil produced.
The following table provides information concerning miles of pipe of
the Company's gas distribution systems. For a further description of Arkansas
Western's properties, see the discussion under Item 1 ("Business").
AWG Associated Total
------------------------------------
Gathering 386 - 386
Transmission 812 172 984
Distribution 3,172 520 3,692
--------------------------------------------------------------------------------
4,370 692 5,062
================================================================================
The following information is provided to supplement that presented in
Item 8. For a further description of Southwestern's oil and gas properties, see
the discussion under Item 1.
Leasehold Acreage
Undeveloped Developed
Gross Net Gross Net
----------------------------------------------
Arkoma 150,372 93,710 237,261 155,557
Mid-Continent 72,964 23,049 91,491 34,650
Texas/New Mexico 262,734 99,720 173,785 36,405
Louisiana 61,597 24,825 40,430 7,011
--------------------------------------------------------------------------------
547,667 241,304 542,967 233,623
================================================================================
17
Producing Wells
Gas Oil Total
Gross Net Gross Net Gross Net
----------------------------------------------------
Arkoma 808 401.4 - - 808 401.4
Mid-Continent 163 111.2 401 79.6 564 190.8
Texas/New Mexico 170 53.0 231 125.2 401 178.2
Louisiana 14 4.7 18 12.6 32 17.3
--------------------------------------------------------------------------------
1,155 570.3 650 217.4 1,805 787.7
================================================================================
Wells Drilled During the Year
Exploratory
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
---- --------------------------------------------------------------
2000 13.0 4.0 12.0 4.8 25.0 8.8
1999 4.0 1.5 4.0 1.6 8.0 3.1
1998 3.0 .5 10.0 3.9 13.0 4.4
Development
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
---- --------------------------------------------------------------
2000 65.0 21.9 14.0 6.3 79.0 28.2
1999 47.0 18.3 15.0 6.1 62.0 24.4
1998 72.0 29.4 10.0 6.4 82.0 35.8
Wells in Progress as of December 31, 2000
Gross Net
-------------------
Exploratory - -
Development 1.0 0.4
--------------------------------------------------------------------------------
Total 1.0 0.4
================================================================================
During 2000, Southwestern was required to file Form 23, "Annual Survey
of Domestic Oil and Gas Reserves" with the Department of Energy. The basis for
reporting reserves on Form 23 is not comparable to the reserve data included in
Note 6 to the financial statements in the 2000 Annual Report to Shareholders.
The primary differences are that Form 23 reports gross reserves, including the
royalty owners' share, and includes reserves for only those properties where the
Company is the operator.
ITEM 3. LEGAL PROCEEDINGS
In its Form 8-K filed July 2, 1996, the Company disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
This matter went to a non-jury trial as to liability on January 10, 2000. The
court in this matter issued Findings of Fact and Conclusions of Law that found
no fraud was committed. The court also found that any override royalty interests
that might ultimately be found to be due under the plaintiffs' claim for
additional override royalties accrued after
18
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 proceeding that is scheduled for April 30, 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 United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the Hales class action royalty litigation previously reported. The
Company was found to be ultimately liable and satisfied the Hales judgment in
July 2000. MMS was included in the class action litigation against its
objections, but did not pursue further action to remove itself from the class.
On August 25, 2000, a class action suit was filed against the Company
and its subsidiaries in Sebastian County, Arkansas, on behalf of all mineral
owners who own or owned a royalty and/or overriding royalty interest in oil and
gas leases or other agreements in certain sections of Franklin County, Arkansas.
The Company was granted authority in 1968 by the Arkansas Oil and Gas Commission
to operate a gas storage facility in one section of Franklin County. Based upon
subsequently developed geological data, the Company sought authority to expand
this area and was granted authority by the Arkansas Oil and Gas Commission to
operate gas storage in additional sections. Plaintiffs are challenging the
storage agreements that the Company obtained from the mineral interest owners in
1968, 1999 and 2000 to operate the gas storage facility known as "Stockton."
Plaintiffs allege various wrongful, intentional and fraudulent acts relating to
the operation of the storage pool beginning in 1968 and continuing to the
present and allege that the above-referenced agreements from the mineral owners
were obtained through misrepresentation and fraud. The Company has owned and
operated the Stockton storage unit through its Arkansas Western Gas Company
subsidiary until 1994, at which time it was transferred to its subsidiary,
SEECO, Inc. Plaintiffs claim ownership rights in the gas that the Company has
stored in the storage pool in an amount in excess of $5 million in actual
damages, interest, attorney's fees and punitive damages. The Company and its
outside counsel believe that this action is without merit and does not meet the
requirements for a class action. The Company believes that plaintiffs claim to
the storage gas, which the Company has injected into the storage facility, has
no merit and is not supported by the Arkansas gas storage statute under which
the Company operates this facility. While the amount of this claim could be
significant, management believes, based upon its investigation, that this claim
is without merit and that the Company's ultimate liability, if any, will not be
material to its consolidated financial position, but in any one period it could
be significant to its results of operations.
The Company is subject to laws and regulations relating to the
protection of the environment. The Company's policy is to accrue environmental
and cleanup related costs of a non-capital 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 2000, to a vote of security holders, through the solicitation
of proxies or otherwise.
19
Executive Officers of the Registrant
Years Served
Name Officer Position Age as Officer
--------------------------------------------------------------------------------
Harold M. Korell President and Chief Executive
Officer and Director 56 4
Greg D. Kerley Executive Vice President and
Chief Financial Officer 45 11
Richard F. Lane Senior Vice President,
Southwestern Energy Production
Company and SEECO, Inc. 43 3
George A. Taaffe Senior Vice President, General
Counsel and Secretary 54 2
Charles V. Stevens Senior Vice President,
Arkansas Western Gas Company 51 12
Mr. Korell was appointed to his present position in October 1998 and
assumed the position of Chief Executive Officer on January 1, 1999. He joined
the Company in 1997 as Executive Vice President and Chief Operating Officer.
From 1992 to 1997, he was employed by American Exploration Company where he was
most recently Senior Vice President - Operations. From 1990 to 1992, he was
Executive Vice President of McCormick Resources and from 1973 to 1989, he held
various positions with Tenneco Oil Company, including Vice President,
Production.
Mr. Kerley was appointed to his present position in December 1999.
Previously, he served as Senior Vice President and Chief Financial Officer from
1998 to 1999, Senior Vice President - Treasurer and Secretary from 1997 to 1998,
Vice President - Treasurer and Secretary from 1992 to 1997, and Controller from
1990 to 1992. Mr. Kerley also served as the Chief Accounting Officer from 1990
to 1998.
Mr. Lane was appointed to his present position in February 2001.
Previously, he served as Vice President - Exploration and he joined the Company
in February 1998 as Manager - Exploration. From 1993 to 1998, he was employed by
American Exploration Company where he was most recently Offshore Exploration
Manager. Previously, he held various managerial and geological positions at
FINA, Inc. and Tenneco Oil Company.
Mr. Taaffe joined the Company in his present position in July 1999.
Prior to joining the Company, he served as Vice President and Assistant General
Counsel for Consolidated Natural Gas Company from 1988 to 1999 and Assistant
General Counsel for Joy Technologies from 1973 to 1988.
Mr. Stevens has served the Company in his present position since
December 1997. Previously, he served as Vice President of Arkansas Western Gas
Company from 1988 to 1997.
All officers are elected at the Annual Meeting of the Board of
Directors for one-year terms or until their successors are duly elected. There
are no arrangements between any officer and any other person pursuant to which
he was selected as an officer. There is no family relationship between any of
the named executive officers or between any of them and the Company's directors.
20
Part II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is traded on the New York Stock Exchange
under the symbol "SWN." At December 31, 2000, the Company had 2,192 shareholders
of record. The following prices represent closing market transactions on the New
York Stock Exchange.
Range of Market Prices Cash Dividends Paid
Quarter Ended 2000 1999 2000 1999
------------- --------------------------------------------------------------
March 31 $7.44 $5.44 $8.50 $5.19 $.06 $.06
June 30 $10.38 $6.06 $10.56 $6.06 $.06 $.06
September 30 $10.00 $6.13 $11.00 $7.38 - $.06
December 31 $10.44 $7.25 $9.31 $5.63 - $.06
On June 22, 2000, the Arkansas Supreme Court affirmed a $109.3 million
judgment against the Company from a class action lawsuit brought by royalty
owners. As a result of the judgment, the Company also suspended its quarterly
dividend. Dividends totaling $3.0 million were paid during 2000. The Company
paid dividends at an annual rate of $.24 per share in 1999 and 1998.
21
ITEM 6. SELECTED FINANCIAL DATA
2000 1999 1998 1997 1996 1995
-------------------------------------------------------------------------------------------------------------------------
Financial Review (in thousands)
Operating revenues
Exploration and production $110,920 $75,039 $86,232 $100,129 $86,978 $63,285
Gas distribution 151,234 132,420 134,711 154,155 142,730 119,452
Gas marketing and other 208,196 137,942 97,795 83,511 30,636 31,622
Intersegment revenues (106,467) (65,005) (52,433) (61,606) (57,004) (47,534)
-------------------------------------------------------------------------------------------------------------------------
363,883 280,396 266,305 276,189 203,340 166,825
-------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 58,669 45,370 39,863 46,806 42,851 37,133
Gas purchases - marketing 133,221 92,851 73,235 63,054 14,114 13,714
Operating and general 59,790 57,957 61,915 59,167 50,509 44,436
Unusual items 111,288 - - - - -
Depreciation, depletion and
amortization 45,869 41,603 46,917 48,208 42,394 35,992
Write-down of oil and gas properties - - 66,383 - - -
Taxes, other than income taxes 8,515 6,557 6,943 7,018 5,476 4,362
-------------------------------------------------------------------------------------------------------------------------
417,352 244,338 295,256 224,253 155,344 135,637
-------------------------------------------------------------------------------------------------------------------------
Operating income (53,469) 36,058 (28,951) 51,936 47,996 31,188
Interest expense, net (23,230) (17,351) (17,186) (16,414) (13,044) (11,167)
Other income (expense) 1,997 (2,331) (3,956) (5,017) (4,015) (1,227)
-------------------------------------------------------------------------------------------------------------------------
Income before income taxes and
extraordinary item (74,702) 16,376 (50,093) 30,505 30,937 18,794
-------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current - 537 (6,029) (732) (5,569) (4,908)
Deferred (28,905) 5,912 (13,467) 12,522 17,320 12,167
-------------------------------------------------------------------------------------------------------------------------
(28,905) 6,449 (19,496) 11,790 11,751 7,259
-------------------------------------------------------------------------------------------------------------------------
Income (loss) before extraordinary item (45,797) 9,927 (30,597) 18,715 19,186 11,535
Extraordinary item (890) - - - - (295)
-------------------------------------------------------------------------------------------------------------------------
Net income (loss) $(46,687) $9,927 $(30,597) $18,715 $19,186 $11,240
=========================================================================================================================
Cash flow from operations, net of working
capital changes (in thousands) $(28,917)(1) $58,131 $93,708 $79,483 $71,830 $56,177
Return on equity n/a 5.21% n/a 8.45% 9.23% 5.78%
=========================================================================================================================
Common Stock Statistics
Basic earnings (loss) per share before
extraordinary item $(1.82) $.40 $(1.23) $.76 $.78 $.46
Basic and diluted earnings (loss) per share $(1.86) $.40 $(1.23) $.76 $.78 $.45
Cash dividends declared and paid per share $.12 $.24 $.24 $.24 $.24 $.24
Book value per share $5.61 $7.60 $7.45 $8.92 $8.41 $7.87
Market price at year-end $10.38 $6.56 $7.50 $12.88 $15.13 $12.75
Number of shareholders of record at year-end 2,192 2,268 2,333 2,379 2,572 2,759
Average shares outstanding 25,043,586 24,941,550 24,882,170 24,738,882 24,705,256 25,130,781
=========================================================================================================================
[FN]
(1) Cash flow from operations, net of working capital changes, for 2000 would
have been $82.4 million excluding the effects of unusual and extraordinary
items.
22
2000 1999 1998 1997 1996 1995
------------------------------------------------------------------------------------------------------------------
Capitalization (in thousands)
Total debt, including current portion $396,000 $302,200 $283,436 $299,543 $278,285 $210,828
Common shareholders' equity 141,291 190,356 185,856 221,565 207,941 194,504
------------------------------------------------------------------------------------------------------------------
Total capitalization $537,291 $492,556 $469,292 $521,108 $486,226 $405,332
------------------------------------------------------------------------------------------------------------------
Total assets $705,378 $671,446 $647,620 $710,866 $660,190 $569,093
------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt 73.70% 61.35% 60.27% 57.23% 56.96% 51.65%
Equity 26.30% 38.65% 39.73% 42.77% 43.04% 48.35%
==================================================================================================================
Capital Expenditures (in millions)
Exploration and production $69.2 $59.0 $52.4 $73.5 $110.3 $82.2
Gas distribution 6.0 7.1 10.1 12.6 12.8 18.5
Other .5 .9 1.9 2.7 1.8 .9
------------------------------------------------------------------------------------------------------------------
$75.7 $67.0 $64.4 $88.8 $124.9 $101.6
==================================================================================================================
Exploration and Production
Natural gas:
Production, Bcf 31.6 29.4 32.7 33.4 34.8 34.5
Average price per Mcf $2.88 $2.21 $2.34 $2.57 $2.26 $1.72
Oil:
Production, MBbls 676 578 703 749 391 229
Average price per barrel $22.99 $17.11 $13.60 $19.02 $21.21 $17.15
Total gas and oil production, Bcfe 35.7 32.9 36.9 37.9 37.1 35.9
Average production (lifting) cost per Mcf equivalent $.55 $.44 $.43 $.45 $.29 $.22
Proved reserves at year-end:
Natural gas, Bcf 331.8 307.5 303.7 291.4 297.5 294.9
Oil, MBbls 8,130 7,859 6,850 7,852 8,238 2,152
Total reserves, Bcf equivalent 380.6 354.7 344.8 338.5 346.9 307.8
==================================================================================================================
Gas Distribution (1)
Sales and transportation volumes, Bcf:
Residential 10.9 10.8 11.1 12.6 13.4 12.1
Commercial 7.6 7.6 7.6 8.4 8.8 7.6
Industrial 3.5 3.5 4.2 6.6 7.7 7.7
End-use transportation 8.3 9.6 8.8 6.6 5.5 5.2
------------------------------------------------------------------------------------------------------------------
30.3 31.5 31.7 34.2 35.4 32.6
Off-system transportation 3.1 4.8 1.1 2.8 3.6 9.8
------------------------------------------------------------------------------------------------------------------
33.4 36.3 32.8 37.0 39.0 42.4
------------------------------------------------------------------------------------------------------------------
Customers - year-end
Residential 119,024 158,606 156,384 154,864 151,880 147,267
Commercial 16,282 21,929 22,229 21,431 20,845 20,109
Industrial 228 290 303 311 326 340
------------------------------------------------------------------------------------------------------------------
135,534 180,825 178,916 176,606 173,051 167,716
------------------------------------------------------------------------------------------------------------------
Degree days 3,994 3,179 3,472 4,131 4,341 4,064
Percent of normal 100% 79% 87% 103% 108% 102%
==================================================================================================================
[FN]
(1) Gas distribution statistics include the operations of the Company's
Missouri properties through the sale date of May 31, 2000.
23
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the financial statements and the notes thereto included
in Item 8. of this report and with the discussion below on "Forward-Looking
Information." Certain reclassifications have been made to the prior years'
financial statements to conform with the 2000 presentation. These
reclassifications had no effect on previously reported net income.
RESULTS OF OPERATIONS
The Company reported a net loss of $46.7 million, or $1.86 per share,
for 2000, compared to net income of $9.9 million, or $.40 per share, for 1999
and a net loss of $30.6 million, or $1.23 per share, in 1998. The loss for 2000
includes one-time charges for unusual items, including a $109.3 million judgment
in the Hales lawsuit (see Note 1 to the financial statements for additional
discussion) and a $2.0 million accrual for on-going litigation, an extraordinary
loss on the early retirement of debt, and a $3.2 million gain from the sale of
the Company's Missouri utility properties. Exclusive of these one-time charges
and the gain on sale, net income for 2000 would have been $20.5 million, or $.82
per share. The loss for 1998 reflects the impact of an after-tax, non-cash
ceiling test write-down of the Company's oil and gas properties of $40.5
million, or $1.63 per share. Excluding the non-cash charge, the Company would
have recognized net income of $9.9 million, or $.40 per share in 1998.
Results for 2000, exclusive of the one-time charges and the gain on the
sale of the utility properties, reflect both increased oil and gas production
and higher oil and gas prices realized, offset by higher operating and general
expenses and higher depreciation, depletion and amortization expense. Results
for 1999 and 1998 were negatively impacted by lower wellhead prices for the
Company's oil and gas production and by unseasonably warm weather.
Exploration and Production
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.
2000 1999 1998
--------------------------------------
Revenues (in thousands) $110,920 $75,039 $86,232
Operating income (loss) (in thousands) $(70,584)(1) $16,451 $(47,273)(2)
Gas production (Bcf) 31.6 29.4 32.7
Oil production (MBbls) 676 578 703
Total production (Bcfe) 35.7 32.9 36.9
Average gas price per Mcf $2.88 $2.21 $2.34
Average oil price per Bbl $22.99 $17.11 $13.60
Operating expenses per Mcfe
Production expenses $0.40 $0.35 $0.34
Production taxes $0.15 $0.09 $0.09
General & administrative expenses $0.32 $0.30 $0.34
Full cost pool amortization $1.06 $1.00 $1.04
[FN]
(1) Includes a charge of $109.3 million for the Hales judgment and a charge of
$2.0 million related to on-going litigation. Excluding these unusual items,
operating income for the exploration and production segment would have been
$40.7 million for 2000.
(2) Includes a full cost pool ceiling test write-down of $66.4 million.
Excluding this non-cash write-down, operating income would have been $19.1
million for 1998.
24
Revenues and Operating Income
The Company's exploration and production revenues increased 48% in 2000
and decreased 13% in 1999. The increase in 2000 was due to an increase in
production and higher average prices received. The decrease in 1999 revenues was
due to lower volumes of oil and gas produced and a lower average gas price
received.
Operating income of the exploration and production segment was $40.7
million in 2000 excluding the impact of the Hales judgment and the other unusual
items, compared to $16.5 million in 1999, and $19.1 million in 1998 excluding
the impact of the non-cash write-down of oil and gas properties. The increase in
2000 was due to an 8% increase in equivalent oil and gas production and higher
oil and gas prices realized, partially offset by increased operating costs and
expenses. The decrease in 1999 was due primarily to an 11% decrease in
equivalent oil and gas production volumes.
Production
Gas and oil production totaled 35.7 billion cubic feet equivalent
(Bcfe) in 2000, 32.9 Bcfe in 1999 and 36.9 Bcfe in 1998. The increase in 2000
production volumes resulted from new wells added in 2000 and 1999 in the
Company's Permian Basin and south Louisiana operating areas, partially offset by
the loss of production from certain wells in the Company's Mid-Continent
operating area that were sold at auction during 2000. The decrease in 1999
production was due to the combined effects of production declines in the
Company's outside operated properties resulting from the industry slowdown that
began in 1998, production declines in some of the Company's Gulf Coast
properties, and the loss of production from marginal properties that were sold
in 1999.
Gas sales to unaffiliated purchasers were 23.8 Bcf in 2000, up from
21.2 Bcf in 1999 and 21.4 Bcf in 1998. Sales to unaffiliated purchasers are
primarily made under contracts which reflect current short-term prices and which
are subject to seasonal price swings.
Intersegment sales to Arkansas Western Gas Company (AWG), the utility
subsidiary which operates the Company's northwest Arkansas utility system, were
5.1 Bcf in both 2000 and 1999 and 7.7 Bcf in 1998. Although weather as measured
in degree days was normal in 2000 and colder than 1999, sales to AWG were flat
as record cold weather in the months of November and December caused the Company
to utilize its storage facilities in addition to gas production to meet
contractual commitments to AWG. Affiliated deliveries for 1999 were down as
unseasonably warm weather decreased AWG's demand for the Company's gas supply.
The Company's gas production provided approximately 36% of AWG's requirements in
2000, 38% in 1999 and 55% in 1998.
Prior to 1999, most of the sales to AWG's system were pursuant to an
intersegment long-term contract entered into in 1978 with SEECO, Inc. (SEECO).
In October 1998, AWG instituted a competitive bidding process for its gas supply
that included seven different packages. These bid requests included replacement
of the gas supply and no-notice service previously provided by the long-term gas
supply contract between AWG and SEECO. In the initial 1998 bid, SEECO, along
with the Company's marketing subsidiary, successfully bid on five of the seven
packages with prices based on the NorAm East Index plus a demand charge. Based
on normal weather patterns, the volumes of gas projected to be supplied under
these contracts would be approximately equal to the historical annual volumes
sold under the expired long-term contract. However, under the new contracts, the
Company supplied most of AWG's no-notice service and less of its routine base
requirements than it had under the previous contract. During periods of warmer
weather, as in early 2000 and in 1999 and 1998, lower total gas volumes will be
sold to AWG than compared to periods of normal or colder weather. The total
premium over the NorAm East Index under these contracts is estimated to be
approximately $1.0 million lower (after-tax) than the annual premium earned
under the expired long-term contract. The majority of the premium is received
through monthly demand charges which are received regardless of volumes actually
delivered. Other sales to AWG are made under long-term contracts with flexible
pricing provisions.
25
Of the five bid packages originally secured by the Company, three were
for a 3-year term, one was for a 2-year term and one was for a 1-year term. The
Company was unsuccessful in subsequent bidding for the 2-year and 1-year
packages and no longer makes affiliated sales under those contracts. There were
no demand fees associated with these two bid packages. In total, these two
packages provided approximately 2.5 Bcf annually of AWG's gas supply. Gas
volumes previously sold at market prices to AWG under these two packages are now
sold to unaffiliated parties. The three remaining packages will again be put out
to bid by AWG in 2001. The Company will bid to retain these gas supply packages
although there is no assurance that it will be successful. If successful, the
Company cannot predict the amount of premium that would be associated with the
new contracts.
The Company's intersegment sales to Associated Natural Gas Company
(Associated), a division of AWG which operates the Company's natural gas
distribution system in northeast Arkansas, were 2.7 Bcf in 2000, 3.1 Bcf in
1999, and 3.6 Bcf in 1998. Affiliated deliveries to Associated decreased in 2000
due to the sale of Associated's Missouri utility operations in May 2000.
Deliveries to Associated decreased in 1999 due primarily to corresponding
changes in heating weather. Effective October 1990, SEECO entered into a
ten-year contract with Associated to supply a portion of its system requirements
at a price to be redetermined annually. For the contract period beginning
October 1, 1997, the contract was revised to redetermine the sales price monthly
based on an index posting plus a reservation fee. Effective October 2000,
Associated placed its gas supply out for competitive bids. The Company was
successful in obtaining a one-year bid to supply approximately 1.0 Bcf of gas,
or approximately 40% of Associated's annual requirement assuming normal weather
patterns.
The Company expects future increases in its gas production to come
primarily from sales to unaffiliated purchasers. The Company is unable to
predict changes in the market demand and price for natural gas, including
changes which may be induced by the effects of weather on demand of both
affiliated and unaffiliated customers for the Company's production.
Additionally, the Company holds a large amount of undeveloped leasehold acreage
and producing acreage, and has an inventory of drilling leads, prospects and
seismic data that will continue to be evaluated and developed in the future. The
Company's exploration programs have been directed primarily toward natural gas
in recent years.
Commodity Prices
The overall average price realized for the Company's gas production was
$2.88 per Mcf in 2000, $2.21 per Mcf in 1999, and $2.34 per Mcf in 1998. The
changes in the average price realized primarily reflects changes in average
annual spot market prices and the effects of the Company's price hedging
activities. The Company's hedging activities lowered the average gas price $1.04
per Mcf in 2000 and $.06 per Mcf in 1999, and added $.19 per Mcf to the average
gas price in 1998. Additionally, the Company receives monthly demand charges
related to the no-notice service it makes available to the utility segment which
increases the Company's average gas price received.
The Company realized an average price of $22.99 per barrel for its oil
production for the year ended December 31, 2000, up from $17.11 per barrel for
1999 and $13.60 per barrel for 1998.
The Company periodically enters into hedging activities with respect to
a portion of its projected crude oil and natural gas production through a
variety of financial arrangements intended to support oil and gas prices at
targeted levels and to minimize the impact of price fluctuations (see Note 8 of
the financial statements for additional discussion). The Company's policies
prohibit speculation with derivatives and limit swap agreements to
counterparties with appropriate credit standings. At December 31, 2000, the
Company had hedges in place on 34.7 Bcf of future gas production and 697,000
barrels of future oil production. Subsequent to December 31, 2000, the Company
closed its position on 298,000 barrels with a floor price of $18.00. The Company
currently has hedged approximately 80% of its 2001 anticipated gas production
levels and 50% of its projected oil production.
26
Disregarding the impact of hedges, the Company expects the average
price it receives for its total gas production to be slightly higher than
average spot market prices due to the prices it receives under the contracts
covering its intersegment sales which provide swing services to the Company's
utility systems. Future changes in revenues from sales of the Company's gas
production will be dependent upon changes in the market price for gas, access to
new markets, maintenance of existing markets, and additions of new gas reserves.
Operating Costs and Expenses
Production expenses per Mcfe for this segment were $.40 in 2000,
compared to $.35 in 1999 and $.34 in 1998. Production taxes per Mcfe were $.15
in 2000 compared to $.09 in both 1999 and 1998. The increase in production
expenses per Mcfe in 2000 was due primarily to an increase in workover expenses.
The increase in 2000 production taxes per Mcfe was due to increased severance
and ad valorem taxes that resulted from higher commodity prices. General and
administrative expense per Mcfe was $.32 in 2000, compared to $.30 in 1999 and
$.34 in 1998. The increase in general and administrative costs in 2000 as
compared to 1999 resulted from increases in incentive compensation pay that is
dependent upon the operating results for this segment. The decrease in 1999
general and administrative costs as compared to 1998 resulted from severance
costs and other costs related to the closing of the Company's Oklahoma City
office in 1998.
The Company's full cost pool amortization rate averaged $1.06 per Mcfe
for 2000, compared to $1.00 per Mcfe in 1999 and $1.04 per Mcfe in 1998. The
average rate increased in 2000 due primarily to a $9.9 million decline in the
balance of unevaluated costs excluded from amortization in the full cost pool.
The rate decreased in 1999 as compared to 1998 due to the full cost ceiling
write-down taken in 1998.
The Company utilizes the full cost method of accounting for costs
related to its oil and natural gas properties. Under this method, all such costs
(productive and nonproductive) are capitalized and amortized on an aggregate
basis over the estimated lives of the properties using the units-of-production
method. These capitalized costs are subject to a ceiling test, however, which
limits such pooled costs to the aggregate of the present value of future net
revenues attributable to proved gas and oil reserves discounted at 10 percent
(standardized measure) plus the lower of cost or market value of unproved
properties. At December 31, 2000, 1999 and 1998 the Company's unamortized costs
of oil and gas properties did not exceed this ceiling amount. Primarily due to
high oil and gas prices in effect at year-end, the Company's standardized
measure increased to $895.1 million at December 31, 2000, compared to $262.1
million at December 31, 1999 and $222.8 million at December 31, 1998. Market
prices for natural gas have declined since December 31, 2000, although they are
still considerably higher than prices in effect at year-end 1999 and 1998. As a
comparative measure only, the Company's standardized measure at December 31,
2000, assuming a NYMEX index price of $4.50 per Mcf and a WTI index price of
$25.00 per barrel, would have been approximately $487.0 million. A decline in
oil and gas prices from year-end 2000 levels or other factors, without other
mitigating circumstances, could cause a future write-down of capitalized costs
and a noncash charge against future earnings.
Inflation impacts the Company by generally increasing its operating
costs and the costs of its capital additions. The effects of inflation on the
Company's operations in recent years have been minimal due to low inflation
rates. However, during 2000 the impact of inflation intensified in certain areas
of the Company's exploration and production segment as shortages in drilling
rigs, third party services and qualified labor developed due to an overall
increase in the activity level of the domestic oil and gas industry. This impact
is continuing into 2001 with the significant increases in oil and gas prices
experienced during the past several months. Increased competition in south
Louisiana has also had the impact of increasing 3-D seismic and land costs in
the area.
27
Gas Distribution
The operating results of the Company's gas distribution segment are
highly seasonal. 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 (APSC). 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.
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 $3.2 million and proceeds from the sale were used to pay down
debt. As a result of the adverse Hales judgment, the Company's Board of
Directors authorized management to pursue the sale of the Company's remaining
gas distribution operations. The sale process did not result in an acceptable
bid. Although the Company may sell its gas distribution segment in the future,
it currently plans to operate these assets as a continuing part of its business.
2000 1999 1998
-------------------------------------------
($ in thousands, except for Mcf amounts)
Revenues $151,234 $132,420 $134,711
Gas purchases $93,992 $68,876 $70,972
Operating costs and expenses $42,587 $46,357 $47,710
Operating income $14,655 $17,187 $16,029
Deliveries (Bcf)
Sales and end-use transportation 30.4 31.6 31.7
Off-system transportation 3.1 4.8 1.1
Average number of customers 152,773 177,328 174,693
Average sales rate per Mcf $6.55 $5.67 $5.57
Heating weather - degree days 3,994 3,179 3,472
Percent of normal 100% 79% 87%
Note: Amounts and statistics for 2000, 1999 and 1998 include the operations of
the Company's Missouri properties through the sale date of May 31, 2000.
Revenues and Operating Income
Gas distribution revenues fluctuate due to the pass-through of gas
supply cost changes and due to 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.
Gas distribution revenues increased 14% in 2000 and decreased 2% in
1999. The increase in 2000 was due to a higher sales rate and increased sales
volumes caused by colder weather, partially offset by the loss of revenues
resulting from the sale of the utility's Missouri assets. The decrease in 1999
was due to the effects of warmer weather. Weather in 2000 was normal and 26%
colder than the prior year. Weather in 1999 was 21% warmer than normal and 8%
warmer than the prior year.
Operating income for Southwestern's utility systems decreased 15% in
2000 and increased 7% in 1999. The decrease in 2000 resulted from the sale of
the Missouri assets and a $1.4 million annual rate reduction that was
implemented in December 1999. The increase in 1999 was due to the Company's
efforts in reducing operating costs and to customer growth.
28
Deliveries and Rates
In 2000, AWG sold 16.8 Bcf to its customers at an average rate of $6.45
per Mcf, compared to 14.5 Bcf at $5.47 per Mcf in 1999 and 15.1 Bcf at $5.37 per
Mcf in 1998. Additionally, AWG transported 6.3 Bcf in 2000, 6.2 Bcf in 1999, and
6.0 Bcf in 1998 for its end-use customers. Associated sold 5.3 Bcf to its
customers in 2000 at an average rate of $6.89 per Mcf, compared to 7.4 Bcf in
1999 at $6.06 per Mcf and 7.8 Bcf at $5.95 per Mcf in 1998. Associated
transported 2.0 Bcf for its end-use customers in 2000, compared to 3.4 Bcf in
1999 and 2.8 Bcf in 1998. The decrease in the combined volumes sold and
transported for end-use customers in 2000 resulted from the sale of the Missouri
properties, offset by increased deliveries due to colder weather, and decreased
in 1999 due to warmer weather, partially offset by customer growth. The
fluctuations in the average sales rates reflect changes in the average cost of
gas purchased for delivery to the Company's customers, which are passed through
to customers under automatic adjustment clauses.
Total deliveries to industrial customers of AWG and Associated,
including transportation volumes, were 11.8 Bcf in 2000, 13.1 Bcf in 1999 and
13.0 Bcf in 1998. The decline in deliveries in 2000 resulted from the sale of
the Missouri assets. AWG also transported 3.1 Bcf of gas through its gathering
system in 2000 for off-system deliveries, all to the Ozark Gas Transmission
System, compared to 4.8 Bcf in 1999 and 1.1 Bcf in 1998. The level of off-system
deliveries each year generally reflects the changes of on-system demands of the
Company's gas distribution systems for the Company's gas production. The average
off-system transportation rate was approximately $.10 per Mcf, exclusive of
fuel, in 2000 and 1999, and $.11 per Mcf in 1998.
Gas distribution revenues in future years will be impacted by the
utility's gas purchase costs, the sale of the Company's Missouri assets,
customer growth and rate increases allowed by the APSC. In recent years, AWG has
experienced customer growth of approximately 2% to 3% annually, while Associated
has experienced customer growth of approximately 1% or less annually. Based on
current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue.
In February 2001, the APSC approved a 90-day temporary tariff to
collect additional gas costs not yet billed to customers through the utility's
normal purchased gas adjustment clause in its approved tariffs. The Company had
under-recovered purchased gas costs of $12.9 million in current assets at
December 31, 2000. The level of deferred purchases had increased to over $30.0
million during January 2001 as a result of rapidly increasing gas costs. The
temporary tariff allows the utility to bill customers an additional $3.00 per
Mcf of usage and is expected to generate $14.0 to $15.0 million of additional
cash flow during the next few months allowing the Company faster recovery of gas
costs already incurred.
Tariffs implemented in Arkansas as a result of rate increases in both
1996 and 1997 contain a weather normalization clause to lessen the impact of
revenue increases and decreases which might result from weather variations
during the winter heating season. Rate increase requests, which may be filed in
the future, will depend on customer growth, increases in operating expenses, and
additional investment in property, plant and equipment. See "Regulatory Matters"
below for additional discussion related to the Company's gas distribution
segment.
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 Missouri assets as
discussed above. Other operating costs and expenses of the gas distribution
segment for 2000 were lower than 1999 and 1998 due primarily to the sale of the
utility's Missouri assets.
Going forward, Southwestern's comparative operating results for its gas
distribution segment will be lower reflecting the Missouri asset divestiture.
However, the Company does not expect the sale to materially impact consolidated
earnings, as the loss in operating income should generally be offset by a
corresponding decrease in corporate interest expense.
29
Inflation impacts the Company's gas distribution segment by generally
increasing its operating costs and the costs of its capital additions. The
effects of inflation on the utility's operations in recent years have been
minimal due to low inflation rates. Additionally, delays inherent in the
rate-making process prevent the Company from obtaining immediate recovery of
increased operating costs of its gas distribution segment.
Regulatory Matters
In May 1999, the Staff of the APSC initiated a proceeding in which it
sought an annual reduction of approximately $2.3 million in the rates AWG
charges it customers in northwest Arkansas. The Staff's position was based on
various adjustments to the utility's rate base, operating expenses, capital
structure and rate of return. A large portion of the proposed reduction was
based on a downward adjustment to the utility's return on equity authorized by
the APSC in 1996. During the third quarter of 1999, the Company reached
agreement with the Staff and the APSC to resolve this issue and to close several
other dockets that had remained open. In the settlement agreement, the Company
agreed to reduce its rates collected from customers on a prospective basis in
the amount of $1.4 million annually, effective December 1, 1999. The agreement
also includes the resolution of a proceeding initiated in December 1998 by the
Staff of the APSC and that was previously disclosed by the Company where the
Staff had recommended the disallowance of approximately $3.1 million of gas
supply costs. As part of the settlement, this docket was closed with no negative
adjustment to the Company.
The Company received approvals in December 1997 from the APSC and the
Missouri Public Service Commission (MPSC) for rate increases and tariff changes
which allow the utility to collect an additional $3.0 million annually. Of the
$3.0 million total, approximately $2.0 million is in the form of base rate
increases and $1.0 million is related to the increased cost of service of the
Company's gathering plant which is recovered through either the purchased gas
adjustment clause or through direct charges to transportation customers.
In its order approving the Missouri changes, the MPSC further ordered
Associated to modify its purchased gas adjustment tariff to remove any specific
language referencing recovery of the cost of service of its gathering
facilities. The MPSC order provided that Associated should base gathering
charges to its customers on competitive market conditions and that it would be
allowed recovery from its sales and transportation customers of all prudently
incurred gathering costs without reference to its cost of service. The MPSC
reviews these gathering costs annually as part of its review of Associated's gas
costs. Associated believes that the MPSC lacks statutory authority to approve
charges which are not based on historical cost of service. Associated appealed
this issue to the circuit court which ruled in favor of the MPSC. The Company
appealed the lower court's decision to the Missouri Court of Appeals which
requested that the MPSC reissue its order making clear the basis for its
decision. The Company continued to bill its ratepayers gas gathering costs based
on its cost of service through the date of the sale of its Missouri assets.
Gathering costs have been recovered in this manner from Missouri customers since
Associated's 1990 rate case. Prior to the 1997 changes, Associated's gathering
costs were recovered from Arkansas customers through its base rates.
A December 1996 rate increase order issued by the APSC also provided
that AWG cause to be filed with the APSC an independent study of its procedures
for allocating costs between regulated and non-regulated operations, its
staffing levels and executive compensation. The independent study was ordered by
the APSC to address issues raised by the Office of the Attorney General of the
State of Arkansas. The study was conducted in 1999 with a final report issued in
December 1999. The report found the Company's costs to be reasonable in all
categories and did not recommend any changes to the rates currently in effect.
The Company is subject to continuing reviews of it gas supply costs by
the APSC. The MPSC is currently auditing the last year of Associated's gas costs
in Missouri. The Company currently has open issues with the MPSC, however, the
Company believes that none of these issues will have a material adverse effect
on the Company's financial condition or results of operations.
30
AWG also purchases gas from unaffiliated producers under take-or-pay
contracts. The Company believes that it does not have a significant exposure to
liabilities resulting from these contracts and expects to be able to continue to
satisfactorily manage its exposure to take-or-pay liabilities.
Marketing and Other
Marketing
2000 1999 1998
-----------------------------------------
Revenues (in thousands) $207.7 $137.5 $97.2
Operating income (in thousands) $2.5 $2.1 $1.8
Gas volumes marketed (Bcf) 59.6 63.1 49.6
Operating income for the marketing segment was $2.5 million on revenues
of $207.7 million in 2000, compared to $2.1 million on revenues of $137.5
million in 1999, and $1.8 million on revenues of $97.2 million in 1998. The
Company marketed 59.6 Bcf in 2000, compared to 63.1 Bcf in 1999 and 49.6 Bcf in
1998. The Company enters into hedging activities with respect to its gas
marketing activities to provide margin protection (see Note 8 of the financial
statements for additional discussion).
NOARK Partnership
The marketing segment also manages the Company's 25% interest in the
NOARK Pipeline System, Limited Partnership (NOARK). The NOARK Pipeline was a
258-mile long intrastate gas transmission system that extended across northern
Arkansas, crossing three major interstate pipelines and interconnecting with the
Company's distribution systems. The NOARK Pipeline had been operating below
capacity and generating losses since it was placed in service in September 1992.
The Company's share of the pretax loss from operations included in other income
related to its NOARK investment was $1.8 million in 2000, $2.0 million in 1999,
and $3.1 million in 1998. The improvements in the 2000 and 1999 results
primarily reflect the benefits of the integration of the NOARK Pipeline System
with the Ozark Gas Transmission System (Ozark). The integration of the two
systems was completed in November, 1998.
In January 1998, the Company entered into an agreement with Enogex Inc.
(Enogex), a subsidiary of OGE Energy Corp., to expand the NOARK system and
provide access to Oklahoma gas supplies through an integration of NOARK with
Ozark. Ozark was a 437-mile interstate pipeline system which began in eastern
Oklahoma and terminated in eastern Arkansas. Effective August 1, 1998, Enogex
acquired Ozark and contributed the pipeline system to the NOARK partnership.
Enogex also acquired the NOARK partnership interests not held by Southwestern.
Enogex funded the acquisition of Ozark and the expansion and integration with
NOARK, which resulted in the Company's interest in the partnership decreasing to
25% with Enogex owning a 75% interest. There are also provisions in the
agreement with Enogex which allow for future revenue allocations to the Company
above its 25% partnership interest if certain minimum throughput and revenue
assumptions are not met. As a result of the changes discussed above, the Company
believes that it will be able to continue to reduce the losses it has
experienced on the NOARK project and expects its investment in NOARK to be
realized over the life of the system (see Note 7 of the financial statements for
additional discussion).
Ozark Pipeline, the new integrated system became operational November
1, 1998, and includes 749 miles of pipeline with a total throughput capacity of
330 MMcfd. Deliveries are currently being made by the integrated pipeline to
portions of AWG's distribution system, to Associated, and to the interstate
pipelines with which it interconnects. Ozark Pipeline had an average daily
throughput of 188 million cubic feet of gas per day (MMcfd) in 2000 and 168
MMcfd in 1999. In 1998, NOARK had an average daily throughput of 27.3 MMcfd
before the integration with Ozark. As a result of a rate case filed in 2000,
Ozark Pipeline's maximum transportation rate increased from $.2455 per dekatherm
to $.2867 per dekatherm effective November 1, 2000. At December 31, 2000, the
Company's gas distribution subsidiary has transportation contracts with Ozark
Pipeline for 66.9 MMcfd of firm capacity. These contracts expire in 2002 and
2003 and are renewable annually thereafter until terminated with 180 days'
notice.
31
As further explained in Note 11 of the financial statements, the
Company has severally guaranteed 60% of NOARK's currently outstanding debt. This
debt financed a portion of the original cost to construct the NOARK Pipeline.
Other Income, Costs and Expenses
Interest costs, net of capitalization, were up 34% in 2000 and 1% in
1999, both as compared to prior years. The increase in 2000 was caused primarily
by higher average borrowings that resulted from payment of the Hales judgment
and to the current lower level of capitalized interest related to the Company's
oil and gas properties. Interest capitalized decreased 26% in 2000 and 15% in
1999. The changes in capitalized interest are due primarily to decreases in the
level of costs excluded from amortization in the exploration and production
segment.
The increase in other income in 2000 resulted from the $3.2 million
gain on the sale of the Company's Missouri gas distribution assets and gains
from the sale of other miscellaneous assets. The changes in other income in 1999
and 1998 relate primarily to changes in the Company's share of operating losses
incurred by NOARK, as discussed above. Additionally, in 1999 and 1998 the
Company incurred certain costs related to a judgment bond that the Company was
required to post after receiving the initial adverse verdict in the Hales case.
The Hales judgment was the primary cause for the Company's deferred tax
benefit of $28.9 million in 2000. In 1998, the write-down of the Company's oil
and gas properties resulted in a deferred tax benefit of $25.9 million.
Excluding the impacts of these changes in deferred income taxes, the changes in
the provisions for current and deferred income taxes recorded each year result
primarily from the level of taxable income, the collection of under-recovered
purchased gas costs, abandoned property costs, and the deduction of intangible
drilling costs in the year incurred for tax purposes, netted against the
turnaround of intangible drilling costs deducted for tax purposes in prior
years. Intangible drilling costs are capitalized and amortized over future years
for financial reporting purposes under the full cost method of accounting.
LIQUIDITY AND CAPITAL RESOURCES
The Company depends on internally generated funds and its revolving
line of credit discussed under Financing Requirements as its major sources of
liquidity. Due to the Hales judgment and the impact of high year-end gas prices
on working capital, net cash used in operating activities was $53.2 million in
2000, compared to cash provided by operating activities of $58.1 million in 1999
and $93.7 million in 1998. The primary components of cash generated from
operations are net income, depreciation, depletion and amortization, write-down
of oil and gas properties, the provision for deferred income taxes and changes
in current assets and current liabilities. Net cash from operating activities
provided 89% of the Company's capital requirements for routine capital
expenditures, cash dividends, and scheduled debt retirements in 1999 and 125% in
1998.
Capital Expenditures
Capital expenditures totaled $75.7 million in 2000, $67.0 million in
1999, and $64.4 million in 1998. The Company's exploration and production
segment expenditures included acquisitions of oil and gas producing properties
totaling $6.7 million in 2000 and $9.4 million in 1999. The Company made no
producing property acquisitions in 1998.
2000 1999 1998
------------------------------------------
(in thousands)
Capital Expenditures
Exploration and production $69,211 $59,004 $52,376
Gas distribution 5,994 7,124 10,108
Other 512 839 1,875
--------------------------------------------------------------------------------
$75,717 $66,967 $64,359
================================================================================
32
Capital investments planned for 2001 total $81.6 million, consisting of
$75.0 million for exploration and production, $6.1 million for gas distribution
system expenditures and $.5 million for general purposes. The Company expects
that its level of capital investments will be adequate to allow the Company to
maintain its present markets, explore and develop its existing gas and oil
properties as well as generate new drilling prospects, and finance improvements
necessary due to normal customer growth in its gas distribution segment.
Financing Requirements
At year-end 2000, Southwestern's total debt was $396.0 million,
including $171.0 million under a short-term credit facility. This compares to
year-end 1999 total debt of $302.2 million, including $7.5 million classified as
short-term debt. 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 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 and was 7.85% at December 31, 2000. The new
credit facility has a term of 364 days and expires in July 2001. The Company
intends to renew or replace this facility prior to its expiration.
In August 2000, the Company retired $22.0 million of 9.36% private
placement notes. Certain costs of the redemption were expensed and are
classified as an extraordinary loss, net of related income tax effects.
In 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes
due 2027 and $40.0 million of 7.21% Medium-Term Notes due 2017. These notes were
issued under a supplement to the Company's $250.0 million shelf registration
statement filed with the Securities and Exchange Commission in February 1997,
for the issuance of up to $125.0 million of Medium-Term Notes. The Company has
$25.0 million of capacity remaining under the shelf registration statement. The
Company also has $125.0 million of 6.7% Notes due in 2005 that were issued under
the shelf registration. The Company's public notes are rated BBB by Standard and
Poor's and Baa3 by Moody's.
In connection with the Enogex transaction in 1998 discussed above under
"NOARK Partnership," the Company and a previous general partner converted
certain of their loans to the NOARK partnership, plus accrued interest, into
equity, and contributed approximately $10.7 million to the partnership to fund
costs incurred in connection with the prepayment of NOARK's 9.74% Senior Secured
notes. The Company's share of the contribution was $6.5 million. In June 1998,
the NOARK partnership issued $80.0 million of 7.15% Notes due 2018. The notes
require semi-annual principal payments of $1.0 million that began in December
1998. 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%. The Company advanced $3.3 million to
NOARK to fund its share of debt service payments in 2000 and advanced $2.3
million in 1999. If NOARK is unable to generate sufficient cash in the future to
service its debt and the Company is required to continue contributing cash to
fund its debt guarantee, the Company may be required to record the NOARK debt
commitment under current accounting rules.
Under its short-term credit agreement the Company may not issue total
debt in excess of 80% of its total capital, shareholders' equity may not be less
than $120.0 million (excluding any adjustments for SFAS No. 133 after its
adoption) and the Company may not declare or pay any dividends on its common
stock. The Company must also have a ratio of earnings before interest, taxes,
depreciation and amortization (EBITDA) to fixed charges of at least 2.5 or
higher for the previous 12 months. For 2000, this calculation excludes the
impact of the Hales judgment. At the end of 2000, the Company's capital
structure consisted of 73.7% debt (including short-term debt but excluding the
Company's several guarantee of NOARK's obligations) and 26.3% equity, with a
ratio of EBITDA to fixed charges of 4.1. Over the long term, the Company will
continue to consider the sale of its remaining gas distribution assets to pay
down existing debt.
33
In the short term, funds provided by operating activities are expected to
increase significantly due to higher gas and oil prices currently being received
for the Company's production. As part of its strategy to reduce its debt level,
the Company has hedged approximately 80% of its expected 2001 gas production and
50% of its expected 2001 oil production to insure it receives attractive prices.
Under these assumptions and assuming no other unanticipated uses of cash arise
during the year, the Company expects to reduce its debt level by $50 million to
$70 million during 2001.
Working Capital
The Company maintains access to funds which may be needed to meet
seasonal requirements through its credit facility explained above. The Company
had net negative working capital of $127.0 million at the end of 2000 due to the
short-term revolving credit facility balance of $171.0 million, compared to
positive working capital of $13.9 million at the end of 1999. Current assets
increased by 61% to $112.9 million in 2000, while current liabilities (without
consideration of short-term debt) increased 41%. The increases in current assets
and current liabilities at December 31, 2000, was due primarily to increases in
accounts receivable, accounts payable and under-recovered purchased gas costs
that resulted from extremely high market prices for natural gas at year end.
FORWARD-LOOKING INFORMATION
All statements, other than historical financial information, included
in this discussion and analysis of financial condition and results of operations
may be deemed to be forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933, as amended, and Section 21E of the Securities
Exchange Act of 1934, as amended. Although the Company believes the expectations
expressed in such forward-looking statements are based on reasonable
assumptions, such statements are not guarantees of future performance and actual
results or developments may differ materially from those in the forward-looking
statements. Important factors that could cause actual results to differ
materially from those in the forward-looking statements herein include, but are
not limited to, the timing and extent of changes in commodity prices for gas and
oil, the effects of commodity hedges and the volatility in earnings caused by
new hedge accounting standards, the timing and extent of the Company's success
in discovering, developing, producing, and estimating reserves, the effects of
weather and regulation on the Company's gas distribution segment, the value that
the Company's gas distribution segment may bring in exploring sales
opportunities for this segment and the timing of any proposed sale, increased
competition, legal and economic factors, governmental regulation, 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.
ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
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
7% of accounts receivable. See the discussion of credit risk associated with
commodities trading below.
34
Interest Rate Risk
The following table provides information on the Company's financial
instruments that are sensitive to changes in interest rates. The table presents
the Company's debt obligations, principal cash flows and related
weighted-average interest rates by expected maturity dates. Variable average
interest rates reflect the rates in effect at December 31, 2000 for borrowings
under the Company's credit facility. 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 December 31, 2000.
Expected Maturity Date Fair Value
-------------------------------------------------------------------- ----------
2001 2002 2003 2004 2005 Thereafter Total 12/31/00
-------------------------------------------------------------------- ----------
($ in millions)
Fixed Rate - - - - $125.0 $100.0 $225.0 $226.3
Average Interest Rate - - - - 6.70% 7.46% 7.04%
Variable Rate $171.0 - - - - - $171.0 $171.0
Average Interest Rate 7.83% - - - - - 7.83%
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 markets. 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.
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) or MBbls (thousand
barrels), the weighted average contract prices, and the total dollar contract
amount by expected maturity dates. The "Carrying Amount" for the contract
amounts are calculated as the contractual payments for the quantity of gas or
oil to be exchanged under futures contracts and do not represent amounts
recorded in the Company's financial statements. The "Fair Value" represents
values for the same contracts using comparable market prices at December 31,
2000. At December 31, 2000, the "Carrying Amount" of these financial instruments
exceeded the "Fair Value" by $60.6 million.
35
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) 1.9 1.0 .2
Weighted average price per Mcf $3.42 $2.65 $2.75
Contract amount (in millions) $6.4 $1.4 $2.6 $.8 $.6 $.3
Swaps with a fixed-price payment
Contract volume (Bcf) .4 - -
Weighted average price per Mcf $4.83 - -
Contract amount (in millions) $1.8 $2.8 - - - -
Price collars
Contract volume (Bcf) 25.2 6.0 -
Weighted average floor price per Mcf $3.66 $4.0 -
Contract amount of floor (in millions) $92.3 $96.0 $24.0 $27.1 - -
Weighted average ceiling price per Mcf $4.52 $4.72 -
Contract amount of ceiling (in millions) $113.9 $56.3 $28.3 $24.1 - -
Oil
Swaps with a fixed-price receipt
Contract volume (MBbls) 72 - -
Weighted average price per Bbl $17.49 - -
Contract amount (in millions) $1.3 $.8 - - - -
Price floor
Contract volume (MBbls) 325(1) - -
Weighted average price per Bbl $18.00 - -
Contract amount (in millions) $5.9 $6.0 - - - -
Price collar
Contract volume (MBbls) 300 - -
Weighted average floor price per Bbl $27.40 - -
Contract amount of floor (in millions) $8.2 $9.4 - - - -
Weighted average ceiling price per Bbl $29.95 - -
Contract amount of ceiling (in millions) $9.0 $8.7 - - - -
[FN]
(1) Subsequent to December 31, 2000, the Company closed its position relating to
the $18.00 per barrel floor on a notional amount of 298 MBbls covering eleven
months of 2001 production.
36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Reports of Management and Independent Public Accountants 38
Consolidated Statements of Operations for the years ended
December 31, 2000, 1999, and 1998 39
Consolidated Balance Sheets as of December 31, 2000 and 1999 40
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999, and 1998 41
Consolidated Statements of Retained Earnings for the years ended
December 31, 2000, 1999, and 1998 41
Notes to Consolidated Financial Statements,
December 31, 2000, 1999, and 1998 42
37
Report of Management
Management is responsible for the preparation and integrity of the
Company's financial statements. The financial statements have been prepared in
accordance with accounting principles generally accepted in the United States
consistently applied, and necessarily include some amounts that are based on
management's best estimates and judgment.
The Company maintains a system of internal accounting and
administrative controls that management believes provide reasonable assurance
that assets are safeguarded and that transactions are properly recorded and
executed in accordance with management's authorization. The Company's financial
statements have been audited by its independent public accountants, Arthur
Andersen LLP. In accordance with auditing standards generally accepted in the
United States, the independent auditors obtained a sufficient understanding of
the Company's internal controls to plan their audit and determine the nature,
timing, and extent of other tests to be performed.
The Audit Committee of the Board of Directors, composed solely of
outside directors, meets with management and Arthur Andersen LLP to review
planned audit scopes and results and to discuss other matters affecting internal
accounting controls and financial reporting. The independent auditors have
direct access to the Audit Committee and periodically meet with it without
management representatives present.
Report of Independent Public Accountants
To the Board of Directors and Shareholders of Southwestern Energy Company:
We have audited the consolidated balance sheets of SOUTHWESTERN ENERGY
COMPANY (an Arkansas corporation) AND SUBSIDIARIES as of December 31, 2000 and
1999, and the related consolidated statements of operations, retained earnings,
and cash flows for each of the three years in the period ended December 31,
2000. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Southwestern Energy
Company and Subsidiaries as of December 31, 2000 and 1999, and the results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2000, in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 5, 2001
38
Statements of Operations
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 2000 1999 1998
--------------------------------------------------------------------------------
(in thousands, except share
and per share amounts)
Operating Revenues
Gas sales $200,269 $165,898 $172,790
Gas marketing 137,234 96,570 76,367
Oil sales 15,537 9,891 9,557
Gas transportation and other 10,843 8,037 7,591
--------------------------------------------------------------------------------
363,883 280,396 266,305
--------------------------------------------------------------------------------
Operating Costs and Expenses
Gas purchases - utility 58,669 45,370 39,863
Gas purchases - marketing 133,221 92,851 73,235
Operating expenses 34,808 33,783 34,400
General and administrative expenses 24,982 24,174 27,515
Unusual items 111,288 - -
Depreciation, depletion and amortization 45,869 41,603 46,917
Write-down of oil and gas properties - - 66,383
Taxes, other than income taxes 8,515 6,557 6,943
--------------------------------------------------------------------------------
417,352 244,338 295,256
--------------------------------------------------------------------------------
Operating Income (Loss) (53,469) 36,058 (28,951)
--------------------------------------------------------------------------------
Interest Expense
Interest on long-term debt 24,089 19,735 19,600
Other interest charges 1,588 923 1,470
Interest capitalized (2,447) (3,307) (3,884)
--------------------------------------------------------------------------------
23,230 17,351 17,186
--------------------------------------------------------------------------------
Other Income (Expense) 1,997 (2,331) (3,956)
--------------------------------------------------------------------------------
Income (Loss) Before Provision (Benefit)
for Income Taxes (74,702) 16,376 (50,093)
--------------------------------------------------------------------------------
Provision (Benefit) for Income Taxes
Current - 537 (6,029)
Deferred (28,905) 5,912 (13,467)
--------------------------------------------------------------------------------
(28,905) 6,449 (19,496)
--------------------------------------------------------------------------------
Income (Loss) Before Extraordinary Item (45,797) 9,927 (30,597)
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569,000 Tax Benefit) (890) - -
--------------------------------------------------------------------------------
Net Income (Loss) $(46,687) $9,927 $(30,597)
================================================================================
Basic and Diluted Earnings Per Share
Income (Loss) Before Extraordinary Item $(1.82) $.40 $(1.23)
Extraordinary Loss Due to Early Retirement
of Debt (Net of $569,000 Tax Benefit) (.04) - -
Net Income (Loss) $(1.86) $.40 $(1.23)
================================================================================
Weighted Average Common Shares Outstanding 25,043,586 24,941,550 24,882,170
================================================================================
Diluted Weighted Average Common Shares
Outstanding 25,043,586 24,947,021 24,882,170
================================================================================
The accompanying notes are an integral part of the financial statements.
39
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 2000 1999
--------------------------------------------------------------------------------
(in thousands)
ASSETS
Current Assets
Cash $2,386 $1,240
Accounts receivable 77,041 43,339
Inventories, at average cost 17,000 21,520
Under-recovered purchased gas costs 12,942 -
Other 3,486 4,073
--------------------------------------------------------------------------------
Total current assets 112,855 70,172
--------------------------------------------------------------------------------
Investments 15,574 14,180
--------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method,
including $27,692,000 in 2000 and $37,554,000 in
1999 excluded from amortization 872,023 816,199
Gas distribution systems 190,893 222,145
Gas in underground storage 27,867 28,712
Other 27,940 28,826
--------------------------------------------------------------------------------
1,118,723 1,095,882
Less: Accumulated depreciation, depletion and
amortization 554,616 519,927
--------------------------------------------------------------------------------
564,107 575,955
--------------------------------------------------------------------------------
Other Assets 12,842 11,139
--------------------------------------------------------------------------------
$705,378 $671,446
================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Short-term debt $171,000 $7,500
Accounts payable 54,304 33,069
Taxes payable 4,346 3,506
Interest payable 2,806 2,483
Customer deposits 4,799 6,021
Other 2,629 3,767
--------------------------------------------------------------------------------
Total current liabilities 239,884 56,346
--------------------------------------------------------------------------------
Long-Term Debt 225,000 294,700
--------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 97,431 126,902
Other 1,772 3,142
--------------------------------------------------------------------------------
99,203 130,044
--------------------------------------------------------------------------------
Commitments and Contingencies
--------------------------------------------------------------------------------
Shareholders' Equity
Common stock, $.10 par value; authorized 75,000,000
shares, issued 27,738,084 shares 2,774 2,774
Additional paid-in capital 20,220 20,732
Retained earnings, per accompanying statements 148,353 198,044
--------------------------------------------------------------------------------
171,347 221,550
Less: Common stock in treasury, at cost, 2,556,908
shares in 2000 and 2,700,391 shares in 1999 28,485 30,083
Unamortized cost of restricted shares issued under
stock incentive plan, 241,452 shares in 2000 and
188,781 shares in 1999 1,571 1,111
--------------------------------------------------------------------------------
141,291 190,356
--------------------------------------------------------------------------------
$705,378 $671,446
================================================================================
The accompanying notes are an integral part of the financial statements.
40
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 2000 1999 1998
--------------------------------------------------------------------------------
(in thousands)
Cash Flows From Operating Activities
Net income (loss) $(46,687) $9,927 $(30,597)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Depreciation, depletion and amortization 47,227 42,971 48,267
Write-down of oil and gas properties - - 66,383
Deferred income taxes (28,905) 5,912 (13,467)
Equity in loss of partnership 1,767 2,008 3,087
Gain on sale of Missouri utility assets (3,209) - -
Extraordinary loss due to early retirement
of debt (net of tax) 890 - -
Change in assets and liabilities:
Accounts receivable (36,693) (2,684) 5,097
Income taxes receivable 85 1,658 1,066
Under-recovered purchased gas costs (14,104) (273) 10,931
Inventories 2,290 1,292 (2,347)
Accounts payable 22,156 (4,711) 7,877
Other current assets and liabilities 1,980 2,031 (2,589)
--------------------------------------------------------------------------------
Net cash provided by (used in) operating
activities (53,203) 58,131 93,708
--------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (75,717) (66,967) (64,359)
Sale of Missouri utility assets 32,000 - -
Sale of oil and gas properties 13,651 - -
Investment in partnership (3,250) (2,273) (10,062)
(Increase) decrease in gas stored underground 845 (4,433) (531)
Other items (1,066) 2,380 340
--------------------------------------------------------------------------------
Net cash used in investing activities (33,537) (71,293) (74,612)
--------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving debt and
short-term note 115,800 20,300 (11,500)
Retirement of notes and payments on
long-term debt (24,910) (1,535) (4,607)
Dividends paid (3,004) (5,985) (5,970)
--------------------------------------------------------------------------------
Net cash provided by (used in) financing
activities 87,886 12,780 (22,077)
--------------------------------------------------------------------------------
Increase (decrease) in cash 1,146 (382) (2,981)
Cash at beginning of year 1,240 1,622 4,603
--------------------------------------------------------------------------------
Cash at end of year $2,386 $1,240 $1,622
================================================================================
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 2000 1999 1998
--------------------------------------------------------------------------------
(in thousands)
Retained Earnings, beginning of year $198,044 $194,102 $230,669
Net income (loss) (46,687) 9,927 (30,597)
Cash dividends declared ($.12 per share in
2000, $.24 per share in 1999 and 1998) (3,004) (5,985) (5,970)
--------------------------------------------------------------------------------
Retained Earnings, end of year $148,353 $198,044 $194,102
================================================================================
The accompanying notes are an integral part of the financial statements.
41
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 2000, 1999, and 1998
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations and Consolidation
Southwestern Energy Company (Southwestern or the Company) is an
integrated energy company primarily focused on natural gas. Through its
wholly-owned subsidiaries, the Company is engaged in oil and gas exploration and
production, natural gas gathering, transmission and marketing, and natural gas
distribution. Southwestern's exploration and production activities are
concentrated in Arkansas, New Mexico, Texas, Oklahoma and Louisiana. The gas
distribution segment operates in northern Arkansas and under normal weather
conditions obtains approximately 35% to 40% of its gas supply from one of the
Company's exploration and production subsidiaries. The customers of the gas
distribution segment consist of residential, commercial, and industrial users of
natural gas. Southwestern's marketing and transportation business is
concentrated in its core areas of operations.
On May 31, 2000, the Company completed the sale of its Missouri gas
distribution assets for $32.0 million resulting in a pre-tax gain of
approximately $3.2 million. Proceeds from the sale of the Missouri assets were
used to reduce the Company's outstanding debt. As a result of the adverse Hales
judgment in June 2000, the Company's Board of Directors authorized management to
pursue the sale of the Company's remaining gas distribution assets. The sale
process did not result in an acceptable bid. Although the Company may sell its
gas distribution segment in the future, it currently plans to operate these
assets as a continuing part of its business.
The consolidated financial statements include the accounts of
Southwestern Energy Company and its wholly-owned subsidiaries, Southwestern
Energy Production Company, SEECO, Inc., Arkansas Western Gas Company,
Southwestern Energy Services Company, Diamond "M" Production Company,
Southwestern Energy Pipeline Company, A.W. Realty Company, and Arkansas Western
Pipeline Company. All significant intercompany accounts and transactions have
been eliminated. The Company accounts for its general partnership interest in
the NOARK Pipeline System, Limited Partnership (NOARK) using the equity method
of accounting. In accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," the
Company recognizes profit on intercompany sales of gas delivered to storage by
its utility subsidiary. Certain reclassifications have been made to the prior
years' financial statements to conform with the 2000 presentation. These
reclassifications had no effect on previously recorded net income.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any, at the
date of the financial statements, and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.
Unusual Items
In June 2000, the Company reported that the Arkansas Supreme Court
ruled to affirm the 1998 decision of the Sebastian County Circuit Court awarding
$109.3 million in a class action to royalty owners of SEECO, Inc. (Hales
judgment). The Company fully satisfied the judgment and the Circuit Court in
Sebastian County issued an order in complete satisfaction of the judgment
effective July 18, 2000. Additionally, the Company incurred an unusual charge of
$2.0 million related to other ongoing litigation.
42
Property, Depreciation, Depletion and Amortization
Gas and Oil Properties - The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive)
including salaries, benefits, and other internal costs directly attributable to
these activities are capitalized and amortized on an aggregate basis over the
estimated lives of the properties using the units-of-production method. The
Company excludes all costs of unevaluated properties from immediate
amortization. The Company's unamortized costs of oil and gas properties are
limited to the sum of the future net revenues attributable to proved oil and gas
reserves discounted at 10 percent plus the lower of cost or market value of any
unproved properties. If the Company's unamortized costs in oil and gas
properties exceed this ceiling amount, a provision for additional depreciation,
depletion and amortization is required. At June 30, 1998, the Company recognized
a $40.5 million non-cash charge to earnings by recording a write-down of its oil
and gas properties of $66.4 million and a related reduction in the provision for
deferred income taxes of $25.9 million. At December 31, 2000, 1999, and 1998,
the Company's net book value of oil and gas properties did not exceed the
ceiling amounts. Market prices, production rates, levels of reserves, and the
evaluation of costs excluded from amortization all influence the calculation of
the full cost ceiling.
Gas Distribution Systems - Costs applicable to construction activities,
including overhead items, are capitalized. Depreciation and amortization of the
gas distribution system is provided using the straight-line method with average
annual rates for plant functions ranging from 1.7% to 5.9%. Gas in underground
storage is stated at average cost.
Other property, plant and equipment is depreciated using the
straight-line method over estimated useful lives ranging from 5 to 35 years.
The Company charges to maintenance or operations the cost of labor,
materials, and other expenses incurred in maintaining the operating efficiency
of its properties. Betterments are added to property accounts at cost.
Retirements are credited to property, plant and equipment at cost and charged to
accumulated depreciation, depletion and amortization with no gain or loss
recognized, except for abnormal retirements.
Capitalized Interest - Interest is capitalized on the cost of
unevaluated gas and oil properties excluded from amortization. In accordance
with established utility regulatory practice, an allowance for funds used during
construction of major projects is capitalized and amortized over the estimated
lives of the related facilities.
Gas Distribution Revenues and Receivables
Customer receivables arise from the sale or transportation of gas by
the Company's gas distribution subsidiary. The Company's 136,000 gas
distribution customers are located in northern Arkansas and represent a
diversified base of residential, commercial, and industrial users. The Company
records gas distribution revenues on an accrual basis, as gas volumes are used,
to provide a proper matching of revenues with expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual cost of purchased gas above or below the
level included in the base rates is permitted to be billed or is required to be
credited to customers. Each month, the difference between actual costs of
purchased gas and gas costs recovered from customers is deferred. The deferred
differences are billed or credited, as appropriate, to customers in subsequent
months. Rate schedules include a weather normalization clause to lessen the
impact of revenue increases and decreases which might result from weather
variations during the winter heating season. The pass-through of gas costs to
customers is not affected by this normalization clause.
43
Gas Production Imbalances
The exploration and production subsidiaries record gas sales using the
entitlement method. The entitlement method requires revenue recognition of the
Company's revenue interest share of gas production from properties in which gas
sales are disproportionately allocated to owners because of marketing or other
contractual arrangements. The Company's net imbalance position at December 31,
2000 and 1999 was not significant.
Income Taxes
Deferred income taxes are provided to recognize the income tax effect
of reporting certain transactions in different years for income tax and
financial reporting purposes.
Risk Management
The Company uses derivative financial instruments to manage defined
commodity price risks and does not use them for trading purposes. The Company
uses commodity swap agreements and options to hedge sales of natural gas and
crude oil. Gains and losses resulting from hedging activities have been
recognized when the related physical transactions were recognized. Gains or
losses from commodity swap agreements and options that did not qualify for
accounting treatment as hedges have been recognized currently as other income or
expense. See Note 8 for a discussion of the Company's commodity hedging activity
and the impact of the adoption of SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities."
Earnings Per Share and Shareholders' Equity
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 2,602,800 shares with an average exercise price of $9.79 outstanding
at December 31, 2000 and options for 1,634,901 shares with a weighted average
exercise price of $12.15 outstanding at December 31, 1998. Due to the Company's
net loss for 2000 and 1998, these incremental shares would have an anti-dilutive
effect and were, therefore, not considered. The Company had options for
1,275,899 shares of common stock with a weighted average exercise price of
$12.97 per share at December 31, 1999, that were not included in the calculation
of diluted shares because they would have had an anti-dilutive effect. The
remaining 785,300 options at December 31, 1999 with a weighted average exercise
price of $6.46 were included in the calculation of diluted shares.
During 2000 and 1999, the Company issued 154,438 and 105,436 treasury
shares, respectively, under a compensatory plan and for stock awards and
returned to treasury 10,955 and 2,300 shares, respectively, canceled from
earlier issues under the compensatory plan. The net effect of these transactions
was a $1.6 million decrease in 2000 and a $1.2 million decrease in 1999 in
treasury stock.
Dividend on Common Stock
As a result of the adverse Hales judgment in June 2000, the Company has
indefinitely suspended payment of quarterly dividends on its common stock.
44
(2) DEBT
Debt balances as of December 31, 2000 and 1999 consisted of the following:
2000 1999
-------------------------
(in thousands)
Senior Notes
9.36% Series $ - $ 22,000
6.70% Series due 2005 125,000 125,000
7.625% Series due 2027, putable at the
holders' option in 2009 60,000 60,000
7.21% Series due 2017 40,000 40,000
--------------------------------------------------------------------------------
225,000 247,000
Other
Variable rate unsecured revolving credit arrangements - 47,700
--------------------------------------------------------------------------------
Total long-term debt $225,000 $294,700
================================================================================
Short-Term Debt
Variable rate (7.85% at December 31, 2000) unsecured
revolving credit arrangements $171,000 $ -
Short-term note payable - 7,500
--------------------------------------------------------------------------------
Total short-term debt $171,000 $ 7,500
================================================================================
In July 2000, the Company replaced its existing revolving credit
facilities with a new 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 9.36% Senior Notes.
The new credit facility is also being used to fund normal working capital needs.
The new credit facility has a term of 364 days, with interest generally based at
112.5 basis points over the LIBOR rate. The Company intends to renew or replace
this facility prior to its expiration.
In August 2000, the Company retired $22.0 million of 9.36% Senior
Notes. Certain costs of the redemption were expensed and are classified as an
extraordinary loss, net of related income tax effects, in the accompanying
financial statements.
The terms of the debt instruments and agreements contain covenants
which impose certain restrictions on the Company, including limiting of
additional indebtedness and prohibiting the payment of cash dividends. The
Company was in compliance with its debt agreements at December 31, 2000.
There are no aggregate maturities of long-term debt for each of the
years ending December 31, 2001 through 2004. For the year ended December 31,
2005, the aggregate maturity is $125.0 million. Total interest payments were
$23.6 million in 2000 and $19.6 million in 1999 and 1998.
45
(3) INCOME TAXES
The provision (benefit) for income taxes included the following
components:
2000 1999 1998
---------------------------------
(in thousands)
Federal:
Current $ - $ - $ (6,673)
Deferred (23,723) 5,236 (10,098)
State:
Current - 537 644
Deferred (5,063) 795 (3,250)
Investment tax credit amortization (119) (119) (119)
--------------------------------------------------------------------------------
Provision (benefit) for income taxes $(28,905) $6,449 $(19,496)
================================================================================
The provision (benefit) for income taxes was an effective rate of 38.7%
in 2000, 39.4% in 1999, and 38.9% in 1998. The following reconciles the
provision (benefit) for income taxes included in the consolidated statements of
operations with the provision (benefit) which would result from application of
the statutory federal tax rate to pretax financial income:
2000 1999 1998
---------------------------------
(in thousands)
Expected provision (benefit) at federal
statutory rate of 35% $(26,145) $5,732 $(17,532)
Increase (decrease) resulting from:
State income taxes, net of federal
income tax effect (3,291) 866 (1,694)
Other 531 (149) (270)
--------------------------------------------------------------------------------
Provision (benefit) for income taxes $(28,905) $6,449 $(19,496)
================================================================================
The components of the Company's net deferred tax liability as of
December 31, 2000 and 1999 were as follows:
2000 1999
-----------------------
(in thousands)
Deferred tax liabilities:
Differences between book and tax basis of property $129,702 $123,516
Stored gas 8,883 8,267
Deferred purchased gas costs 11,313 2,289
Prepaid pension costs 1,884 2,086
Book over tax basis in partnerships 11,755 10,133
Other 1,072 415
--------------------------------------------------------------------------------
164,609 146,706
--------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 884 705
Alternative minimum tax credit carryforward 3,046 3,127
Net operating loss carryforward 63,449 16,808
Other 1,671 1,155
--------------------------------------------------------------------------------
69,050 21,795
--------------------------------------------------------------------------------
Net deferred tax liability $ 95,559 $124,911
================================================================================
46
Total income tax payments of $.5 million, $.6 million, and $3.3 million
were made in 2000, 1999, and 1998, respectively.
(4) PENSION PLAN AND OTHER POSTRETIREMENT BENEFITS
The Company applies SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits." Substantially all employees are
covered by the Company's defined benefit pension and postretirement benefit
plans. The following provides a reconciliation of the changes in the plans'
benefit obligations, fair value of assets, and funded status as of December 31,
2000 and 1999:
Other Postretirement
Pension Benefits Benefits
----------------------------------------------
2000 1999 2000 1999
----------------------------------------------
(in thousands)
Change in Benefit Obligations:
Benefit obligation at January 1 $61,515 $59,194 $3,759 $3,832
Service cost 1,682 1,881 85 99
Interest cost 4,509 4,130 268 261
Amendments - 5,560 - -
Actuarial loss (gain) 1,438 (5,359) (226) (255)
Benefits paid (7,256) (3,891) (138) (178)
Amount transferred (5,317) - - -
Effect of settlement - - (1,737) -
-------------------------------------------------------------------------------------------
Benefit obligation at December 31 $56,571 $61,515 $2,011 $3,759
===========================================================================================
Change in Plan Assets:
Fair value of plan assets at January 1 $70,478 $71,518 $615 $345
Actual return on plan assets 8,716 2,838 4 20
Employer contributions - - 308 428
Benefit payments (7,243) (3,878) (138) (178)
Amount transferred (5,668) - - -
Effect of settlement - - (216) -
-------------------------------------------------------------------------------------------
Fair value of plan assets at December 31 $66,283 $70,478 $573 $615
===========================================================================================
Funded Status:
Funded status at December 31 $9,712 $8,963 $(1,438) $(3,144)
Unrecognized net actuarial (gain) loss (9,832) (9,237) 299 926
Unrecognized prior service cost 4,965 5,417 - -
Unrecognized transition obligation (37) (220) 1,032 1,265
-------------------------------------------------------------------------------------------
Prepaid (accrued) benefit cost $4,808 $4,923 $(107) $(953)
===========================================================================================
The Company's supplemental retirement plan has an accumulated benefit
obligation in excess of plan assets. The plan's accumulated benefit obligation
was $286,000 and $233,000 at December 31, 2000 and 1999, respectively. There are
no plan assets in the supplemental retirement plan due to the nature of the
plan.
47
Net periodic pension and other postretirement benefit costs include the
following components for 2000, 1999, and 1998:
Other Postretirement
Pension Benefits Benefits
-----------------------------------------------------
2000 1999 1998 2000 1999 1998
-----------------------------------------------------
(in thousands)
Service cost $1,682 $1,881 $2,060 $ 85 $ 99 $ 87
Interest cost 4,509 4,130 3,644 268 261 242
Expected return on plan assets (6,190) (6,259) (5,863) (39) (28) -
Amortization of transition obligation (183) (183) (183) 103 103 103
Recognized net actuarial (gain) loss (142) (142) (150) 63 111 55
Amortization of prior service costs 451 451 46 - - -
----------------------------------------------------------------------------------------------
$127 $(122) $(446) $480 $546 $487
==============================================================================================
Prior to 1998, the Company's pension plans provided for benefits based
on years of benefit service and the employee's "average compensation" as
defined. During 1998, the Company amended its plans to become "cash balance"
plans on a prospective basis. A cash balance plan provides benefits based upon a
fixed percentage of an employee's annual compensation. The Company's funding
policy is to contribute amounts which are actuarially determined to provide the
plans with sufficient assets to meet future benefit payment requirements and
which are tax deductible.
The postretirement benefit plans provide contributory health care and
life insurance benefits. Employees become eligible for these benefits if they
meet age and service requirements. Generally, the benefits paid are a stated
percentage of medical expenses reduced by deductibles and other coverages.
During 1998, the Company established trusts to partially fund its postretirement
benefit obligations.
The weighted average assumptions used in the measurement of the
Company's benefit obligations for 2000 and 1999 are as follows:
Other Postretirement
Pension Benefits Benefits
-------------------------------------------
2000 1999 2000 1999
-------------------------------------------
Discount rate 7.25% 7.50% 7.25% 7.50%
Expected return on plan assets 9.00% 9.00% 5.00% 5.00%
Rate of compensation increase 4.50% 4.50% n/a n/a
================================================================================
For measurement purposes a 9% annual rate of increase in the per capita
cost of covered medical benefits and an 8% annual rate of increase in the per
capita cost of dental benefits was assumed for 2001. These rates were assumed to
gradually decrease to 6% for medical benefits and 5% for dental benefits for
2011 and remain at that level thereafter.
48
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one percentage point change in
assumed health care cost trend rates would have the following effects:
1% Increase 1% Decrease
--------------------------
(in thousands)
Effect on the total service and interest cost
components $ 29 $ (25)
Effect on postretirement benefit obligation $220 $(190)
================================================================================
(5) NATURAL GAS AND OIL PRODUCING ACTIVITIES
All of the Company's gas and oil properties are located in the United
States. The table below sets forth the results of operations from gas and oil
producing activities:
2000 1999 1998
----------------------------------
(in thousands)
Sales $110,920 $75,039 $86,232
Production (lifting) costs (19,804) (14,039) (15,807)
Depreciation, depletion and amortization (39,048) (34,230) (39,444)
Write-down of oil and gas properties - - (66,383)
--------------------------------------------------------------------------------
52,068 26,770 (35,402)
Income tax benefit (expense) (20,023) (10,528) 13,913
--------------------------------------------------------------------------------
Results of operations $32,045 $16,242 $(21,489)
================================================================================
The results of operations shown above exclude unusual items in 2000 and
overhead and interest costs in all years. Income tax expense is calculated by
applying the statutory tax rates to the revenues less costs, including
depreciation, depletion and amortization, and after giving effect to permanent
differences and tax credits.
The table below sets forth capitalized costs incurred in gas and oil
property acquisition, exploration, and development activities during 2000, 1999,
and 1998:
2000 1999 1998
---------------------------------
(in thousands)
Property acquisition costs $13,369 $19,845 $12,729
Exploration costs 27,853 19,519 14,273
Development costs 27,519 19,059 24,709
--------------------------------------------------------------------------------
Capitalized costs incurred $68,741 $58,423 $51,711
================================================================================
Amortization per Mcf equivalent $1.06 $1.00 $1.04
================================================================================
Capitalized interest is included as part of the cost of oil and gas
properties. The Company capitalized $2.4 million, $3.3 million, and $3.9 million
during 2000, 1999, and 1998, respectively, based on the Company's weighted
average cost of borrowings used to finance the expenditures.
In addition to capitalized interest, the Company also capitalized
internal costs of $7.3 million, $7.4 million, and $7.7 million during 2000,
1999, and 1998, respectively. These internal costs were directly related to
acquisition, exploration and development activities and are included as part of
the cost of oil and gas properties.
49
The following table shows the capitalized costs of gas and oil
properties and the related accumulated depreciation, depletion and amortization
at December 31, 2000 and 1999:
2000 1999
-----------------------
(in thousands)
Proved properties $841,875 $774,473
Unproved properties 30,148 41,726
--------------------------------------------------------------------------------
Total capitalized costs 872,023 816,199
Less: Accumulated depreciation, depletion
and amortization 457,551 419,517
--------------------------------------------------------------------------------
Net capitalized costs $414,472 $396,682
================================================================================
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 2000. Of the total, approximately
$12.8 million is invested in Louisiana. The majority of Louisiana costs are
related to seismic projects that will be evaluated over several years as the
seismic data is interpreted and the acreage is explored. The remaining costs
excluded from amortization are related to properties which are not individually
significant and on which the evaluation process has not been completed. The
Company is, therefore, unable to estimate when these costs will be included in
the amortization computation.
2000 1999 1998 Prior Total
-------------------------------------------
(in thousands)
Property acquisition costs $4,047 $2,157 $1,785 $2,451 $10,440
Exploration costs 2,484 5,295 2,438 3,127 13,344
Capitalized interest 521 1,005 735 1,647 3,908
--------------------------------------------------------------------------------
$7,052 $8,457 $4,958 $7,225 $27,692
================================================================================
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved
natural gas and oil reserves for 2000, 1999, and 1998:
2000 1999 1998
-----------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
-----------------------------------------------------------
Proved reserves, beginning of year 307,523 7,859 303,667 6,850 291,378 7,852
Revisions of previous estimates 5,357 (22) (7,464) 1,155 1,064 (696)
Extensions, discoveries, and other additions 53,389 1,347 34,730 225 44,814 442
Production (31,602) (676) (29,444) (578) (32,668) (703)
Acquisition of reserves in place 8,100 82 9,762 576 - -
Disposition of reserves in place (11,013) (460) (3,728) (369) (921) (45)
---------------------------------------------------------------------------------------------------------
Proved reserves, end of year 331,754 8,130 307,523 7,859 303,667 6,850
=========================================================================================================
Proved, developed reserves:
Beginning of year 250,290 7,154 258,092 6,370 252,393 7,312
End of year 270,830 7,100 250,290 7,154 258,092 6,370
=========================================================================================================
50
The "Standardized Measure of Discounted Future Net Cash Flows Relating
to Proved Oil and Gas Reserves" (standardized measure) is a disclosure required
by SFAS No. 69, "Disclosures About Oil and Gas Producing Activities." The
standardized measure does not purport to present the fair market value of a
company's proved gas and oil reserves. In addition, there are uncertainties
inherent in estimating quantities of proved reserves. Substantially all
quantities of gas and oil reserves owned by the Company were estimated or
audited by the independent petroleum engineering firm of K & A Energy
Consultants, Inc.
Following is the standardized measure relating to proved gas and oil
reserves at December 31, 2000, 1999, and 1998:
2000 1999 1998
------------------------------------
(in thousands)
Future cash inflows $3,366,304 $ 989,997 $ 820,522
Future production and development costs (506,417) (227,361) (176,130)
Future income tax expense (974,273) (247,408) (206,097)
-----------------------------------------------------------------------------------------------
Future net cash flows 1,885,614 515,228 438,295
10% annual discount for estimated timing of cash flows (990,472) (253,153) (215,502)
-----------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 895,142 $ 262,075 $ 222,793
===============================================================================================
Under the standardized measure, future cash inflows were estimated by
applying year-end prices, adjusted for known contractual changes, to the
estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pretax cash inflows. Future income taxes were
computed by applying the year-end statutory rate, after consideration of
permanent differences, to the excess of pretax cash inflows over the Company's
tax basis in the associated proved gas and oil properties. Future net cash
inflows after income taxes were discounted using a 10% annual discount rate to
arrive at the standardized measure.
Following is an analysis of changes in the standardized measure during
2000, 1999, and 1998:
2000 1999 1998
------------------------------
(in thousands)
Standardized measure, beginning of year $262,075 $222,793 $259,063
Sales and transfers of gas and oil produced,
net of production costs (91,116) (61,000) (70,425)
Net changes in prices and production costs 837,691 48,506 (71,400)
Extensions, discoveries, and other additions,
net of future production and development costs 259,212 48,279 61,146
Acquisition of reserves in place 33,032 14,765 -
Revisions of previous quantity estimates 20,178 (612) (3,024)
Accretion of discount 38,076 32,447 38,445
Net change in income taxes (317,527) (17,015) 23,714
Changes in production rates (timing) and other (146,479) (26,088) (14,726)
--------------------------------------------------------------------------------
Standardized measure, end of year $895,142 $262,075 $222,793
================================================================================
51
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company holds a 25% general partnership interest in NOARK. NOARK
Pipeline was formerly a 258-mile long intrastate gas transmission system which
extended across northern Arkansas. In January 1998, the Company entered into an
agreement with Enogex Inc. (Enogex) that resulted in the expansion of the NOARK
Pipeline and provided the pipeline with access to Oklahoma gas supplies through
an integration of NOARK with the Ozark Gas Transmission System (Ozark). Enogex
is a subsidiary of OGE Energy Corp. Ozark was a 437-mile interstate pipeline
system which began in eastern Oklahoma and terminated in eastern Arkansas.
Enogex acquired the Ozark system and contributed it to NOARK. Enogex also
acquired the NOARK partnership interests not owned by Southwestern. The
acquisition of Ozark and its integration with NOARK Pipeline was approved by the
Federal Energy Regulatory Commission in late 1998 at which time NOARK Pipeline
was converted to an interstate pipeline and operated in combination with Ozark.
Enogex funded the acquisition of Ozark and the expansion and integration with
NOARK Pipeline which resulted in the Company's ownership interest in the
partnership decreasing to 25% from 48%.
The Company's investment in NOARK totaled $15.5 million at December 31,
2000 and $14.0 million at December 31, 1999, including advances of $3.3 million
made during 2000, $2.3 million made during 1999, and $10.1 million made during
1998. Advances in 1998 included the Company's share of costs related to the
prepayment of NOARK's Senior Secured Notes. Other advances are made primarily to
service NOARK's long-term debt. See Note 11 for further discussion of NOARK's
funding requirements and the Company's investment in NOARK.
NOARK's financial position at December 31, 2000 and 1999 is summarized
below:
2000 1999
--------------------------
(in thousands)
Current assets $ 9,532 $ 7,056
Noncurrent assets 179,136 178,195
--------------------------------------------------------------------------------
$188,668 $185,251
================================================================================
Current liabilities $ 11,803 $ 10,413
Long-term debt 73,000 75,000
Partners' capital 103,865 99,838
--------------------------------------------------------------------------------
$188,668 $185,251
================================================================================
The Company's share of NOARK's pretax loss was $1.8 million, $2.0
million, and $3.1 million for 2000, 1999, and 1998, respectively. The Company
records its share of NOARK's pretax loss in other income (expense) on the
statements of operations.
NOARK's results of operations for 2000, 1999, and 1998 are summarized
below:
2000 1999 1998
-------------------------------
(in thousands)
Operating revenues $73,633 $40,358 $17,445
Pretax net loss $(1,391) $(3,564) $(4,114)
================================================================================
52
(8) FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair
value of each class of financial instruments for which it is practicable to
estimate the value:
Cash, Customer Deposits, and Short-Term Debt: The carrying amount is a
reasonable estimate of fair value.
Long-Term Debt: The fair value of the Company's long-term debt is
estimated based on the expected current rates which would be offered to the
Company for debt of the same maturities.
Commodity Hedges: The fair value of all hedging financial instruments
is the amount at which they could be settled, based on quoted market prices or
estimates obtained from dealers. The carrying amounts and estimated fair values
of the Company's financial instruments as of December 31, 2000 and 1999 were as
follows:
2000 1999
---------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------------------------------------------
(in thousands)
Cash $2,386 $2,386 $1,240 $1,240
Customer deposits $4,799 $4,799 $6,021 $6,021
Short-term debt $171,000 $171,000 $7,500 $7,500
Long-term debt $225,000 $226,309 $294,700 $289,193
Commodity hedges $(160) $(60,596) $640 $(399)
================================================================================
Derivatives and Price Risk Management
SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended by SFAS No. 137 and SFAS No. 138, is effective for
fiscal years beginning after June 15, 2000 and requires that all derivatives be
recognized as assets or liabilities in the balance sheet and that these
instruments be measured at 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. Additionally, the Company recorded a net of
tax cumulative loss to retained earnings of $1.7 million and a net of tax loss
to other comprehensive income (equity section of the balance sheet) of $35.4
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.
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 appropriate
credit standings.
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
53
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
"ceiling" price above which the Company pays the counterparty the amount by
which the price of the commodity is above the contracted ceiling.
At December 31, 2000, the Company had collars in place on 31.2 Bcf of
future gas production. Of this total, 21.9 Bcf had floors and ceilings ranging
from $3.50 to $6.00, respectively. The remaining 9.3 Bcf had floors and ceilings
ranging from $2.50 to $3.50, respectively. Additionally, the Company had collars
on 300,000 barrels of crude oil with floors and ceilings ranging from $27.00 to
$30.33, respectively.
At December 31, 2000, the Company had outstanding natural gas price
swaps on total notional volumes of 3.1 Bcf for which the Company will receive
fixed prices ranging from $2.57 to $4.62 per MMBtu. Under contracts on .4 Bcf
the Company will make average fixed price payments of $4.83 per MMBtu and
receive variable prices based on the NYMEX futures market. At December 31, 2000,
the Company also had outstanding crude oil swaps to receive fixed prices of
$17.49 per barrel in 2001 on notional volumes of 72,000 barrels. The Company's
price risk management activities reduced revenues $39.3 million in 2000 and $1.1
million in 1999, and increased revenues $7.4 million in 1998.
At December 31, 2000, the Company also had an $18.00 per barrel floor
on 325,000 barrels. Subsequent to December 31, 2000, the Company closed its
position on this oil floor. 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.
(9) STOCK OPTIONS
The Southwestern Energy Company 2000 Stock Incentive Plan (2000 Plan)
was adopted in February, 2000 and provides for the compensation of officers, key
employees and eligible non-employee directors of the Company and its
subsidiaries. The 2000 Plan replaces the Southwestern Energy Company 1993 Stock
Incentive Plan (1993 Plan) and the Southwestern Energy Company 1993 Stock
Incentive Plan for Outside Directors (1993 Director Plan). The 2000 Plan
provides for grants of options, stock appreciation rights, shares of phantom
stock, and shares of restricted stock that in the aggregate do not exceed
1,250,000 shares. The types of incentives which may be awarded are comprehensive
and are intended to enable the Board of Directors to structure the most
appropriate incentives and to address changes in income tax laws which may be
enacted over the term of the 2000 Plan.
The 1993 Plan provided for the compensation of officers and key
employees of the Company and its subsidiaries through grants of options, shares
of restricted stock, and stock bonuses that in the aggregate did not exceed
1,700,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock and cash awards, the shares related to which in the
aggregate did not exceed 1,700,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The Company has also awarded stock
option grants outside the 2000 Plan and the 1993 Plan to certain non-officer
employees and to certain officers at the time of their hire.
54
The 2000 Plan awards each non-employee director who is eligible to
participate in the plan an annual Director's Option with respect to 8,000 shares
of common stock. Previously, the 1993 Director Plan provided for annual stock
option grants of 12,000 shares (with 12,000 limited SARs) to each non-employee
director. Options under the 1993 Director Plan were limited to no more than
240,000 shares.
The Company's 1985 Nonqualified Stock Option Plan expired in 1992,
except with respect to awards then outstanding. The following tables summarize
stock option activity for the years 2000, 1999, and 1998 and provide information
for options outstanding at December 31, 2000:
2000 1999 1998
------------------------------------------------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Exercise of Exercise of Exercise
Shares Price Shares Price Shares Price
------------------------------------------------------------------
Options outstanding at January 1 2,061,199 $10.49 1,634,901 $12.15 1,619,114 $13.37
Granted 666,100 $7.58 562,250 $6.18 394,900 $8.00
Exercised - - 1,333 $7.31 22,200 $5.58
Canceled 124,499 $9.55 134,619 $12.68 356,913 $13.48
--------------------------------------------------------------------------------------------------------
Options outstanding at December 31 2,602,800 $9.79 2,061,199 $10.49 1,634,901 $12.15
========================================================================================================
Options Outstanding Options Exercisable
------------------------------------------------------------------
Weighted
Weighted Average Weighted
Options Average Remaining Options Average
Range of Outstanding Exercise Contractual Exercisable Exercise
Exercise Prices at Year End Price Life (Years) at Year End Price
-------------------------------------------------------------------------------------------
$6.00 - $7.00 573,084 $6.14 8.8 195,272 $6.18
$7.06 - $8.75 866,701 $7.42 9.3 167,004 $7.34
$9.06 - $13.38 623,800 $11.99 6.0 512,737 $12.24
$14.00 - $17.50 539,215 $14.95 4.3 451,369 $15.01
-------------------------------------------------------------------------------------------
2,602,800 $9.79 1,326,382 $11.67
===========================================================================================
All options are issued at fair market value at the date of grant and
expire ten years from the date of grant. Options generally vest to employees and
directors over a three to four year period from the date of grant. Of the total
options outstanding, 325,000 performance accelerated options were granted in
1994 at an option price of $14.63. These options vest over a four-year period
beginning in 2000.
The Company has granted 453,165 shares of restricted stock to employees
through 2000. Of this total, 410,615 shares vest over a three-year period and
the remaining shares vest over a five-year period. The related compensation
expense is being amortized over the vesting periods. As of December 31, 2000,
189,512 shares have vested to employees and 22,201 shares have been cancelled
and returned to treasury shares.
55
The Company applies the disclosure-only provisions of SFAS No. 123,
"Accounting for Stock-Based Compensation." Accordingly, no compensation cost has
been recognized for the stock option plans. Had compensation cost for the
Company's stock option plans been determined consistent with the provisions of
SFAS No. 123, the Company's net income (loss) and earnings (loss) per share
would have been reduced to the pro forma amounts indicated below:
2000 1999 1998
---------------------------------
Net income (loss), in thousands
As reported $(46,687) $9,927 $(30,597)
Pro forma $(47,444) $9,241 $(31,201)
Basic earnings (loss) per share
As reported $(1.86) $.40 $(1.23)
Pro forma $(1.90) $.37 $(1.25)
Diluted earnings (loss) per share
As reported $(1.86) $.40 $(1.23)
Pro forma $(1.90) $.37 $(1.25)
Because the SFAS No. 123 method of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in future years. The fair
value of each option grant is estimated on the date of grant using the
Black-Scholes option pricing model with the following weighted-average
assumptions: no dividend yield; expected volatility of 44.0%; risk-free interest
rate of 6.0%; and expected lives of 6 years.
(10) COMMON STOCK PURCHASE RIGHTS
In 1999, the Company's Common Share Purchase Rights Plan was amended
and extended for an additional ten years. Per the terms of the amended plan, one
common share purchase right is attached to each outstanding share of the
Company's common stock. Each right entitles the holder to purchase one share of
common stock at an exercise price of $40.00, subject to adjustment. These rights
will become exercisable in the event that a person or group acquires or
commences a tender or exchange offer for 15% or more of the Company's
outstanding shares or the Board determines that a holder of 10% or more of the
Company's outstanding shares presents a threat to the best interests of the
Company. At no time will these rights have any voting power.
If any person or entity actually acquires 15% of the common stock (10%
or more if the Board determines such acquiror is adverse), rightholders (other
than the 15% or 10% stockholder) will be entitled to buy, at the right's then
current exercise price, the Company's common stock with a market value of twice
the exercise price. Similarly, if the Company is acquired in a merger or other
business combination, each right will entitle its holder to purchase, at the
right's then current exercise price, a number of the surviving company's common
shares having a market value at that time of twice the right's exercise price.
56
The rights may be redeemed by the Board for $.01 per right or exchanged
for common shares on a one-for-one basis prior to the time that they become
exercisable. In the event, however, that redemption of the rights is considered
in connection with a proposed acquisition of the Company, the Board may redeem
the rights only on the recommendation of its independent directors
(nonmanagement directors who are not affiliated with the proposed acquiror).
These rights expire in 2009.
(11) CONTINGENCIES AND COMMITMENTS
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on NOARK's 7.15% Notes due 2018.
The Company's share of the several guarantee is 60%. At December 31, 2000 and
1999, the principal outstanding for these Notes was $75.0 million and $77.0
million, respectively. 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, as discussed further in Note 7, 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.
In its Form 8-K filed July 2, 1996, the Company disclosed that a
lawsuit relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
This matter went to a non-jury trial as to liability on January 10, 2000. The
court in this matter issued Findings of Fact and Conclusions of Law that found
no fraud was committed. The court also found that any override royalty interests
that might ultimately be found to be due under the plaintiffs' 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
proceeding that is scheduled for April 30, 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 United States Minerals Management Service (MMS), a federal agency
responsible for the administration of federal oil and gas leases, is
investigating the Company and its subsidiaries in respect of claims similar to
those in the Hales class action royalty litigation previously reported. The
Company was found to be ultimately liable in the Hales litigation and satisfied
the judgment in July 2000. MMS was included in the class action litigation
against its objections, but did not pursue further action to remove itself from
the class.
57
On August 25, 2000, a class action suit was filed against the Company
and its subsidiaries in Sebastian County, Arkansas, on behalf of all mineral
owners who own or owned a royalty and/or overriding royalty interest in oil and
gas leases or other agreements in certain sections of Franklin County, Arkansas.
The Company was granted authority in 1968 by the Arkansas Oil and Gas Commission
to operate a gas storage facility in one section of Franklin County. Based upon
subsequently developed geological data, the Company sought authority to expand
this area and was granted authority by the Arkansas Oil and Gas Commission to
operate gas storage in additional sections. Plaintiffs are challenging the
storage agreements that the Company obtained from the mineral interest owners in
1968, 1999 and 2000 to operate the gas storage facility known as "Stockton".
Plaintiffs allege various wrongful, intentional and fraudulent acts relating to
the operation of the storage pool beginning in 1968 and continuing to the
present and allege that the above-referenced agreements from the mineral owners
were obtained through misrepresentation and fraud. The Company has owned and
operated the Stockton storage unit through its Arkansas Western Gas Company
subsidiary until 1994, at which time it was transferred to its subsidiary,
SEECO, Inc. Plaintiffs claim ownership rights in the gas that the Company has
stored in the storage pool in an amount in excess of $5 million in actual
damages, interest, attorney's fees and punitive damages. The Company and its
outside counsel believe that this action is without merit and does not meet the
requirements for a class action. The Company believes that plaintiffs' claim to
the storage gas, which the Company has injected into the storage facility, has
no merit and is not supported by the Arkansas gas storage statute under which
the Company operates this facility. While the amount of this claim could be
significant, management believes, based upon its investigation, that this claim
is without merit and that the Company's ultimate liability, if any, will not be
material to its consolidated financial position, but in any one period it could
be significant to its results of operations.
The Company is subject to laws and regulations relating to the
protection of the environment. The Company's policy is to accrue environmental
and cleanup related costs of a non-capital 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.
(12) 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
is shown in the following table. The "Other" column includes items related to
non-reportable segments (real estate and pipeline operations) and corporate
items.
58
Exploration
and Gas
Production Distribution Marketing Other Total
------------------------------------------------------------
(in thousands)
2000
Revenues from external customers $ 75,597 $151,052 $137,234 $ - $363,883
Intersegment revenues 35,323 182 70,514 448 106,467
Unusual items (1) 111,288 - - - 111,288
Operating income (loss) (70,584) 14,655 2,460 - (53,469)
Depreciation, depletion and
amortization expense 39,048 6,625 109 87 45,869
Interest expense (2) 17,472 4,608 16 1,134 23,230
Provision (benefit) for income taxes (2) (34,153) 4,869 912 (533) (28,905)
Assets 460,296 188,811 20,929 35,342(3) 705,378
Capital expenditures 69,211 5,994 24 488 75,717
=====================================================================================================
1999
Revenues from external customers $ 51,533 $132,293 $ 96,570 $ - $280,396
Intersegment revenues 23,506 127 40,956 416 65,005
Operating income 16,451 17,187 2,142 278 36,058
Depreciation, depletion and
amortization expense 34,230 7,186 92 95 41,603
Interest expense (2) 11,345 5,027 - 979 17,351
Provision (benefit) for income taxes (2) 1,806 4,569 859 (785) 6,449
Assets 435,022 190,731 11,212 34,481(3) 671,446
Capital expenditures 59,004 7,124 9 830 66,967
=====================================================================================================
1998
Revenues from external customers $ 55,347 $134,579 $ 76,367 $ 12 $266,305
Intersegment revenues 30,885 132 20,808 608 52,433
Operating income (loss) (47,273) 16,029 1,800 493 (28,951)
Depreciation, depletion and
amortization expense 39,444 7,296 41 136 46,917
Write-down of oil and gas properties 66,383 - - - 66,383
Interest expense (2) 10,906 5,299 38 943 17,186
Provision (benefit) for income taxes (2) (23,238) 4,028 704 (990) (19,496)
Assets 408,193 192,396 8,905 38,126(3) 647,620
Capital expenditures 52,376 10,108 8 1,867 64,359
=====================================================================================================
[FN]
(1) Includes $109.3 million for the Hales judgment and $2.0 million for other
ongoing litigation.
(2) Interest expense and the provision (benefit) for income taxes by segment are
an allocation of corporate amounts as debt and income tax expense (benefit) are
incurred at the corporate level.
(3) Other assets include the Company's equity investment in the operations of
NOARK (see Note 7), corporate assets not allocated to segments, and assets
for non-reportable segments.
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.
59
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for
the years ended December 31, 2000 and 1999:
Quarter Ended March 31 June 30 September 30 December 31
-------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
2000
-------------------------------------------------
Operating revenues $96,913 $78,483 $75,342 $113,145
Operating income (loss) $21,056 $(101,849) $5,884 $21,440
Net income (loss) $9,186 $(64,199) $(754) $9,080
Basic and diluted earnings (loss) per share $.37 $(2.57) $(.03) $.36
1999
-------------------------------------------------
Operating revenues $78,220 $56,039 $60,400 $85,737
Operating income $19,929 $1,541 $1,664 $12,924
Net income (loss) $9,132 $(1,704) $(1,935) $4,434
Basic and diluted earnings (loss) per share $.37 $(.07) $(.08) $.18
=================================================================================================
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no changes in or disagreements with accountants on
accounting and financial disclosure.
Part III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The definitive Proxy Statement to holders of the Company's Common Stock
in connection with the solicitation of proxies to be used in voting at the
Annual Meeting of Shareholders on May 17, 2001 (the 2001 Proxy Statement), is
hereby incorporated by reference for the purpose of providing information about
the identification of directors. Refer to the sections "Election of Directors"
and "Share Ownership of Management and Directors" for information concerning the
directors.
Information concerning executive officers is presented in Part I, Item 4 of this
Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
The 2001 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about executive compensation. Refer to the
section "Executive Compensation."
60
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The 2001 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about security ownership of certain beneficial
owners and management. Refer to the sections "Security Ownership of Certain
Beneficial Owners" and "Share Ownership of Managment and Directors" for
information about security ownership of certain beneficial owners and
management.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The 2001 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about related transactions. Refer to the
section "Share Ownership of Management and Directors" for information about
transactions with members of the Company's Board of Directors.
Part IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) The consolidated financial statements of the Company and its
subsidiaries and the report of independent public accountants
are included in Item 8 of this Report.
(2) The consolidated financial statement schedules have been omitted
because they are not required under the related instructions, or
are not applicable.
(3) The exhibits listed on the accompanying Exhibit Index (pages 63 and
64) are filed as part of, or incorporated by reference into, this
Report.
(b) Reports on Form 8-K:
A Current Report on Form 8-K was filed on November 3, 2000, referencing
a conference call conducted on October 31, 2000, announcing the results of the
Company's third quarter 2000 activity.
A Current Report on Form 8-K was filed on December 8, 2000, referencing
a press release issued on December 7, 2000, announcing the Company's hedge
position for 2001 through 2003.
A Current Report on Form 8-K was filed on December 20, 2000,
referencing a press release issued on December 18, 2000, announcing the
Company's 2001 strategy and outlook. Additional exhibits included the transcript
of the December 18, 2000 teleconference regarding the December 18th press
release and the accompanying slide presentation.
61
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused the report to be signed on
its behalf by the undersigned, thereunto duly authorized.
SOUTHWESTERN ENERGY COMPANY
--------------------------------
(Registrant)
Dated: March 30, 2001 BY: /s/ Greg D. Kerley
--------------------------------
Greg D. Kerley
Executive Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated on March 30, 2001.
/s/ Harold M. Korell President, Chief Executive Officer
------------------------------------ and Director
Harold M. Korell
/s/ Greg D. Kerley Executive Vice President
------------------------------------ and Chief Financial Officer
Greg D. Kerley
/s/ Stanley T. Wilson Controller and Chief Accounting Officer
------------------------------------
Stanley T. Wilson
/s/ Charles E. Scharlau Director and Chairman
------------------------------------
Charles E. Scharlau
/s/ Lewis E. Epley, Jr. Director
------------------------------------
Lewis E. Epley, Jr.
/s/ John Paul Hammerschmidt Director
------------------------------------
John Paul Hammerschmidt
/s/ Robert L. Howard Director
------------------------------------
Robert L. Howard
/s/ Kenneth R. Mourton Director
------------------------------------
Kenneth R. Mourton
Supplemental Information to be Furnished With Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered Securities
Pursuant of Section 12 of the Act.
Not Applicable
62
EXHIBIT INDEX
Exhibit
No. Description
------- -----------
3. Articles of Incorporation and Bylaws of the Company (amended and
restated Articles of Incorporation incorporated by reference to Exhibit 3
to Annual Report on Form 10-K for the year ended December 31,1993);
Bylaws of the Company (amended Bylaws of the Company incorporated by
reference to Exhibit 3 to Annual Report on Form 10-K for the year ended
December 31, 1994).
4.1 Amended and Restated Rights Agreement, dated April 12, 1999 (incorporated
by reference to Exhibit 4.1 to Annual Report on Form 10-K for the year
ended December 31, 1999).
4.2 Prospectus, Registration Statement, and Indenture on 6.70% Senior Notes
due December 1, 2005 and issued December 5, 1995 (incorporated by
reference to the Company's Forms S-3 and S-3/A filed on November 1, 1995,
and November 17, 1995, respectively, and also to the Company's filings of
a Prospectus and Prospectus Supplement on November 22, 1995, and December
4, 1995, respectively).
4.3 Prospectus Supplement and Form of Distribution Agreement on $125,000,000
of Medium-Term Notes dated February 21, 1997 (Prospectus Supplement
incorporated by reference to the Company's filing of a Prospectus
Supplement on February 21, 1997, Form of Distribution Agreement
incorporated by reference to Exhibit 10 filed with the Company's Form 8-K
dated February 21, 1997).
4.4 Short-Term Credit Agreement dated July 17, 2000 between Southwestern
Energy Company and Bank One, N.A., as administrative agent, and Bank of
America, N.A., as syndication agent (filed herewith).
Material Contracts:
10.1 Gas Purchase Contract between SEECO, Inc. and Associated Natural Gas
Company, dated October 1, 1990, and as amended September 30, 1997
(original contract incorporated by reference to Exhibit 10 to Annual
Report on Form 10-K for the year ended December 31, 1990; amendment
incorporated by reference to Exhibit 10.2 to Annual Report on Form 10-K
for the year ended December 31, 1997).
10.2 Compensation Plans:
(a) Summary of Southwestern Energy Company Annual and Long-Term Incentive
Compensation Plan, effective January 1, 1985, as amended July 10,
1989 (replaced by Southwestern Energy Company Incentive Compensation
Plan, effective January 1, 1993) (original plan incorporated by
reference to Exhibit 10 to Annual Report on Form 10-K for the year
ended December 31, 1984; first amendment thereto incorporated by
reference to Exhibit 10 to Annual Report on Form 10-K for the year
ended December 31, 1989).
(b) Southwestern Energy Company Incentive Compensation Plan, effective
January 1, 1993, and Amended and Restated as of January 1, 1999
(incorporated by reference to Exhibit 10.2(b) to Annual Report on
Form 10-K for the year ended December 31, 1998).
(c) Nonqualified Stock Option Plan, effective February 22, 1985, as
amended July 10, 1989 (replaced by Southwestern Energy Company 1993
Stock Incentive Plan, dated April 7, 1993, which was replaced by the
Southwestern Energy Company 2000 Stock Incentive Plan dated February
18, 2000) (original plan incorporated by reference to Exhibit 10 to
Annual Report on Form 10-K for the year ended December 31, 1985;
amended plan incorporated by reference to Exhibit 10 to Annual Report
on Form 10-K for the year ended December 31, 1989).
(d) Southwestern Energy Company 1993 Stock Incentive Plan, dated April 7,
1993 and Amended and Restated as of February 18, 1998 (replaced by
the Southwestern Energy Company 2000 Stock Incentive Plan dated
February 18, 2000) (incorporated by reference to Exhibit 10.2(d) to
Annual Report on Form 10-K for the year ended December 31, 1998).
63
Exhibit
No. Description
------- -----------
(e) Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors, dated April 7, 1993 (replaced by the Southwestern Energy
Company 2000 Stock Incentive Plan dated February 18, 2000)
(incorporated by reference to the appendix filed with the Company's
definitive Proxy Statement to holders of the Registrant's Common
Stock in connection with the solicitation of proxies to be used in
voting at the Annual Meeting of Shareholders on May 26, 1993).
(f) Southwestern Energy Company 2000 Stock Incentive Plan dated February
18, 2000 (incorporated by reference to the appendix filed with the
Company's definitive Proxy Statement to holders of the Registrant's
Common Stock in connection with the solicitation of proxies to be
used in voting at the Annual Meeting of Shareholders on May 24,
2000).
10.3 Southwestern Energy Company Supplemental Retirement Plan, adopted May 31,
1989, and Amended and Restated as of December 15, 1993, and as further
amended February 1, 1996 (amended and restated plan incorporated by
reference to Exhibit 10.5 to Annual Report on Form 10-K for the year
ended December 31, 1993; amendment dated February 1, 1996, incorporated
by reference to Exhibit 10.5 to Annual Report on Form 10-K for the year
ended December 31, 1995).
10.4 Southwestern Energy Company Supplemental Retirement Plan Trust, dated
December 30, 1993 (incorporated by reference to Exhibit 10.6 to Annual
Report on Form 10-K for the year ended December 31, 1993).
10.5 Southwestern Energy Company Nonqualified Retirement Plan, effective
October 4, 1995 (incorporated by reference to Exhibit 10.7 to Annual
Report of Form 10-K for the year ended December 31, 1995).
10.6 Employment and Consulting Agreement for Charles E. Scharlau, dated
May 21, 1998 (incorporated by reference to Exhibit 10.9 to Annual Report
on Form 10-K for the year ended December 31, 1998).
10.7 Form of Indemnity Agreement, between the Company and each officer and
director of the Company (incorporated by reference to Exhibit 10.20 to
Annual Report on Form 10-K for the year ended December 31, 1991).
10.8 Form of Executive Severance Agreement for the Executive Officers of the
Company, effective February 17,1999 (incorporated by reference to Exhibit
10.12 to Annual Report on Form 10-K for the year ended December 31,
1998).
10.9 Omnibus Project Agreement of NOARK Pipeline System, Limited Partnership
by and among Southwestern Energy Pipeline Company, Southwestern Energy
Company, Enogex Arkansas Pipeline Corporation, and Enogex Inc., dated
January 12, 1998 (incorporated by reference to Exhibit 10.17 to Annual
Report on Form 10-K for the year ended December 31, 1997).
10.10 Amended and Restated Limited Partnership Agreement of NOARK Pipeline
System, Limited Partnership dated January 12, 1998 and amended June 18,
1998 (amended and restated agreement incorporated by reference to Exhibit
10.18 to Annual Report on Form 10-K for the year ended December 31, 1997;
first amendment thereto incorporated by reference to Exhibit 10.14 to
Annual Report on Form 10-K for the year ended December 31, 1998).
10.11 Asset Sale and Purchase Agreement by and among Southwestern Energy
Company, Arkansas Western Gas Company and Atmos Energy Corporation, dated
October 15, 1999 (incorporated by reference to Exhibit 10.12 to Annual
Report on Form 10-K for the year ended December 31, 1999).
21. Subsidiaries of the Registrant (incorporated by reference to Exhibit 21
to Annual Report on Form 10-K for the year ended December 31, 1996).
23. Consent of Arthur Andersen LLP (filed herewith).
64