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Proc-Type: 2001,MIC-CLEAR
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<SEC-DOCUMENT>0000007332-01-000032.txt : 20010402
<SEC-HEADER>0000007332-01-000032.hdr.sgml : 20010402
ACCESSION NUMBER: 0000007332-01-000032
CONFORMED SUBMISSION TYPE: 10-K405
PUBLIC DOCUMENT COUNT: 4
CONFORMED PERIOD OF REPORT: 20001231
FILED AS OF DATE: 20010330
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: SOUTHWESTERN ENERGY CO
CENTRAL INDEX KEY: 0000007332
STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923]
IRS NUMBER: 710205415
STATE OF INCORPORATION: AR
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K405
SEC ACT:
SEC FILE NUMBER: 001-08246
FILM NUMBER: 1585537
BUSINESS ADDRESS:
STREET 1: 1083 SAIN ST
STREET 2: P O BOX 1408
CITY: FAYETTEVILLE
STATE: AR
ZIP: 72702-1408
BUSINESS PHONE: 5015211141
MAIL ADDRESS:
STREET 1: 1083 SAIN ST
STREET 2: P O BOX 1408
CITY: FAYETTEVILLE
STATE: AR
ZIP: 72702-1408
FORMER COMPANY:
FORMER CONFORMED NAME: ARKANSAS WESTERN GAS CO
DATE OF NAME CHANGE: 19790917
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K405
<SEQUENCE>1
<FILENAME>0001.txt
<DESCRIPTION>ANNUAL REPORT FOR THE YEAR ENDED DECEMBER 31, 2000
<TEXT>
================================================================================
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
-----------------
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
----------------------------- -----------------------
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.
================================================================================
<PAGE>
SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT on FORM 10-K
For the Year Ended December 31, 2000
<TABLE>
<CAPTION>
TABLE OF CONTENTS Page
<S> <C> <C>
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
</TABLE>
2
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
Texas/
Arkoma Mid-Continent New Mexico Louisiana Total
-------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
4
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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").
<TABLE>
<CAPTION>
AWG Associated Total
------------------------------------
<S> <C> <C> <C>
Gathering 386 - 386
Transmission 812 172 984
Distribution 3,172 520 3,692
- --------------------------------------------------------------------------------
4,370 692 5,062
================================================================================
</TABLE>
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
<TABLE>
<CAPTION>
Undeveloped Developed
Gross Net Gross Net
----------------------------------------------
<S> <C> <C> <C> <C>
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
================================================================================
</TABLE>
17
<PAGE>
Producing Wells
<TABLE>
<CAPTION>
Gas Oil Total
Gross Net Gross Net Gross Net
----------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
================================================================================
</TABLE>
Wells Drilled During the Year
<TABLE>
<CAPTION>
Exploratory
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
- ---- --------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
Development
Productive Wells Dry Holes Total
Year Gross Net Gross Net Gross Net
- ---- --------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
Wells in Progress as of December 31, 2000
<TABLE>
<CAPTION>
Gross Net
-------------------
<S> <C> <C>
Exploratory - -
Development 1.0 0.4
- --------------------------------------------------------------------------------
Total 1.0 0.4
================================================================================
</TABLE>
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
<PAGE>
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
<PAGE>
Executive Officers of the Registrant
<TABLE>
<CAPTION>
Years Served
Name Officer Position Age as Officer
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
Range of Market Prices Cash Dividends Paid
Quarter Ended 2000 1999 2000 1999
- ------------- --------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
2000 1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
=========================================================================================================================
</TABLE>
[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.
</FN>
22
<PAGE>
<TABLE>
<CAPTION>
2000 1999 1998 1997 1996 1995
- ------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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%
==================================================================================================================
</TABLE>
[FN]
(1) Gas distribution statistics include the operations of the Company's
Missouri properties through the sale date of May 31, 2000.
</FN>
23
<PAGE>
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.
<TABLE>
<CAPTION>
2000 1999 1998
--------------------------------------
<S> <C> <C> <C>
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
</TABLE>
[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.
</FN>
24
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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 $3.2 million and proceeds from the sale were used to pay down
debt. As a result of the adverse Hales judgment, the Company's Board of
Directors authorized management to pursue the sale of the Company's remaining
gas distribution operations. The sale process did not result in an acceptable
bid. Although the Company may sell its gas distribution segment in the future,
it currently plans to operate these assets as a continuing part of its business.
<TABLE>
<CAPTION>
2000 1999 1998
-------------------------------------------
($ in thousands, except for Mcf amounts)
<S> <C> <C> <C>
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%
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<TABLE>
<CAPTION>
2000 1999 1998
-----------------------------------------
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------------------
(in thousands)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
32
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<TABLE>
<CAPTION>
Expected Maturity Date Fair Value
-------------------------------------------------------------------- ----------
2001 2002 2003 2004 2005 Thereafter Total 12/31/00
-------------------------------------------------------------------- ----------
($ in millions)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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%
</TABLE>
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
<PAGE>
<TABLE>
<CAPTION>
Expected Maturity Date
2001 2002 2003
----------------------------------------------------------
Carrying Fair Carrying Fair Carrying Fair
Amount Value Amount Value Amount Value
----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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 - - - -
</TABLE>
[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.
</FN>
36
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
<S> <C>
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
</TABLE>
37
<PAGE>
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
<PAGE>
Statements of Operations
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------
(in thousands, except share
and per share amounts)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
39
<PAGE>
Balance Sheets
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
December 31, 2000 1999
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
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
================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
40
<PAGE>
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31, 2000 1999 1998
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
41
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
(2) DEBT
Debt balances as of December 31, 2000 and 1999 consisted of the following:
<TABLE>
<CAPTION>
2000 1999
-------------------------
(in thousands)
<S> <C> <C>
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
================================================================================
</TABLE>
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
<PAGE>
(3) INCOME TAXES
The provision (benefit) for income taxes included the following
components:
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------------
(in thousands)
<S> <C> <C> <C>
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)
================================================================================
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------------
(in thousands)
<S> <C> <C> <C>
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)
================================================================================
</TABLE>
The components of the Company's net deferred tax liability as of
December 31, 2000 and 1999 were as follows:
<TABLE>
<CAPTION>
2000 1999
-----------------------
(in thousands)
<S> <C> <C>
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
================================================================================
</TABLE>
46
<PAGE>
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:
<TABLE>
<CAPTION>
Other Postretirement
Pension Benefits Benefits
----------------------------------------------
2000 1999 2000 1999
----------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
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)
===========================================================================================
</TABLE>
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
<PAGE>
Net periodic pension and other postretirement benefit costs include the
following components for 2000, 1999, and 1998:
<TABLE>
<CAPTION>
Other Postretirement
Pension Benefits Benefits
-----------------------------------------------------
2000 1999 1998 2000 1999 1998
-----------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
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
==============================================================================================
</TABLE>
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:
<TABLE>
<CAPTION>
Other Postretirement
Pension Benefits Benefits
-------------------------------------------
2000 1999 2000 1999
-------------------------------------------
<S> <C> <C> <C> <C>
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
================================================================================
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
1% Increase 1% Decrease
--------------------------
(in thousands)
<S> <C> <C>
Effect on the total service and interest cost
components $ 29 $ (25)
Effect on postretirement benefit obligation $220 $(190)
================================================================================
</TABLE>
(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:
<TABLE>
<CAPTION>
2000 1999 1998
----------------------------------
(in thousands)
<S> <C> <C> <C>
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)
================================================================================
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------------
(in thousands)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
2000 1999
-----------------------
(in thousands)
<S> <C> <C>
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
================================================================================
</TABLE>
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.
<TABLE>
<CAPTION>
2000 1999 1998 Prior Total
-------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
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
================================================================================
</TABLE>
(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:
<TABLE>
<CAPTION>
2000 1999 1998
-----------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
-----------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
=========================================================================================================
</TABLE>
50
<PAGE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------------
(in thousands)
<S> <C> <C> <C>
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
===============================================================================================
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------
(in thousands)
<S> <C> <C> <C>
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
================================================================================
</TABLE>
51
<PAGE>
(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:
<TABLE>
<CAPTION>
2000 1999
--------------------------
(in thousands)
<S> <C> <C>
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
================================================================================
</TABLE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
-------------------------------
(in thousands)
<S> <C> <C> <C>
Operating revenues $73,633 $40,358 $17,445
Pretax net loss $(1,391) $(3,564) $(4,114)
================================================================================
</TABLE>
52
<PAGE>
(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:
<TABLE>
<CAPTION>
2000 1999
---------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
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)
================================================================================
</TABLE>
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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
------------------------------------------------------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Exercise of Exercise of Exercise
Shares Price Shares Price Shares Price
------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
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
========================================================================================================
</TABLE>
<TABLE>
<CAPTION>
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
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$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
===========================================================================================
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
2000 1999 1998
---------------------------------
<S> <C> <C> <C>
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)
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
Exploration
and Gas
Production Distribution Marketing Other Total
------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
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
=====================================================================================================
</TABLE>
[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.
</FN>
Intersegment sales by the exploration and production segment and
marketing segment to the gas distribution segment are priced in accordance with
terms of existing contracts and current market conditions. Parent company assets
include furniture and fixtures, prepaid debt costs, and prepaid pension costs.
Parent company general and administrative costs, depreciation expense and taxes
other than income are allocated to segments. All of the Company's operations are
located within the United States.
59
<PAGE>
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for
the years ended December 31, 2000 and 1999:
<TABLE>
<CAPTION>
Quarter Ended March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
2000
-------------------------------------------------
<S> <C> <C> <C> <C>
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
=================================================================================================
</TABLE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4.4
<SEQUENCE>2
<FILENAME>0002.txt
<DESCRIPTION>CREDIT AGREEMENT
<TEXT>
================================================================================
CREDIT AGREEMENT
DATED AS OF JULY 17, 2000
AMONG
SOUTHWESTERN ENERGY COMPANY,
THE LENDERS,
BANK ONE, NA,
AS ADMINISTRATIVE AGENT,
AND
BANK OF AMERICA, N.A.,
AS SYNDICATION AGENT
BANC ONE CAPITAL MARKETS, INC. AND
BANC OF AMERICA SECURITIES LLC,
AS JOINT LEAD ARRANGERS AND BOOK RUNNERS
================================================================================
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
<S> <C> <C>
ARTICLE I
DEFINITIONS.................................1
ARTICLE II
THE CREDITS ...............................12
2.1 Commitment ....................................................12
2.2 Required Payments; Maturity ...................................13
2.3 Ratable Loans .................................................13
2.4 Types of Advances .............................................13
2.5 Commitment Fee; Voluntary Reductions in Aggregate Commitment ..13
2.6 Minimum Amount of Each Advance ................................13
2.7 Mandatory Reductions in Aggregate Commitment ..................13
2.8 Prepayments ...................................................14
2.9 Method of Selecting Types and Interest Periods for
New Advances ..................................................14
2.10 Conversion and Continuation of Outstanding Advances ...........15
2.11 Changes in Interest Rate, etc .................................16
2.12 Rates Applicable After Default ................................16
2.13 Method of Payment .............................................16
2.14 Noteless Agreement; Evidence of Indebtedness ..................17
2.15 Telephonic Notices ............................................17
2.16 Interest Payment Dates; Interest and Fee Basis ................18
2.17 Notification of Advances, Interest Rates, Prepayments and
Commitment Reductions .........................................18
2.18 Lending Installations .........................................18
2.19 Non-Receipt of Funds by the Administrative Agent ..............18
2.20 Replacement of Lender .........................................19
ARTICLE III
YIELD PROTECTION; TAXES..........................19
3.1 Yield Protection ..............................................19
3.2 Changes in Capital Adequacy Regulations .......................20
3.3 Availability of Types of Advances .............................21
3.4 Funding Indemnification .......................................21
3.5 Taxes .........................................................21
3.6 Lender Statements; Survival of Indemnity ......................23
i
<PAGE>
ARTICLE IV
CONDITIONS PRECEDENT ...........................24
4.1 Initial Advance ...............................................24
4.2 Each Advance ..................................................25
ARTICLE V
REPRESENTATIONS AND WARRANTIES ......................26
5.1 Organization ..................................................26
5.2 Authorization and Validity ....................................26
5.3 Financial Statements ..........................................26
5.4 Subsidiaries ..................................................26
5.5 ERISA .........................................................26
5.6 Defaults ......................................................27
5.7 Accuracy of Information .......................................27
5.8 Regulation U ..................................................27
5.9 No Adverse Change .............................................27
5.10 Taxes .........................................................27
5.11 Liens .........................................................27
5.12 Compliance with Orders ........................................28
5.13 Litigation ....................................................28
5.14 Burdensome Agreements .........................................28
5.15 No Conflict ...................................................28
5.16 Title to Properties ...........................................28
5.17 Public Utility Holding Company Act ............................28
5.18 Regulatory Approval ...........................................29
5.19 Negative Pledge ...............................................29
5.20 Investment Company Act ........................................29
5.21 Compliance with Laws ..........................................29
ARTICLE VI
COVENANTS.................................29
6.1 Information ...................................................29
6.2 Affirmative Covenants .........................................32
6.2.1. Reports and Inspection .................................32
6.2.2 Conduct of Business .....................................32
6.2.3 Insurance ...............................................33
6.2.4 Taxes ...................................................33
6.2.5 Compliance with Laws ....................................33
6.2.6 Maintenance of Properties ...............................33
6.3 Negative Covenants ............................................33
6.3.1 Restricted Payments .....................................34
ii
<PAGE>
6.3.2 Merger and Sale of Assets ...............................34
6.3.3 Liens ...................................................35
6.4 Financial Covenants ...........................................38
6.4.1 Debt to Capitalization Ratio ............................38
6.4.2 Fixed Charge Coverage Ratio .............................38
6.4.3 Net Worth ...............................................38
6.3.4 Subsidiary Indebtedness .................................38
ARTICLE VII
DEFAULTS..................................38
7.1 Events of Default .............................................38
7.1.1 Representations and Warranties ..........................38
7.1.2 Payment Default .........................................38
7.1.3 Breach of Certain Covenants .............................38
7.1.4 Other Breach of this Agreement ..........................39
7.1.5 ERISA ...................................................39
7.1.6 Cross-Default ...........................................39
7.1.7 Voluntary Bankruptcy, etc ...............................39
7.1.8 Involuntary Bankruptcy, etc .............................39
7.1.9 Judgments ...............................................40
7.1.10 Environmental Matters ..................................40
ARTICLE VIII
ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES ..............40
8.1 Acceleration ..................................................40
8.2 Amendments ....................................................40
8.3 Preservation of Rights ........................................41
ARTICLE IX
GENERAL PROVISIONS.............................41
9.1 Survival of Representations ...................................41
9.2 Governmental Regulation .......................................41
9.3 Headings ......................................................42
9.4 Entire Agreement ..............................................42
9.5 Several Obligations; Benefits of this Agreement ...............42
9.6 Expenses; Indemnification .....................................42
9.7 Numbers of Documents ..........................................43
9.8 Accounting ....................................................43
9.9 Severability of Provisions ....................................43
9.10 Nonliability of Lenders .......................................43
9.11 Confidentiality ...............................................43
iii
<PAGE>
9.12 Nonreliance ...................................................44
9.13 Disclosure ....................................................44
ARTICLE X
THE AGENTS ................................44
10.1 Appointment; Nature of Relationship ...........................44
10.2 Powers ........................................................44
10.3 General Immunity ..............................................44
10.4 No Responsibility for Loans, Recitals, etc ....................45
10.5 Action on Instructions of Lenders .............................45
10.6 Employment of Agents and Counsel ..............................45
10.7 Reliance on Documents; Counsel ................................45
10.8 Agents' Reimbursement and Indemnification .....................46
10.9 Notice of Default .............................................46
10.10 Rights as a Lender ............................................46
10.11 Lender Credit Decision ........................................47
10.12 Successor Agent ...............................................47
10.13 Delegation to Affiliates ......................................48
ARTICLE XI
SETOFF; RATABLE PAYMENTS .........................48
11.1 Setoff ........................................................48
11.2 Ratable Payments ..............................................48
ARTICLE XII
BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS .............48
12.1 Successors and Assigns ........................................48
12.2 Participations ................................................49
12.2.1. Permitted Participants; Effect ........................49
12.2.2. Voting Rights .........................................49
12.3 Assignments ...................................................50
12.3.1. Permitted Assignments .................................50
12.3.2. Effect; Effective Date ................................50
12.4 Dissemination of Information ..................................51
12.5 Tax Treatment .................................................51
ARTICLE XIII
NOTICES ..................................51
13.1 Notices .......................................................51
13.2 Change of Address .............................................51
iv
<PAGE>
ARTICLE XIV
COUNTERPARTS ...............................51
ARTICLE XV
CHOICE OF LAW; CONSENT TO JURISDICTION;
WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE ................52
15.1 CHOICE OF LAW .................................................52
15.2 CONSENT TO JURISDICTION .......................................52
15.3 WAIVER OF JURY TRIAL ..........................................52
15.4 Maximum Interest Rate .........................................53
15.5 Termination of Existing Agreements ............................53
</TABLE>
v
<PAGE>
<TABLE>
<CAPTION>
SCHEDULES
<S> <C>
Schedule 1A Commitments
Schedule 1B Existing Indebtedness
Schedule 2.7(a) Excluded Asset Sales
Schedule 2.7(b) Assets to be Swapped
Schedule 5.4 Subsidiaries
Schedule 5.13 Litigation
Schedule 5.19 Liens
Schedule 6.2 Insurance
EXHIBITS
Exhibit A Form of Borrowing Notice
Exhibit B Form of Opinion of Counsel to Borrower
Exhibit C Form of Assignment Agreement
Exhibit D Form of Money Transfer Instructions
Exhibit E Form of Note
Exhibit F Form of Compliance Certificate
</TABLE>
vi
<PAGE>
CREDIT AGREEMENT
This Agreement, dated as of July 17, 2000, is among Southwestern Energy
Company, the Lenders, Bank of America N.A., as Syndication Agent, and Bank One,
NA, a national banking association having its principal office in Chicago,
Illinois, as Administrative Agent. The parties hereto agree as follows:
ARTICLE I
DEFINITIONS
As used in this Agreement:
"Acquisition" means any transaction, or any series of related transactions,
consummated on or after the date of this Agreement, by which the Borrower or any
of its Subsidiaries (i) acquires any going business or all or substantially all
of the assets of any firm, corporation or limited liability company, or division
thereof, whether through purchase of assets, merger or otherwise or (ii)
directly or indirectly acquires (in one transaction or as the most recent
transaction in a series of transactions) at least a majority (in number of
votes) of the securities of a corporation which have ordinary voting power for
the election of directors (other than securities having such power only by
reason of the happening of a contingency) or a majority (by percentage or voting
power) of the outstanding ownership interests of a partnership or limited
liability company.
"Administrative Agent" means Bank One in its capacity as administrative
agent for the Lenders pursuant to Article X, and not in its individual capacity
as a Lender, and any successor Administrative Agent appointed pursuant to
Article X.
"Advance" means a borrowing hereunder, (i) made by the Lenders on the same
Borrowing Date, or (ii) converted or continued by the Lenders on the same date
of conversion or continuation, consisting, in either case, of the aggregate
amount of the several Loans of the same Type and, in the case of Eurodollar
Loans and Transaction Rate Loans, for the same Interest Period.
"Affected Lender" is defined in Section 2.20.
"Affiliate" of any Person means any other Person directly or indirectly
controlling, controlled by or under common control with such Person. A Person
shall be deemed to control another Person if the controlling Person owns 10% or
more of any class of voting securities (or other ownership interests) of the
controlled Person or possesses, directly or indirectly, the power to direct or
cause the direction of the management or policies of the controlled Person,
whether through ownership of stock, by contract or otherwise.
"Agent" means the Administrative Agent and/or the Syndication Agent.
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"Aggregate Commitment" means the aggregate of the Commitments of all the
Lenders, as reduced from time to time pursuant to the terms hereof.
"Agreement" means this credit agreement, as it may be amended or modified
and in effect from time to time.
"Agreement Accounting Principles" means generally accepted accounting
principles as in effect from time to time; provided that if the Borrower
notifies the Administrative Agent that the Borrower does not want to give effect
to any change in generally accepted accounting principles (or if the
Administrative Agent notifies the Borrower that the Required Lenders do not want
to give effect to any such change), then Agreement Accounting Principles shall
mean generally accepted accounting principles as in effect immediately before
the relevant change in generally accepted accounting principles became
effective, until either such notice is withdrawn or this Agreement is amended in
a manner satisfactory to the Borrower and the Required Lenders. "Alternate Base
Rate" means, for any day, a rate of interest per annum equal to the higher of
(i) the Prime Rate for such day and (ii) the sum of the Federal Funds Effective
Rate for such day plus 1/2% per annum.
"Arranger" means each of Banc One Capital Markets, Inc. and Banc of America
Securities LLC.
"Article" means an article of this Agreement unless another document is
specifically referenced.
"Asset Sale" means any sale, lease, assignment for value or other
disposition by the Borrower or any Subsidiary, excluding (a) sales and other
dispositions in the ordinary course of business and (b) any sale or other
disposition of any asset listed on Schedule 2.7(a).
"Authorized Officer" means any of the following officers of the Borrower,
acting singly: the Chief Executive Officer, the President, the Chief Financial
Officer, the Treasurer or any Executive Vice President, Senior Vice President or
Vice President.
"Bank One" means Bank One, NA, a national banking association having its
principal office in Chicago, Illinois, in its individual capacity, and its
successors.
"Borrower" means Southwestern Energy Company, an Arkansas corporation, and
its successors and assigns.
"Borrowing Date" means a date on which an Advance is made hereunder.
"Borrowing Notice" is defined in Section 2.9.
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"Business Day" means (i) with respect to any borrowing, payment or rate
selection of Eurodollar Advances, a day (other than a Saturday or Sunday) on
which banks generally are open in Chicago, Dallas and New York for the conduct
of substantially all of their commercial lending activities, interbank wire
transfers can be made on the Fedwire system and dealings in United States
dollars are carried on in the London interbank market and (ii) for all other
purposes, a day (other than a Saturday or Sunday) on which banks generally are
open in Chicago and Dallas for the conduct of substantially all of their
commercial lending activities and interbank wire transfers can be made on the
Fedwire system.
"Capitalized Lease" of a Person means any lease of Property, except oil and
gas leases, by such Person as lessee which would be capitalized on a balance
sheet of such Person prepared in accordance with Agreement Accounting
Principles.
"Capitalized Lease Obligations" of a Person means the amount of the
obligations of such Person under Capitalized Leases which would be shown as a
liability on a balance sheet of such Person prepared in accordance with
Agreement Accounting Principles.
"Case" means the case styled as Allen Hales, Mary Nellie Hales, Robert G.
Jeffers, David P. Taylor, and Taylor Family Limited Partnership "A" v. Seeco,
Inc., Arkansas Western Gas Company, and Southwestern Energy Company, Case No.
CIV-96-327 (III), in the Circuit Court of Sebastian County, Arkansas, and the
appeals therefrom.
"Code" means the Internal Revenue Code of 1986, as amended, reformed or
otherwise modified from time to time.
"Commitment" means, for each Lender, the obligation of such Lender to make
Loans not exceeding the amount set forth on Schedule 1A or as set forth in any
assignment that has become effective pursuant to Section 12.3.2, as such amount
may be modified from time to time pursuant to the terms hereof.
"Contingent Obligation" of a Person means any agreement, undertaking or
arrangement by which such Person assumes, guarantees, endorses, contingently
agrees to purchase or provide funds for the payment of, or otherwise becomes or
is contingently liable upon, the obligation or liability of any other Person, or
agrees to maintain the net worth or working capital or other financial condition
of any other Person, or otherwise assures any creditor of such other Person
against loss, including, without limitation, any comfort letter, operating
agreement, take or pay contract, application for a Letter of Credit or the
obligations of any such Person as general partner of a partnership with respect
to the liabilities of the partnership.
"Conversion/Continuation Notice" is defined in Section 2.10.
"Controlled Group" means all members of a controlled group of corporations
or other business entities and all trades or businesses (whether or not
incorporated) under common
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control which, together with the Borrower or any of its Subsidiaries, are
treated as a single employer under Section 414 of the Code.
"Debt to Capitalization Ratio" means the ratio of (a) Total Debt to (b) the
sum of Total Debt plus Stockholders' Equity.
"Default" means an event described in Article VII.
"Environmental Laws" means any and all federal, state, local and foreign
statutes, laws, judicial decisions, regulations, ordinances, rules, judgments,
orders, decrees, plans, injunctions, permits, concessions, grants, franchises,
licenses, agreements and other governmental restrictions relating to (i) the
protection of the environment, (ii) the effect of the environment on human
health, (iii) emissions, discharges or releases of pollutants, contaminants,
hazardous substances or wastes into surface water, ground water or land, or (iv)
the manufacture, processing, distribution, use, treatment, storage, disposal,
transport or handling of pollutants, contaminants, hazardous substances or
wastes or the clean-up or other remediation thereof.
"ERISA" means the Employee Retirement Income Security Act of 1974, as
amended from time to time, and any rule or regulation issued thereunder.
"Eurodollar Advance" means an Advance which, except as otherwise provided
in Section 2.12, bears interest at the applicable Eurodollar Rate.
"Eurodollar Base Rate" means, with respect to a Eurodollar Advance for the
relevant Interest Period, the applicable British Bankers' Association Interest
Settlement Rate for deposits in U.S. dollars appearing on Reuters Screen FRBD as
of 11:00 a.m. (London time) two Business Days prior to the first day of such
Interest Period, and having a maturity equal to such Interest Period, provided
that, (i) if Reuters Screen FRBD is not available to the Administrative Agent
for any reason, the applicable Eurodollar Base Rate for the relevant Interest
Period shall instead be the applicable British Bankers' Association Interest
Settlement Rate for deposits in U.S. dollars as reported by any other generally
recognized financial information service as of 11:00 a.m. (London time) two
Business Days prior to the first day of such Interest Period, and having a
maturity equal to such Interest Period, and (ii) if no such British Bankers'
Association Interest Settlement Rate is available to the Administrative Agent,
the applicable Eurodollar Base Rate for the relevant Interest Period shall
instead be the rate determined by the Administrative Agent to be the rate at
which Bank One or one of its Affiliate banks offers to place deposits in U.S.
dollars with first-class banks in the London interbank market at approximately
11:00 a.m. (London time) two Business Days prior to the first day of such
Interest Period, in the approximate amount of the relevant Eurodollar Loan and
having a maturity equal to such Interest Period.
"Eurodollar Loan" means a Loan which, except as otherwise provided in
Section 2.12, bears interest at the applicable Eurodollar Rate.
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"Eurodollar Rate" means, with respect to a Eurodollar Advance for the
relevant Interest Period, the sum of the Eurodollar Base Rate applicable to such
Interest Period plus 1.125%.
"Excluded Taxes" means, in the case of each Lender or applicable Lending
Installation and each Agent, taxes imposed on its overall net income, and
franchise taxes imposed on it, by (i) the jurisdiction under the laws of which
such Lender or such Agent is incorporated or organized or (ii) the jurisdiction
in which such Agent's or such Lender's principal executive office or such
Lender's applicable Lending Installation is located.
"Exhibit" refers to an exhibit to this Agreement, unless another document
is specifically referenced.
"Existing Indebtedness" means any Indebtedness described in Schedule 1B
hereto having those terms existing on the date of this Agreement, but no
extension, renewal or replacement thereof.
"Federal Funds Effective Rate" means, for any day, an interest rate per
annum equal to the weighted average of the rates on overnight Federal funds
transactions with members of the Federal Reserve System arranged by Federal
funds brokers on such day, as published for such day (or, if such day is not a
Business Day, for the immediately preceding Business Day) by the Federal Reserve
Bank of New York, or, if such rate is not so published for any day which is a
Business Day, the average of the quotations at approximately 10:00 a.m. (Chicago
time) on such day on such transactions received by the Administrative Agent from
three Federal funds brokers of recognized standing selected by the
Administrative Agent in its sole discretion.
"Final Maturity Date" means July 16, 2001 or such earlier date when the
amount of the Aggregate Commitment has been reduced to zero.
"Fixed Charge Coverage Ratio" means, for any period of four fiscal quarters
of the Borrower ending on the last day of a fiscal quarter, the ratio of (a) the
sum of (i) the Borrower's consolidated earnings before interest, taxes,
depreciation and amortization of non-cash charges, all determined on a
consolidated basis and in accordance with Agreement Accounting Principles for
such period, but excluding, to the extent otherwise included therein, any
non-cash gain or loss on any hedging agreement resulting from the requirements
of SFAS 133, plus (ii) to the extent deducted in determining such consolidated
earnings, (x) any charge resulting from the Case and (y) any non-cash charge
after the date hereof resulting from any write-down of the Borrower's oil and
gas properties to the full cost ceiling limitation required by the full cost
method of accounting for such properties, to (b) the sum of (i) the Borrower's
interest expense for such period plus (ii) the current portion of principal
payments of long-term Indebtedness as of the last day of such period (excluding
any portion of the Private Placement Debt which is current due to the
acceleration thereof resulting from a breach of Section 6.A or 6.B of the
Private Placement Agreement, which acceleration would not be permitted by any
other provision of the Private Placement Agreement).
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"Floating Rate" means, for any day, a rate per annum equal to the Alternate
Base Rate for such day, changing when and as the Alternate Base Rate changes.
"Floating Rate Advance" means an Advance which, except as otherwise
provided in Section 2.12, bears interest at the Floating Rate.
"Floating Rate Loan" means a Loan which, except as otherwise provided in
Section 2.12, bears interest at the Floating Rate.
"Indebtedness" of a Person means such Person's (i) obligations for borrowed
money, (ii) obligations representing the deferred purchase price of Property or
services, (iii) obligations, whether or not assumed, secured by Liens or payable
out of the proceeds or production from Property now or hereafter owned or
acquired by such Person, (iv) obligations which are evidenced by notes,
acceptances, or other instruments, (v) obligations of such Person to purchase
accounts, securities or other Property arising out of or in connection with the
sale of the same or substantially similar accounts, securities or Property, (vi)
Capitalized Lease Obligations, (vii) any other obligation for borrowed money or
other financial accommodation which in accordance with Agreement Accounting
Principles would be shown as a liability on the consolidated balance sheet of
such Person, (viii) net liabilities under interest rate swap, exchange or cap
agreements, obligations or other liabilities with respect to accounts or notes,
(ix) Sale and Leaseback Transactions which do not create a liability on the
consolidated balance sheet of such Person, (x) other transactions which are the
functional equivalent, or take the place, of borrowing but which do not
constitute a liability on the consolidated balance sheet of such Person, (xi)
Contingent Obligations and (xii) Mandatorily Redeemable Stock; provided that,
notwithstanding any of the foregoing, accounts payable arising in the ordinary
course of business payable on terms customary in the trade, and Contingent
Obligations in respect thereof, shall not constitute Indebtedness; and provided,
further, that Indebtedness shall not include accounts payable which the Borrower
is required to reflect on its balance sheet in accordance with Agreement
Accounting Principles to the extent that (i) such accounts payable consist
solely of contingent obligations under oil and gas hedge transactions for future
periods and (ii) as of any date of calculation thereof, the volume of oil and
gas subject to such hedge transactions is not greater than 90% of the Borrower's
anticipated production from proved, producing, oil and gas reserves owned by the
Borrower and its Subsidiaries as of such date over the term covered by such
hedge transactions.
"Intercompany Indebtedness" means any Indebtedness of the Borrower owing to
any Subsidiary or of any Subsidiary owing to the Borrower or to any other
Subsidiary; provided that in the case of any Indebtedness owed by the Borrower
or any Subsidiary to a Subsidiary which is not a Wholly-Owned Subsidiary, such
Indebtedness shall constitute Intercompany Indebtedness only to the extent of
the Borrower's ownership percentage (whether direct or indirect) of the
Subsidiary holding such Indebtedness.
"Interest Period" means, with respect to a Eurodollar Advance, a period of
one, two, three or six months commencing on a Business Day selected by the
Borrower pursuant to this
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Agreement. Such Interest Period shall end on the day which corresponds
numerically to such date one, two, three or six months thereafter, provided that
if there is no such numerically corresponding day in such next, second, third or
sixth succeeding month, such Interest Period shall end on the last Business Day
of such next, second, third or sixth succeeding month. If an Interest Period
would otherwise end on a day which is not a Business Day, such Interest Period
shall end on the next succeeding Business Day, provided that if said next
succeeding Business Day falls in a new calendar month, such Interest Period
shall end on the immediately preceding Business Day.
"Investment" of a Person means any loan, advance (other than commission,
travel and similar advances to officers and employees made in the ordinary
course of business), extension of credit (other than accounts receivable arising
in the ordinary course of business on terms customary in the trade) or
contribution of capital by such Person; stocks, bonds, mutual funds, partnership
interests, notes, debentures or other securities owned by such Person; any
deposit accounts and certificate of deposit owned by such Person; and structured
notes, derivative financial instruments and other similar instruments or
contracts owned by such Person.
"Knowledge" means, with respect to the Borrower, the actual knowledge of
(i) any Authorized Officer, (ii) any vice president of the Borrower in charge of
a principal business unit, division or function (such as sales, administration
or finance), (iii) any other officer who performs a policy making function or
(iv) any other person who performs similar policy making functions for the
Borrower.
"Lenders" means the lending institutions listed on the signature pages of
this Agreement and their respective successors and assigns.
"Lending Installation" means, with respect to a Lender or the
Administrative Agent, the office, branch, subsidiary or affiliate of such Lender
or the Administrative Agent listed on its administrative questionnaire or on the
signature pages hereof or otherwise selected by such Lender or the
Administrative Agent pursuant to Section 2.18.
"Letter of Credit" of a Person means a letter of credit or similar
instrument which is issued upon the application of such Person or upon which
such Person is an account party or for which such Person is in any way liable.
"Lien" means any lien (statutory or other), mortgage, pledge,
hypothecation, assignment, deposit arrangement, encumbrance or other security
arrangement (including, without limitation, the interest of a vendor or lessor
under any conditional sale, Capitalized Lease or other title retention
agreement).
"Loan" means, with respect to a Lender, any loan made by such Lender
pursuant to Article II (or any conversion or continuation thereof).
"Loan Documents" means this Agreement and any Notes issued pursuant to
Section 2.15.
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"Mandatorily Redeemable Stock" means, with respect to any Person, any share
of such Person's capital stock or other equity interest to the extent that it is
(a) redeemable, payable or required to be purchased or otherwise retired or
extinguished, or convertible into any Indebtedness or other liability of such
Person, (i) at a fixed or determinable date, whether by operation of a sinking
fund or otherwise, (ii) at the option of any Person other than such Person or
(iii) upon the occurrence of a condition not solely within the control of such
Person, such as a redemption required to be made out of future earnings or (b)
convertible into Mandatorily Redeemable Stock.
"Material Adverse Effect" means a material adverse effect on (i) the
business, Property, condition (financial or otherwise) or results of operations
of the Borrower and its Subsidiaries taken as a whole, (ii) the ability of the
Borrower to perform its obligations under the Loan Documents, or (iii) the
validity or enforceability of any of the Loan Documents or the rights or
remedies of the Agent or the Lenders thereunder.
"Material Group of Subsidiaries" means two or more Subsidiaries which, if
merged as of any relevant date of determination, would constitute a Significant
Subsidiary.
"Multiemployer Plan" means a Plan maintained pursuant to a collective
bargaining agreement or any other arrangement to which the Borrower or any
member of the Controlled Group is a party to which more than one employer is
obligated to make contributions.
"Net Cash Proceeds" means, with respect to any Asset Sale, the aggregate
cash proceeds (including cash proceeds received by way of deferred payment of
principal pursuant to a note, installment receivable or otherwise, but only as
and when received) received by the Borrower or any Subsidiary pursuant to such
Asset Sale net of (i) the direct costs relating to such Asset Sale (including
sales commissions and legal, accounting and investment banking fees), (ii) taxes
paid or reasonably estimated by the Borrower to be payable as a result thereof
(after taking into account any available tax credits or deductions and any tax
sharing arrangements), (iii) amounts required to be applied to the repayment of
any Indebtedness secured by a Lien on any asset subject to such Asset Sale, (iv)
amounts required to be applied to prepay Private Placement Debt (without giving
effect to any amendment after the date hereof to the Private Placement
Agreement) and (v) the proceeds of any sale of any of the assets listed on
Schedule 2.7(b) to the extent that such proceeds are applied within 150 days to
acquire oil or gas producing properties.
"Non-U.S. Lender" is defined in Section 3.5(iv).
"Note" means any promissory note issued at the request of a Lender pursuant
to Section 2.14 in the form of Exhibit E.
"Obligations" means all unpaid principal of and accrued and unpaid interest
on the Loans, all accrued and unpaid fees and all expenses, reimbursements,
indemnities and other obligations of the Borrower to the Lenders or to any
Lender, either Agent or any indemnified party arising under the Loan Documents.
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"Other Taxes" is defined in Section 3.5(ii).
"Participants" is defined in Section 12.2.1.
"Payment Date" means the last day of each March, June, September and
December.
"PBGC" means the Pension Benefit Guaranty Corporation, or any successor
thereto.
"Person" means any natural person, corporation, firm, joint venture,
partnership, limited liability company, association, enterprise, trust or other
entity or organization, or any government or political subdivision or any
agency, department or instrumentality thereof.
"Plan" means an employee pension benefit plan which is covered by Title IV
of ERISA or subject to the minimum funding standards under Section 412 of the
Code as to which the Borrower or any member of the Controlled Group may have any
liability.
"Prime Rate" means a rate per annum equal to the prime rate of interest
announced by Bank One or by its parent, BANK ONE CORPORATION, which is not
necessarily the lowest rate charged to any customer, changing when and as said
prime rate changes.
"Principal Transmission Facility" means any transportation or distribution
facility, including pipelines, of the Borrower or any Subsidiary located in the
United States of America other than (a) any such facility which in the opinion
of the Board of Directors of the Borrower is not of material importance to the
business conducted by the Borrower and its Subsidiaries taken as a whole, or (b)
any such facility in which interests are held by the Borrower or by one or more
Subsidiaries or by the Borrower and one or more Subsidiaries and by others and
the aggregate interest held by the Borrower and all Subsidiaries does not exceed
50%.
"Private Placement Agreement" means the Note Agreement dated as of December
4, 1991 among the Borrower and various investors pursuant to which the Borrower
issued the Private Placement Debt.
"Private Placement Debt" means the 9.36% Senior Notes due 2011, Series C
issued by the Borrower.
"Productive Property" means any property interest owned by the Borrower or
a Subsidiary in land (including submerged land and rights in and to oil, gas and
mineral leases) located in the United States of America and classified by the
Borrower or such Subsidiary, as the case may be, as productive of crude oil,
natural gas or other petroleum hydrocarbons in paying quantities; provided that
such term shall not include any exploration or production facilities on said
land, including any drilling or producing platform.
"Property" of a Person means any and all property, whether real, personal,
tangible, intangible, or mixed, of such Person, or other assets owned, leased or
operated by such Person.
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"Purchasers" is defined in Section 12.3.1.
"Regulation D" means Regulation D of the Board of Governors of the Federal
Reserve System as from time to time in effect and any successor thereto or other
regulation or official interpretation of said Board of Governors relating to
reserve requirements applicable to member banks of the Federal Reserve System.
"Regulation U" means Regulation U of the Board of Governors of the Federal
Reserve System as from time to time in effect and any successor or other
regulation or official interpretation of said Board of Governors relating to the
extension of credit by banks for the purpose of purchasing or carrying margin
stocks applicable to member banks of the Federal Reserve System.
"Reportable Event" means a reportable event as defined in Section 4043 of
ERISA and the regulations issued under such section, with respect to a Plan,
excluding, however, such events as to which the PBGC has by regulation waived
the requirement of Section 4043(a) of ERISA that it be notified within 30 days
of the occurrence of such event, provided that a failure to meet the minimum
funding standard of Section 412 of the Code and of Section 302 of ERISA shall be
a Reportable Event regardless of the issuance of any such waiver of the notice
requirement in accordance with either Section 4043(a) of ERISA or Section 412(d)
of the Code.
"Required Lenders" means Lenders in the aggregate having at least 66-2/3%
of the Aggregate Commitment or, if the Aggregate Commitment has been terminated,
Lenders in the aggregate holding at least 66-2/3% of the aggregate unpaid
principal amount of the outstanding Advances.
"Reserve Requirement" means, with respect to an Interest Period, the daily
average during such Interest Period of the maximum aggregate reserve requirement
(including all basic, supplemental, marginal and other reserves) which is
imposed under Regulation D on Eurocurrency liabilities.
"Sale and Leaseback Transaction" means any sale or other transfer of
Property by any Person with the intent to lease such Property as lessee.
"Schedule" refers to a specific schedule to this Agreement, unless another
document is specifically referenced.
"SEC" means the Securities and Exchange Commission.
"Section" means a numbered section of this Agreement, unless another
document is specifically referenced.
"Significant Subsidiary" means, as of any date of determination, each
Subsidiary of the Borrower that meets any of the following criteria:
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(i) the Borrower's and its other Subsidiaries' Investments in and to
such Subsidiary (and its respective Subsidiaries), as shown in the
consolidated financial statements of the Borrower and its Subsidiaries
prepared as of the end of the fiscal quarter ended most recently prior to
such date of determination, exceed 10% of the total consolidated assets of
the Borrower and its Subsidiaries; or
(ii) the assets of such Subsidiary (and its respective Subsidiaries)
represent more than 10% of the consolidated assets of the Borrower and its
Subsidiaries as would be shown in the consolidated financial statements
referred to in clause (i) above; or
(iii) such Subsidiary (and its respective Subsidiaries) is responsible
for more than 10% of the consolidated net sales or of the consolidated net
income of the Borrower and its Subsidiaries as reflected in the financial
statements referred to in clause (i) above;
provided that each such determination of such sales or assets shall be made
after deducting all intercompany transactions which, in accordance with
Agreement Accounting Principles, would be eliminated in preparing consolidated
financial statements for the Borrower and its Subsidiaries.
"Single Employer Plan" means a Plan maintained by the Borrower or any
member of the Controlled Group for employees of the Borrower or any member of
the Controlled Group.
"Stockholders' Equity" means the Borrower's stockholders' equity,
determined in accordance with Agreement Accounting Principles, but without
giving effect to (1) any non-cash charge after the date hereof resulting from
any write-down of the Borrower's oil and gas properties to the full cost ceiling
limitations required by the full cost method of accounting for such properties
and (ii) any non-cash gain or loss on any hedging agreement resulting from the
requirements of SFAS 133.
"Subsidiary" of a Person means (i) any corporation more than 50% of the
outstanding securities having ordinary voting power of which shall at the time
be owned or controlled, directly or indirectly, by such Person or by one or more
of its Subsidiaries or by such Person and one or more of its Subsidiaries, or
(ii) any partnership, limited liability company, association, joint venture or
similar business organization more than 50% of the ownership interests having
ordinary voting power of which shall at the time be so owned or controlled.
Unless otherwise expressly provided, all references herein to a "Subsidiary"
shall mean a Subsidiary of the Borrower.
"Syndication Agent" means Bank of America, N.A. in its capacity as
syndication agent for the Lenders pursuant to Article X, and not in its
individual capacity as Lender.
"Taxes" means any and all present or future taxes, duties, levies, imposts,
deductions, charges or withholdings, and any and all liabilities with respect to
the foregoing, but excluding Excluded Taxes and Other Taxes.
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"Total Debt" means all Indebtedness of the Borrower and its Subsidiaries,
determined on a consolidated basis in accordance with Agreement Accounting
Principles.
"Transaction Rate" means, for any day, a rate per annum equal to the higher
of the rate quoted by the Administrative Agent and the rate quoted by the
Syndication Agent, in each case for a loan to the Borrower, for the relevant
Transaction Rate Interest Period, pursuant to procedures agreed to among the
Borrower and the Agents.
"Transaction Rate Advance" means an Advance which, except as otherwise
provided in Section 2.12, bears interest at the applicable Transaction Rate.
"Transaction Rate Interest Period" means a period of not less than 1 nor
more than 180 days, commencing on a Business Day, agreed to by the Borrower, the
Administrative Agent and the Syndication Agent at the time of establishing the
Transaction Rate for such period. If any Transaction Rate Interest Period would
end on a day which is not a Business Day, such Transaction Rate Interest Period
shall end on the next succeeding Business Day.
"Transaction Rate Loan" means a Loan which, except as otherwise provided in
Section 2.12, bears interest at a Transaction Rate.
"Transferee" is defined in Section 12.4.
"Type" means, with respect to any Advance, its nature as a Floating Rate
Advance, a Eurodollar Advance or a Transaction Rate Advance.
"Unmatured Default" means an event which but for the lapse of time or the
giving of notice, or both, would, unless cured or waived, constitute a Default.
"Wholly-Owned Subsidiary" of a Person means (i) any Subsidiary all of the
outstanding voting securities of which shall at the time be owned or controlled,
directly or indirectly, by such Person or one or more Wholly-Owned Subsidiaries
of such Person, or by such Person and one or more Wholly-Owned Subsidiaries of
such Person, or (ii) any partnership, limited liability company, association,
joint venture or similar business organization 100% of the ownership interests
having ordinary voting power of which shall at the time be so owned or
controlled.
The foregoing definitions shall be equally applicable to both the singular
and plural forms of the defined terms.
ARTICLE II
THE CREDITS
2.1 Commitment. From and including the date of this Agreement and to the
Final Maturity Date, each Lender severally agrees, on the terms and conditions
set forth in this
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Agreement (including Section 4.2(iv) and (v)), to make Loans to the Borrower
from time to time in amounts not to exceed in the aggregate at any one time
outstanding the amount of its Commitment. Subject to the terms of this
Agreement, the Borrower may borrow, repay and reborrow at any time prior to the
Final Maturity Date.
2.2 Required Payments; Maturity. Any outstanding Advances and all other
unpaid Obligations shall be paid in full by the Borrower on the Final Maturity
Date or such other date required by Section 2.8 below.
2.3 Ratable Loans. Each Advance hereunder shall consist of Loans made from
the several Lenders ratably in proportion to the ratio that their respective
Commitments bear to the Aggregate Commitment.
2.4 Types of Advances. The Advances may be Floating Rate Advances,
Eurodollar Advances or Transaction Rate Advances, or a combination thereof,
selected by the Borrower in accordance with Sections 2.9 and 2.10; provided that
not more than $20,000,000 of Transaction Rate Advances shall be outstanding at
any time.
2.5 Commitment Fee; Voluntary Reductions in Aggregate Commitment. The
Borrower agrees to pay to the Administrative Agent for the account of each
Lender a commitment fee at a per annum rate equal to 0.375% on the daily unused
portion of such Lender's Commitment from the date hereof to and including the
Final Maturity Date, payable on each Payment Date hereafter and on the Final
Maturity Date. The Borrower may permanently reduce the Aggregate Commitment in
whole, or in part ratably among the Lenders, in integral multiples of
$1,000,000, upon at least three Business Days' written notice to the
Administrative Agent, which notice shall specify the amount of any such
reduction, provided that the amount of the Aggregate Commitment may not be
reduced below the aggregate principal amount of the outstanding Advances. All
accrued commitment fees shall be payable on the effective date of any
termination of the obligations of the Lenders to make Loans hereunder.
2.6 Minimum Amount of Each Advance. Each Eurodollar Advance shall be in the
minimum amount of $750,000 (and in multiples of $50,000 if in excess thereof),
and each Floating Rate Advance and Transaction Rate Advance shall be in the
minimum amount of $500,000 (and in multiples of $50,000 if in excess thereof),
provided that any Floating Rate Advance or Transaction Rate Advance may be in
the amount of the unused Aggregate Commitment.
2.7 Mandatory Reductions in Aggregate Commitment. (a) Within five Business
Days after the receipt by the Borrower or any Subsidiary of the Net Cash
Proceeds of any Asset Sale, the Aggregate Commitment shall be reduced by an
amount equal to such Net Cash Proceeds; provided that (x) no such reduction
shall be required unless the aggregate amount of all Net Cash Proceeds
(excluding any Net Cash Proceeds previously applied to reduce the Aggregate
Commitment pursuant to this Section) received since the date of this Agreement
equals or exceeds $1,000,000; and (y) the amount of Net Cash Proceeds to be
applied on any single
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occasion shall be rounded down to an integral multiple of $100,000 (it being
understood that the amount of Net Cash Proceeds in excess of any such integral
multiple shall be applied on the next date on which Net Cash Proceeds are
applied).
(b) In addition to any reduction of the Aggregate Commitment pursuant to
clause (a) above, if the Private Placement has not been repaid on or before
September 12, 2000, the Aggregate Commitment shall be reduced on such date by an
amount equal to the excess, if any, of $25,000,000 over the aggregate amount of
all previous voluntary reductions of the Aggregate Commitment pursuant to
Section 2.5.
(c) In addition to any reduction of the Aggregate Commitment pursuant to
clause (a) or (b) above, the Aggregate Commitment shall be reduced to zero on
the date of the occurrence of a sale by the Borrower of the capital stock of
Arkansas Western Gas Company, or any sale of all or substantially all of the
assets, of Arkansas Western Gas Company.
2.8 Prepayments. (a) The Borrower may from time to time prepay, without
penalty or premium, all outstanding Floating Rate Advances or Transaction Rate
Advances, or, in a minimum aggregate amount of $1,000,000 or any integral
multiple of $500,000 in excess thereof, any portion of the outstanding Floating
Rate Advances or Transaction Rate Advances upon notice to the Administrative
Agent not later than 10:00 a.m. (Chicago time) on the date of prepayment. The
Borrower may from time to time prepay, without penalty or premium, all
outstanding Eurodollar Advances, or, in a minimum aggregate amount of $1,000,000
or any integral multiple of $1,000,000 in excess thereof, any portion of the
outstanding Eurodollar Advances upon three Business Days' prior notice to the
Administrative Agent.
(b) On any date on which the Aggregate Commitment is reduced pursuant to
Section 2.7, the Borrower shall make a prepayment of Advances in the amount, if
any, by which the aggregate principal amount of all outstanding Advances exceeds
the Aggregate Commitment. Any partial prepayment pursuant to this clause (b)
shall be applied to such Advances as the Borrower may direct or, in the absence
of such direction, as the Administrative Agent may reasonably determine as so
reduced.
(c) Any prepayment of a Eurodollar Loan or a Transaction Rate Loan on a day
other than the last day of an Interest Period therefor shall be subject to
Section 3.4.
2.9 Method of Selecting Types and Interest Periods for New Advances. The
Borrower shall select the Type of Advance and, in the case of each Eurodollar
Advance and Transaction Rate Advance, the Interest Period applicable thereto
from time to time. The Borrower shall give the Administrative Agent irrevocable
notice (a "Borrowing Notice") not later than 10:00 a.m. (Chicago time) on the
Borrowing Date of each Floating Rate Advance or Transaction Rate Advance and
three Business Days before the Borrowing Date of each Eurodollar Advance,
specifying:
(i) the Borrowing Date, which shall be a Business Day, of such Advance,
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(ii) the aggregate amount of such Advance,
(iii) the Type of Advance selected, and
(iv) in the case of each Eurodollar Advance and Transaction Rate Advance,
the Interest Period applicable thereto.
Each Borrowing Notice for a Floating Rate Advance or a Eurodollar Advance shall
be in writing (or by telephone promptly confirmed in writing) substantially in
the form of Exhibit A.
Not later than noon (Chicago time) on each Borrowing Date, each Lender shall
make available its Loan or Loans in funds immediately available in Chicago to
the Administrative Agent at its address specified pursuant to Article XIII. The
Administrative Agent will make the funds so received from the Lenders available
to the Borrower at the Administrative Agent's aforesaid address.
2.10 Conversion and Continuation of Outstanding Advances. Floating Rate
Advances shall continue as Floating Rate Advances unless and until such Floating
Rate Advances are converted into Eurodollar Advances pursuant to this Section
2.10 or are repaid in accordance with Section 2.8. Each Eurodollar Advance and
Transaction Rate Advance shall continue as a Eurodollar Advance or Transaction
Rate Advance, as the case may be, until the end of the then applicable Interest
Period therefor, at which time such Eurodollar Advance or Transaction Rate
Advance shall be automatically converted into a Floating Rate Advance unless (x)
such Advance is or was repaid in accordance with Section 2.8 or (y) the Borrower
shall have given the Administrative Agent a Conversion/Continuation Notice (as
defined below) requesting that, at the end of such Interest Period, such Advance
continue as a Eurodollar Advance or a Transaction Rate Advance, as applicable,
for the same or another Interest Period. Subject to the terms of Section 2.6,
the Borrower may elect from time to time to convert all or any part of any
Advance into an Advance of another Type. The Borrower shall give the
Administrative Agent irrevocable notice (a "Conversion/Continuation Notice") of
each continuation or conversion of an Advance (other than an automatic
continuation or conversion as provided in this Section 2.10) not later than the
time specified in Section 2.9 for the making of the Type of Advance to be
continued or converted into, specifying:
(i) the requested date, which shall be a Business Day, of such conversion
or continuation,
(ii) the aggregate amount and Type of the Advance which is to be converted
or continued,
(iii) in the case of conversion of an Advance, the Type of Advance to be
converted into,
(iv) the amount of such Advance which is to be converted or continued, and
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(v) in the case of conversion into or continuation of a Eurodollar
Advance or a Transaction Rate Advance, the duration of the
Interest Period applicable thereto.
Each Conversion/Continuation Notice given by the Borrower shall constitute a
representation and warranty by the Borrower that no Default or Unmatured Default
exists.
2.11 Changes in Interest Rate, etc. Each Floating Rate Advance shall bear
interest on the outstanding principal amount thereof, for each day from and
including the date such Advance is made or is converted from another Type of
Advance into a Floating Rate Advance pursuant to Section 2.10, to but excluding
the date it is paid or is converted into another Type of Advance pursuant to
Section 2.10, at a rate per annum equal to the Floating Rate for such day.
Changes in the rate of interest on that portion of any Advance maintained as a
Floating Rate Advance will take effect simultaneously with each change in the
Alternate Base Rate. Each Eurodollar Advance and Transaction Rate Advance shall
bear interest on the outstanding principal amount thereof from and including the
first day of the Interest Period applicable thereto to (but not including) the
last day of such Interest Period at the interest rate determined by the
Administrative Agent as applicable to such Eurodollar Advance and Transaction
Rate Advance based upon the Borrower's selections under Sections 2.9 and 2.10
and otherwise in accordance with the terms hereof. No Interest Period may end
after the Final Maturity Date.
2.12 Rates Applicable After Default. Notwithstanding anything to the
contrary contained in Section 2.9 or 2.10, during the continuance of a Default
or Unmatured Default the Required Lenders may, at their option, by notice to the
Borrower (which notice may be revoked at the option of the Required Lenders
notwithstanding any provision of Section 8.2 requiring unanimous consent of the
Lenders to changes in interest rates), declare that no Advance may be made as,
converted into or continued as a Eurodollar Advance or a Transaction Rate
Advance. During the continuance of a Default the Required Lenders may, at their
option, by notice to the Borrower (which notice may be revoked at the option of
the Required Lenders notwithstanding any provision of Section 8.2 requiring
unanimous consent of the Lenders to changes in interest rates), declare that (i)
each Eurodollar Advance and Transaction Rate Advance shall bear interest for the
remainder of the applicable Interest Period at the rate otherwise applicable to
such Interest Period plus 2% per annum and (ii) each Floating Rate Advance shall
bear interest at a rate per annum equal to the Floating Rate in effect from time
to time plus 2% per annum, provided that, during the continuance of a Default
under Section 7.1.6 or 7.1.7, the interest rates set forth in clauses (i) and
(ii) above shall be applicable to all Advances without any election or action on
the part of either Agent or any Lender.
2.13 Method of Payment. All payments of the Obligations hereunder shall be
made, without setoff, deduction, or counterclaim, in immediately available funds
to the Administrative Agent at the Administrative Agent's address specified
pursuant to Article XIII, or at any other Lending Installation of the
Administrative Agent specified in writing by the Administrative Agent to the
Borrower, by noon (local time) on the date when due and shall be applied ratably
by the Administrative Agent among the Lenders. Each payment delivered to the
Administrative Agent for the account of any Lender shall be delivered promptly
by the Administrative Agent to
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such Lender in the same type of funds that the Administrative Agent received at
its address specified pursuant to Article XIII or at any Lending Installation
specified in a notice received by the Administrative Agent from such Lender. The
Administrative Agent is hereby authorized to charge the account of the Borrower
maintained with Bank One for each payment of principal, interest and fees as it
becomes due hereunder.
2.14 Noteless Agreement; Evidence of Indebtedness. (i) Each Lender shall
maintain in accordance with its usual practice an account or accounts evidencing
the indebtedness of the Borrower to such Lender resulting from each Loan made by
such Lender from time to time, including the amounts of principal and interest
payable and paid to such Lender from time to time hereunder.
(ii) The Administrative Agent shall also maintain accounts in which it will
record (a) the amount of each Loan made hereunder, the Type thereof and the
Interest Period with respect thereto, (b) the amount of any principal or
interest due and payable or to become due and payable from the Borrower to each
Lender hereunder and (c) the amount of any sum received by the Administrative
Agent hereunder from the Borrower and each Lender's share thereof.
(iii) The entries maintained in the accounts maintained pursuant to
paragraphs (i) and (ii) above shall be prima facie evidence of the existence and
amounts of the Obligations therein recorded; provided that the failure of the
Administrative Agent or any Lender to maintain such accounts or any error
therein shall not in any manner affect the obligation of the Borrower to repay
the Obligations in accordance with their terms.
(iv) Any Lender may request that its Loans be evidenced by a Note. In such
event, the Borrower shall prepare, execute and deliver to such Lender a Note
payable to the order of such Lender in a form supplied by the Administrative
Agent substantially in the form of Exhibit E. Thereafter, the Loans evidenced by
such Note and interest thereon shall at all times (including after any
assignment pursuant to Section 12.3) be represented by one or more Notes payable
to the order of the payee named therein or any assignee pursuant to Section
12.3, except to the extent that any such Lender or assignee subsequently returns
any such Note for cancellation and requests that such Loans once again be
evidenced as described in paragraphs (i) and (ii) above.
2.15 Telephonic Notices. The Borrower hereby authorizes the Lenders and the
Administrative Agent to extend, convert or continue Advances, effect selections
of Types of Advances and to transfer funds based on telephonic notices made by
any person or persons the Administrative Agent or any Lender in good faith
believes to be acting on behalf of the Borrower, it being understood that the
foregoing authorization is specifically intended to allow Borrowing Notices and
Conversion/Continuation Notices to be given telephonically. The Borrower agrees
to deliver promptly to the Administrative Agent a written confirmation, if such
confirmation is requested by the Administrative Agent or any Lender, of each
telephonic notice signed by an Authorized Officer. If the written confirmation
differs in any material respect from the action taken by the Administrative
Agent and the Lenders, the records of the Administrative Agent and the Lenders
shall govern absent manifest error.
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2.16 Interest Payment Dates; Interest and Fee Basis. Interest accrued on
each Floating Rate Advance shall be payable on each Payment Date, commencing
with the first such date to occur after the date hereof, on any date on which
the Floating Rate Advance is prepaid, whether due to acceleration or otherwise,
or is converted into another Type of Advance, and at maturity. Interest accrued
on each Eurodollar Advance and Transaction Rate Advance shall be payable on the
last day of each applicable Interest Period, on any date on which such Advance
is prepaid, whether by acceleration or otherwise, or is converted into another
Type of Advance, and at maturity. Interest accrued on each Eurodollar Advance
and Transaction Rate Advance having an Interest Period longer than three months
shall also be payable on the last day of each three-month interval during such
Interest Period. Interest and commitment fees shall be calculated for actual
days elapsed on the basis of a 360-day year, except that interest accruing at
the Prime Rate shall be calculated for actual days elapsed on the basis of a
365, or when appropriate 366, day year. Interest shall be payable for the day an
Advance is made but not for the day of any payment on the amount paid if payment
is received prior to noon (local time) at the place of payment. If any payment
of principal of or interest on an Advance shall become due on a day which is not
a Business Day, such payment shall be made on the next succeeding Business Day
and, in the case of a principal payment, such extension of time shall be
included in computing interest in connection with such payment.
2.17 Notification of Advances, Interest Rates, Prepayments and Commitment
Reductions. Promptly after receipt thereof, the Administrative Agent will notify
each Lender of the contents of each Aggregate Commitment reduction notice,
Borrowing Notice, Conversion/Continuation Notice, and repayment notice received
by it hereunder. The Administrative Agent will notify each Lender of the
interest rate applicable to each Eurodollar Advance and Transaction Rate Advance
promptly upon determination of such interest rate and will give each Lender
prompt notice of each change in the Alternate Base Rate.
2.18 Lending Installations. Each Lender may book its Loans at any Lending
Installation selected by such Lender and may change its Lending Installation
from time to time. All terms of this Agreement shall apply to any such Lending
Installation and the Loans and any Notes issued hereunder shall be deemed held
by each Lender for the benefit of any such Lending Installation. Each Lender
may, by written notice to the Administrative Agent and the Borrower in
accordance with Article XIII, designate replacement or additional Lending
Installations through which Loans will be made by it and for whose account Loan
payments are to be made.
2.19 Non-Receipt of Funds by the Administrative Agent. Unless the Borrower
or a Lender, as the case may be, notifies the Administrative Agent prior to the
date on which it is scheduled to make payment to the Administrative Agent of (i)
in the case of a Lender, the proceeds of a Loan or (ii) in the case of the
Borrower, a payment of principal, interest or fees to the Administrative Agent
for the account of the Lenders, that it does not intend to make such payment,
the Administrative Agent may assume that such payment has been made. The
Administrative Agent may, but shall not be obligated to, make the amount of such
payment available to the intended recipient in reliance upon such assumption. If
such Lender or the Borrower, as the case may be, has not in fact made such
payment to the Administrative Agent,
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the recipient of such payment shall, on demand by the Administrative Agent,
repay to the Administrative Agent the amount so made available together with
interest thereon in respect of each day during the period commencing on the date
such amount was so made available by the Administrative Agent until the date the
Administrative Agent recovers such amount at a rate per annum equal to (x) in
the case of payment by a Lender, the Federal Funds Effective Rate for such day
for the first three days and, thereafter, the interest rate applicable to the
relevant Loan or (y) in the case of payment by the Borrower, the interest rate
applicable to the relevant Loan.
2.20 Replacement of Lender. If the Borrower is required pursuant to Section
3.1, 3.2 or 3.5 to make any additional payment to any Lender or if any Lender's
obligation to make or continue, or to convert Advances into, Eurodollar Advances
shall be suspended pursuant to Section 3.3 (any Lender so affected an "Affected
Lender"), the Borrower may elect, if such amounts continue to be charged or such
suspension is still effective, to replace such Affected Lender as a Lender party
to this Agreement, provided that no Default or Unmatured Default shall have
occurred and be continuing at the time of such replacement, and provided,
further, that, concurrently with such replacement, (i) another bank or other
entity which is reasonably satisfactory to the Borrower and the Administrative
Agent shall agree, as of such date, to purchase for cash the Advances and other
Obligations due to the Affected Lender pursuant to an assignment substantially
in the form of Exhibit C and to become a Lender for all purposes under this
Agreement and to assume all obligations of the Affected Lender to be terminated
as of such date and to comply with the requirements of Section 12.3 applicable
to assignments, and (ii) the Borrower shall pay to such Affected Lender in same
day funds on the day of such replacement (A) all interest, fees and other
amounts then accrued but unpaid to such Affected Lender by the Borrower
hereunder to and including the date of termination, including without limitation
payments due to such Affected Lender under Sections 3.1, 3.2 and 3.5, and (B) an
amount, if any, equal to the payment which would have been due to such Lender on
the day of such replacement under Section 3.4 had the Loans of such Affected
Lender been prepaid on such date rather than sold to the replacement Lender.
ARTICLE III
YIELD PROTECTION; TAXES
3.1 Yield Protection. (a) If, on or after the date of this Agreement, (x)
the adoption of or any change in any law or any governmental or
quasi-governmental rule, regulation, policy, guideline or directive (whether or
not having the force of law), or (y) any change in the interpretation or
administration thereof by any governmental or quasi-governmental authority,
central bank or comparable agency charged with the interpretation or
administration thereof, or (z) compliance by any Lender or applicable Lending
Installation with any request or directive (whether or not having the force of
law) issued on or after the date hereof of any such authority, central bank or
comparable agency:
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(i) subjects any Lender or any applicable Lending Installation to any
Taxes, or changes the basis of taxation of payments (other than
with respect to Excluded Taxes) to any Lender in respect of its
Eurodollar Loans, or
(ii) imposes or increases or deems applicable any reserve, assessment,
insurance charge, special deposit or similar requirement against
assets of, deposits with or for the account of, or credit
extended by, any Lender or any applicable Lending Installation
(other than reserves and assessments taken into account in
determining the interest rate applicable to Eurodollar Advances),
or
(iii) imposes any other condition the result of which is to increase
the cost to any Lender or any applicable Lending Installation of
making, funding or maintaining its Eurodollar Loans or reduces
any amount receivable by any Lender or any applicable Lending
Installation in connection with its Eurodollar Loans, or requires
any Lender or any applicable Lending Installation to make any
payment calculated by reference to the amount of Eurodollar Loans
held or interest received by it, by an amount deemed material by
such Lender,
and the result of any of the foregoing is to increase the cost to such Lender or
applicable Lending Installation of making or maintaining its Eurodollar Loans or
Commitment or to reduce the return received by such Lender or applicable Lending
Installation in connection with such Eurodollar Loans or Commitment, then,
within 15 days of demand by such Lender, the Borrower shall pay such Lender such
additional amount or amounts as will compensate such Lender for such increased
cost or reduction in amount received. A Lender shall not be entitled to demand
compensation or be compensated hereunder to the extent that such compensation
relates to any period of time more than 60 days prior to the date upon which
such Lender first notified the Borrower of the occurrence of the event entitling
such Lender to such compensation (unless, and to the extent, that any such
compensation so demanded shall relate to the retroactive application of any
event so notified to the Borrower).
(b) Without limiting clause (a) above, any Lender may require the Borrower
to pay, contemporaneously with each payment of interest on any Eurodollar Loan
of such Lender, additional interest on such Eurodollar Loan at a rate per annum
determined by such Lender up to but not exceeding the excess of (i) (A) the
applicable Eurodollar Base Rate divided by (B) one minus the Reserve Requirement
over (ii) the applicable Eurodollar Base Rate. Any Lender wishing to require
payment of such additional interest (x) shall so notify the Borrower and the
Administrative Agent, in which case such additional interest on the Eurodollar
Loans of such Lender shall be payable to such Lender at the place indicated in
such notice with respect to each Interest Period commencing at least three
Business Days after the giving of such notice and (y) shall notify the Borrower
at least five Business Days prior to each date on which interest is payable on
any Eurodollar Loan of the amount then due it under this Section.
3.2 Changes in Capital Adequacy Regulations. If a Lender determines the
amount of capital required or expected to be maintained by such Lender, any
Lending Installation of such
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Lender or any corporation controlling such Lender is increased as a result of a
Change, then, within 15 days of demand by such Lender, the Borrower shall pay
such Lender the amount necessary to compensate for any shortfall in the rate of
return on the portion of such increased capital which such Lender determines is
attributable to this Agreement, its Loans or its Commitment to make Loans
hereunder (after taking into account such Lender's policies as to capital
adequacy). "Change" means (i) any change after the date of this Agreement in the
Risk-Based Capital Guidelines or (ii) any adoption of or change in any other
law, governmental or quasi-governmental rule, regulation, policy, guideline,
interpretation, or directive (whether or not having the force of law) after the
date of this Agreement which affects the amount of capital required or expected
to be maintained by any Lender or any Lending Installation or any corporation
controlling any Lender. "Risk-Based Capital Guidelines" means (i) the risk-based
capital guidelines in effect in the United States on the date of this Agreement,
including transition rules, and (ii) the corresponding capital regulations
promulgated by regulatory authorities outside the United States implementing the
July 1988 report of the Basle Committee on Banking Regulation and Supervisory
Practices Entitled "International Convergence of Capital Measurements and
Capital Standards," including transition rules, and any amendments to such
regulations adopted prior to the date of this Agreement.
3.3 Availability of Types of Advances. If any Lender reasonably determines
that maintenance of its Eurodollar Loans at a suitable Lending Installation
would violate any applicable law, rule, regulation, or directive, whether or not
having the force of law, or if the Required Lenders reasonably determine that
(i) deposits of a type and maturity appropriate to match fund Eurodollar
Advances are not available or (ii) the Eurodollar Base Rate does not accurately
reflect the cost of obtaining funds to make or maintain Eurodollar Advances,
then the Administrative Agent shall suspend the availability of Eurodollar
Advances and require any affected Eurodollar Advances to be repaid or converted
to Floating Rate Advances (on or before the date required by such law, rule,
regulation or directive), subject to the payment of any funding indemnification
amounts required by Section 3.4.
3.4 Funding Indemnification. If any payment of a Eurodollar Advance or a
Transaction Rate Advance occurs on a date which is not the last day of the
applicable Interest Period, whether because of acceleration, prepayment or
otherwise, or a Eurodollar Advance or a Transaction Rate Advance is not made on
the date specified by the Borrower for any reason other than default by the
Lenders, the Borrower will indemnify each Lender for any loss or cost incurred
by it resulting therefrom, including, without limitation, any loss or cost in
liquidating or employing deposits acquired to fund or maintain such Eurodollar
Advance or a Transaction Rate Advance.
3.5 Taxes. (i) All payments by the Borrower to or for the account of any
Lender or the Administrative Agent hereunder or under any Note shall be made
free and clear of and without deduction for any and all Taxes. If the Borrower
shall be required by law to deduct any Taxes from or in respect of any sum
payable hereunder to any Lender or either Agent, (a) the sum payable shall be
increased as necessary so that after making all required deductions (including
deductions applicable to additional sums payable under this Section 3.5) such
Lender
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or such Agent (as the case may be) receives an amount equal to the sum it would
have received had no such deductions been made, (b) the Borrower shall make such
deductions, (c) the Borrower shall pay the full amount deducted to the relevant
authority in accordance with applicable law and (d) the Borrower shall furnish
to the Administrative Agent the original copy of a receipt evidencing payment
thereof within 30 days after such payment is made.
(ii) In addition, the Borrower hereby agrees to pay any present or future
stamp or documentary taxes and any other excise or property taxes, charges or
similar levies which arise from any payment made hereunder or under any Note or
from the execution or delivery of, or otherwise with respect to, this Agreement
or any Note ("Other Taxes").
(iii) The Borrower hereby agrees to indemnify each Agent and each Lender
for the full amount of Taxes or Other Taxes (including, without limitation, any
Taxes or Other Taxes imposed on amounts payable under this Section 3.5) paid by
such Agent or such Lender and any liability (including penalties, interest and
expenses) arising therefrom or with respect thereto. Payments due under this
indemnification shall be made within 30 days of the date such Agent or such
Lender makes demand therefor pursuant to Section 3.6.
(iv) Each Lender that is not incorporated under the laws of the United
States of America or a state thereof (each a "Non-U.S. Lender") agrees that it
will, not less than ten Business Days after the date of this Agreement, (i)
deliver to each of the Borrower and the Administrative Agent two duly completed
copies of United States Internal Revenue Service Form W-8 BEN or W-8 ECI,
certifying in either case that such Lender is entitled to receive payments under
this Agreement without deduction or withholding of any United States federal
income taxes, and (ii) deliver to each of the Borrower and the Administrative
Agent a United States Internal Revenue Form W-8 or W-9, as the case may be, and
certify that it is entitled to an exemption from United States backup
withholding tax. Each Non-U.S. Lender further undertakes to deliver to each of
the Borrower and the Administrative Agent (x) renewals or additional copies of
such form (or any successor form) on or before the date that such form expires
or becomes obsolete, and (y) after the occurrence of any event requiring a
change in the most recent forms so delivered by it, such additional forms or
amendments thereto as may be reasonably requested by the Borrower or the
Administrative Agent. All forms or amendments described in the preceding
sentence shall certify that such Lender is entitled to receive payments under
this Agreement without deduction or withholding of any United States federal
income taxes, unless an event (including without limitation any change in
treaty, law or regulation) has occurred prior to the date on which any such
delivery would otherwise be required which renders all such forms inapplicable
or which would prevent such Lender from duly completing and delivering any such
form or amendment with respect to it and such Lender advises the Borrower and
the Administrative Agent that it is not capable of receiving payments without
any deduction or withholding of United States federal income tax.
(v) For any period during which a Non-U.S. Lender has failed to provide the
Borrower with an appropriate form pursuant to clause (iv), above (unless such
failure is due to a change in treaty, law or regulation, or any change in the
interpretation or administration thereof by any
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governmental authority, occurring subsequent to the date on which a form
originally was required to be provided), such Non-U.S. Lender shall not be
entitled to indemnification under this Section 3.5 with respect to Taxes imposed
by the United States; provided that, should a Non-U.S. Lender which is otherwise
exempt from or subject to a reduced rate of withholding tax become subject to
Taxes because of its failure to deliver a form required under clause (iv),
above, the Borrower shall take such steps as such Non-U.S. Lender shall
reasonably request to assist such Non-U.S. Lender to recover such Taxes.
(vi) Any Lender that is entitled to an exemption from or reduction of
withholding tax with respect to payments under this Agreement or any Note
pursuant to the law of any relevant jurisdiction or any treaty shall deliver to
the Borrower (with a copy to the Administrative Agent), at the time or times
prescribed by applicable law, such properly completed and executed documentation
prescribed by applicable law as will permit such payments to be made without
withholding or at a reduced rate.
(vii) If the U.S. Internal Revenue Service or any other governmental
authority of the United States or any other country or any political subdivision
thereof asserts a claim that the Administrative Agent did not properly withhold
tax from amounts paid to or for the account of any Lender (because the
appropriate form was not delivered or properly completed, because such Lender
failed to notify the Administrative Agent of a change in circumstances which
rendered its exemption from withholding ineffective, or for any other reason),
such Lender shall indemnify the Administrative Agent fully for all amounts paid,
directly or indirectly, by the Administrative Agent as tax, withholding
therefor, or otherwise, including penalties and interest, and including taxes
imposed by any jurisdiction on amounts payable to the Administrative Agent under
this subsection, together with all costs and expenses related thereto (including
attorneys fees and time charges of attorneys for the Administrative Agent, which
attorneys may be employees of the Administrative Agent). The obligations of the
Lenders under this Section 3.5(vii) shall survive the payment of the Obligations
and termination of this Agreement.
3.6 Lender Statements; Survival of Indemnity. To the extent reasonably
possible, each Lender shall designate an alternate Lending Installation with
respect to its Eurodollar Loans to reduce any liability of the Borrower to such
Lender under Sections 3.1, 3.2 and 3.5 or to avoid the unavailability of
Eurodollar Advances under Section 3.3, so long as such designation is not, in
the reasonable judgment of such Lender, disadvantageous to such Lender. Each
Lender shall deliver a written statement of such Lender to the Borrower (with a
copy to the Administrative Agent) as to the amount due, if any, under Section
3.1, 3.2, 3.4 or 3.5. Such written statement shall set forth in reasonable
detail the calculations upon which such Lender determined such amount and shall
be rebuttable presumptive evidence of the amount thereof. Determination of
amounts payable under such Sections in connection with a Eurodollar Loan shall
be calculated as though each Lender funded its Eurodollar Loan through the
purchase of a deposit of the type and maturity corresponding to the deposit used
as a reference in determining the Eurodollar Base Rate applicable to such Loan,
whether in fact that is the case or not. Determination of amounts payable under
Section 3.4 in connection with any Transaction Rate Loan may be made by the
applicable Lender on any reasonable method. Unless otherwise provided herein,
the amount
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specified in the written statement of any Lender shall be payable on demand
after receipt by the Borrower of such written statement. The obligations of the
Borrower under Sections 3.1, 3.2, 3.4 and 3.5 shall survive payment of the
Obligations and termination of this Agreement.
ARTICLE IV
CONDITIONS PRECEDENT
4.1 Initial Advance. The Lenders shall not be required to make the initial
Advance hereunder unless (a) concurrently with the making of such Advance, the
Borrower shall have paid in full all principal, interest, fees and other amounts
payable under each of the Credit Agreement dated as of February 28, 1994 between
the Borrower and Bank One (then known as The First National Bank of Chicago),
the Credit Agreement dated as of April 29, 1994 between the Borrower and Bank of
America, N.A. (then known as NationsBank, N.A.) and the Letter of Credit
Agreement dated as of November 16, 1998 among the Borrower, various financial
institutions and Bank One, NA (then known as The First National Bank of Chicago)
and (b) the Borrower shall have furnished to the Administrative Agent with
sufficient copies for the Lenders:
(i) Copies of the articles or certificate of incorporation of the
Borrower, together with all amendments, and a certificate of good
standing, each certified by the appropriate governmental officer in
its jurisdiction of incorporation.
(ii) Copies certified by the Secretary or Assistant Secretary of the
Borrower, of its by-laws and of its Board of Directors' resolutions
and of resolutions or actions of any other body authorizing the
execution of the Loan Documents to which the Borrower is a party.
(iii) An incumbency certificate, executed by the Secretary or Assistant
Secretary of the Borrower, which shall identify by name and title
and bear the signatures of the officers of the Borrower authorized
to sign the Loan Documents to which the Borrower is a party, upon
which certificate the Agents and the Lenders shall be entitled to
rely until informed of any change in writing by the Borrower.
(iv) Evidence, in form and substance satisfactory to the Administrative
Agent, that the Borrower has obtained all governmental approvals
necessary for it to enter into the Loan Documents.
(v) A certificate, signed by an Authorized Officer, stating that on the
initial Borrowing Date (x) no Default or Unmatured Default has
occurred and is continuing and (y) the representatives and
warranties set forth in Article V are true and correct as of such
date.
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(vi) A written opinion of the Borrower's counsel, addressed to the
Lenders in substantially the form of Exhibit B.
(vii) Any Notes requested by a Lender pursuant to Section 2.14 payable to
the order of each such requesting Lender.
(viii) Written money transfer instructions, in substantially the form of
Exhibit D, addressed to the Administrative Agent and signed by an
Authorized Officer, together with such other related money transfer
authorizations as the Administrative Agent may have reasonably
requested.
(ix) Copies, certified as being correct and complete by an Authorized
Officer, of (x) the Private Placement Agreement and (y) the
Indenture dated as of December 1, 1995, between the Borrower and
Bank One (then known as The First National Bank of Chicago), as
trustee, and all supplements thereto.
(x) Such other documents as any Lender or its counsel may have
reasonably requested.
4.2 Each Advance. The Lenders shall not be required to make any Advance,
the effect of which is to increase the aggregate amount of Loans outstanding
hereunder, unless on the applicable Borrowing Date:
(i) There exists no Default or Unmatured Default.
(ii) The representations and warranties contained in Article V are true
and correct as of such Borrowing Date except to the extent any such
representation or warranty is stated to relate solely to an earlier
date, in which case such representation or warranty shall have been
true and correct on and as of such earlier date.
(iii) All legal matters incident to the making of such Advance shall be
reasonably satisfactory to the Lenders and their counsel.
(iv) With respect to any Advance which causes the aggregate amount of
outstanding Loans to exceed $45,000,000, Bank One shall be satisfied
that the letter of credit issued under the Letter of Credit
Agreement referred to in Section 4.1(a) will be (x) cancelled
without any drawing thereunder and (y) returned to Bank One on the
date of the making of such Advance.
(v) With respect to any Advance which causes the aggregate amount of
outstanding Loans to exceed the remainder of $155,000,000 minus all
reductions of the Aggregate Commitment previously made pursuant to
Section 2.7(a), written evidence that the Private Placement Debt has
been (or concurrently with the making of such Advance will be) paid
in full.
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Each Borrowing Notice with respect to each such Advance shall constitute a
representation and warranty by the Borrower that the conditions contained in
Sections 4.2(i) and (ii) have been satisfied.
ARTICLE V
REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants to the Lenders that:
5.1 Organization. The Borrower and each of its Subsidiaries are
corporations duly incorporated and validly existing and in good standing under
the laws of the states of their incorporation and have all requisite authority
to conduct their respective businesses in each jurisdiction in which the failure
to have such authority, singly or in the aggregate, could reasonably be expected
to have a Material Adverse Effect. The Borrower and each of its Subsidiaries
have full power and authority to carry on their business as now conducted and
the Borrower has full power and authority to execute, deliver and perform its
obligations under this Agreement.
5.2 Authorization and Validity. The execution and delivery by the Borrower
of this Agreement has been duly authorized by proper corporate proceedings. This
Agreement has been duly executed and delivered by the Borrower and constitutes,
and when executed and delivered by the Borrower each Note will constitute, a
legal, valid and binding obligation of the Borrower enforceable in accordance
with its terms, except as enforceability may be limited by bankruptcy,
insolvency or similar laws affecting the enforcement of creditors' rights
generally.
5.3 Financial Statements. The December 31, 1999 and the March 31, 2000
consolidated financial statements of the Borrower and the Subsidiaries
heretofore delivered to the Agents and the Lenders were prepared in accordance
with generally accepted accounting principles in effect on the date such
statements were prepared and fairly present the financial position and results
of operations of the Borrower and its Subsidiaries at such dates and the
consolidated results of their operations for the periods then ended.
5.4 Subsidiaries. Schedule 5.4 hereto contains an accurate list of all of
the presently existing Subsidiaries, setting forth their respective
jurisdictions of incorporation and the percentage of their respective capital
stock owned by the Borrower or other Subsidiaries. All of the issued and
outstanding shares of capital stock of the Subsidiaries have been duly
authorized and issued and are fully paid and nonassessable.
5.5 ERISA. Each Plan is in material compliance with, and has been
administered in material compliance with, all applicable provisions of ERISA,
the Code and any other applicable federal or state law, except where the failure
to so comply would not (individually or in the aggregate) reasonably be expected
to have a Material Adverse Effect, and no event or condition
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has occurred and is continuing as to which the Borrower is under an obligation
to furnish a report to the Administrative Agent and the Lenders under Section
6.1(d) and which would reasonably be expected (individually or in the aggregate)
to have a Material Adverse Effect.
5.6 Defaults. No Default or Unmatured Default has occurred and is
continuing.
5.7 Accuracy of Information. No information, exhibit or report furnished by
the Borrower or any Subsidiary to the Administrative Agent or any Lender in
connection with the negotiation of this Agreement contains any material
misstatement of fact or omitted to state a material fact necessary to make the
statements contained therein not misleading.
5.8 Regulation U. Neither the Borrower nor any Subsidiary is engaged
principally, or as one of its important activities, in the business of extending
credit for the purpose of purchasing or carrying Margin Stock. Margin Stock
constitutes less than 25% of the consolidated assets of the Borrower and its
Subsidiaries which are subject to any limitation on sale or pledge or any other
restriction hereunder. No part of the proceeds of any Credit will be used to
purchase or carry any Margin Stock in violation of Regulation U.
5.9 No Adverse Change. Except for developments in the Case or as disclosed
in the Quarterly Report on Form 10-Q of the Borrower for the quarterly period
ended March 31, 2000 filed with the Securities and Exchange Commission or the
Forms 8-K of the Borrower filed with the Securities and Exchange Commission on
June 22, 2000 and June 26, 2000, since March 31, 2000 there has been no change
in the business, property, condition (financial or otherwise) or results of
operations of the Borrower and its Subsidiaries which could reasonably be
expected to have a Material Adverse Effect.
5.10 Taxes. The Borrower and its Subsidiaries have filed all United States
federal tax returns and all other tax returns which, to the Knowledge of the
Borrower, are required to be filed and have paid all taxes due pursuant to said
returns or material taxes due pursuant to any assessment received by the
Borrower or any Subsidiary, except in both cases such taxes, if any, as are
being contested in good faith and as to which adequate reserves have been
provided in accordance with Agreement Accounting Principles. The charges,
accruals and reserves on the books of the Borrower and its Subsidiaries in
respect of any taxes or other governmental charges are adequate in accordance
with Agreement Accounting Principles.
5.11 Liens. There are no Liens on any of the properties or assets of the
Borrower or any Subsidiary except (i) Liens permitted by Section 6.3.5 and (ii)
with respect to properties and assets other than Productive Properties,
Principal Transmission Facilities and the stock of any Subsidiary, Liens that
could not, individually or in the aggregate, reasonably be expected to have a
Material Adverse Effect. All easements, rights of way, licenses and other real
property rights required for operation of the businesses of the Borrower and its
Subsidiaries (collectively the "Rights of Way") are owned free and clear of any
Lien, other than Liens permitted by this Agreement and Liens already on any
parcel of real property with respect to which the Rights of Way have been
granted, which will not, in the aggregate, at any time materially detract from
the
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value of the Rights of Way or materially impair the use of the Rights of Way in
the operation of the businesses of the Borrower and its Subsidiaries.
5.12 Compliance with Orders. Neither the Borrower nor any Subsidiary is in
default under the terms of any order of any federal or state court or
administrative agency by which it or any of its properties may be bound, except
for any defaults which could not, individually or in the aggregate, be
reasonably expected to have a Material Adverse Effect.
5.13 Litigation. Except for the Case and as set forth in Schedule 5.13,
there are no actions at law or in equity pending or, to the Knowledge of the
Borrower, threatened involving the likelihood of any judgment or liability
against the Borrower or any Subsidiary which could reasonably be expected to
have a Material Adverse Effect. Except for the investigation arising out of the
1990 rate increase approved by the Arkansas Public Service Commission and
related proceedings, there are no proceedings of any kind or nature pending or,
to the Knowledge of the Borrower, threatened against the Borrower by any federal
or state board or other administrative authority or agency which could
reasonably be expected to have a Material Adverse Effect.
5.14 Burdensome Agreements. The Borrower is not a party to any contract or
agreement which, in the opinion of management of the Borrower, could reasonably
be expected to have a Material Adverse Effect.
5.15 No Conflict. The execution, delivery, and compliance with the terms of
this Agreement will not conflict with or result in the breach of any of the
terms, conditions or provisions of, or constitute a default under, the charter
or bylaws of the Borrower or any Subsidiary, or any indenture, loan agreement or
other agreement or instrument to which the Borrower or any Subsidiary is a party
or by which it may be bound, or result in creation of any Lien on any property
of the Borrower or any Subsidiary, and neither the Borrower nor any Subsidiary
is in default (after the expiration of any applicable grace period) in the
performance, observance or fulfillment of any of the obligations, covenants or
conditions contained in (i) any agreement to which it is a party, which default
could reasonably be expected to have a Material Adverse Effect, or (ii) any
agreement or instrument evidencing or governing Indebtedness in a principal
amount exceeding $5,000,000 (excluding in each case any default under Section
6.A or 6.B of the Private Placement Agreement).
5.16 Title to Properties. The Borrower and its Subsidiaries have good and
marketable title to all real properties purported to be owned by them and good
title to all other assets purported to be owned by them, subject to such minor
defects as are common to property of the type owned by the Borrower and its
Subsidiaries and Liens permitted by this Agreement and such defects and Liens in
the aggregate do not materially interfere with or impair the Borrower's or any
Subsidiary's business as presently conducted.
5.17 Public Utility Holding Company Act. The Borrower and the Subsidiaries
are exempt from registration under the provisions of the Public Utility Holding
Company Act of 1935 pursuant to Section 3(a) thereof.
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5.18 Regulatory Approval. No consent or authorization of, filing with, or
any other act by or in respect of any Person is required in connection with the
enforceability, execution, delivery, performance or validity of this Agreement
or the transactions contemplated thereby.
5.19 Negative Pledge. Except as set forth in Schedule 5.19 hereto, neither
the Borrower nor any Subsidiary is subject to any agreement, indenture,
instrument, undertaking or security (other than this Agreement) which prohibit
the creation, incurrence or sufferance to exist of any Lien.
5.20 Investment Company Act. The Borrower is not an "investment company" or
a Borrower "controlled" by an "investment company", within the meaning of the
Investment Company Act of 1940, as amended.
5.21 Compliance with Laws. The Borrower and its Subsidiaries have all
franchises, licenses and permits necessary for the conduct of their respective
businesses, and are in compliance with all laws, rules, regulations, orders,
writs, judgments, injunctions, decrees or awards to which it may be subject,
including, without limitation, (i) all provisions of ERISA, which, if violated,
might result in a Lien or charge upon any property of the Borrower or any
Subsidiary, and (ii) all material provisions of the Occupational Safety and
Health Act of 1970 and the rules and regulations thereunder and applicable
statutes, regulations, orders and restrictions relating to environmental
standards or controls, except to the extent that failure to maintain or comply
with any of the foregoing, singly and in the aggregate, could not reasonably be
expected to have a Material Adverse Effect.
ARTICLE VI
COVENANTS
During the term of this Agreement, unless the Required Lenders shall
otherwise consent in writing:
6.1 Information. The Borrower will furnish to each Lender:
(a) As soon as reasonably practicable and in any event within 120 days
after the close of each of its fiscal years, financial statements of the
Borrower for such fiscal year on a consolidated and consolidating basis
(consolidating statements need not be certified by such accountants) for
itself and its Subsidiaries, including balance sheets as of the end of such
period, statements of income and statements of retained earnings, and
statements of cash flows, and, as to the consolidated statements, prepared
in accordance with generally accepted accounting principles (except as
expressly set forth therein) and accompanied by an unqualified (as to going
concern or the scope of the audit) opinion of independent certified public
accountants of recognized standing, which opinion shall state that such
audit was conducted in accordance with generally accepted auditing
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standards and said financial statements fairly present the financial
condition and results of operation of the Borrower as at the end of, and
for, such fiscal year and a certificate of said accountants that, in the
course of their examination necessary for their opinion, they have obtained
no knowledge of any Default or Unmatured Default relating to accounting
matters, or if, in the opinion of such accountants, any such Default or
Unmatured Default shall exist, said certificate shall state the nature and
status thereof; provided that delivery pursuant to clause (e) below of
copies of the Annual Report on Form 10-K of the Borrower for such fiscal
year filed with the Securities and Exchange Commission (together with
copies of the financial statements required to be included therein) shall
be deemed to satisfy the requirement of this clause (a) to deliver
consolidated financial statements (but not the requirement to deliver
consolidating statements or the accountants' certificate as to the presence
or absence of any Default or Unmatured Default).
(b) As soon as reasonably practicable and in any event within 60 days
after the close of each of the first three quarterly accounting periods of
each of its fiscal years, for itself and its Subsidiaries, consolidated and
consolidating unaudited balance sheets as at the close of each such period
and consolidated and consolidating statements of income and statements of
retained earnings and statements of cash flows for the period from the
beginning of such fiscal year to the end of such quarter; provided that
delivery pursuant to clause (e) below of copies of the Quarterly Report on
Form 10-Q of the Borrower for such quarterly period filed with the
Securities and Exchange Commission shall be deemed to satisfy the
requirements of this clause (b) to deliver consolidated financial
statements (but not the requirement to deliver the certificate of the
Borrower's chief financial officer or chief accounting officer with respect
thereto).
(c) Simultaneously with the delivery of each set of financial
statements referred to in Sections 6.1(a) and 6.1(b), a certificate of the
chief financial officer or the chief accounting officer of the Borrower in
the form of Exhibit F (i) setting forth in reasonable detail the
calculations required to establish whether the Borrower was in compliance
with the requirements of Section 6.4 on the date of such financial
statements, (ii) stating whether there exists on the date of such
certificate any Default and or Unmatured Default and, if any Default or
Unmatured Default then exists, setting forth the details thereof and the
action which the Borrower is taking or proposes to take with respect
thereto, and (iii) stating that such financial statements fairly reflect in
all material respects the financial conditions and results of operations of
the Borrower and its Subsidiaries as of the date of the delivery of such
financial statements and for the period covered thereby.
(d) As soon as possible and in any event within 10 Business Days after
the Borrower has Knowledge that any of the events or conditions specified
below has occurred or exists with respect to any Plan or Multiemployer
Plan, a statement, signed by the chief financial officer or chief
accounting officer of the Borrower, describing said event or condition and
the action which the Borrower or applicable member of the
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Controlled Group proposes to take with respect thereto (and a copy of any
report or notice required to be filed with or given to the PBGC by the
Borrower or applicable member of the Controlled Group with respect to such
event or condition):
(i) the occurrence of any Reportable Event with respect to any
Plan, or any waiver shall be requested under Section 412(d) of the Code
for any Plan,
(ii) the distribution under Section 4041(c) of ERISA of a notice of
intent to terminate any Plan, or any action taken by the Borrower or
any member of the Controlled Group to terminate any Plan under Section
4041(c) of ERISA,
(iii) the institution by PBGC of proceedings under Section 4042 of
ERISA for the termination of, or the appointment of a trustee to
administer, any Plan, or the receipt by the Borrower or any member of
the Controlled Group of a notice from any Multiemployer Plan that such
action has been taken by PBGC with respect to such Multiemployer Plan,
(iv) the complete or partial withdrawal from a Multiemployer Plan
by the Borrower or any member of the Controlled Group that could
reasonably be expected to result in liability of the Borrower or such
member under Section 4201 or 4204 of ERISA (including the obligation to
satisfy secondary liability as a result of a purchaser default) having
a Material Adverse Effect, or the receipt by the Borrower or any member
of the Controlled Group of notice from a Multiemployer Plan that it is
in reorganization or insolvency pursuant to Section 4241 or 4245 of
ERISA or that it intends to terminate or has terminated under Section
4041A of ERISA,
(v) the institution of a proceeding by a fiduciary of any
Multiemployer Plan against the Borrower or any member of the Controlled
Group to enforce Section 515 of ERISA, which proceeding is not
dismissed within 30 days, or
(vi) the adoption of an amendment to any Plan that, pursuant to
Section 401(a)(29) of the Code or Section 307 of ERISA, would result in
the loss of tax-exempt status of the trust of which such Plan is a part
if the Borrower or any member of the Controlled Group fails to timely
provide security to the Plan in accordance with the provisions of said
Sections.
(e) Promptly upon the filing thereof, copies of all registration
statements and annual, quarterly, monthly or other regular reports which
the Borrower or any of its Subsidiaries files with the Securities and
Exchange Commission.
(f) Promptly upon the furnishing thereof to all shareholders of the
Borrower generally, copies of all financial statements, reports and proxy
statements so furnished.
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(g) Promptly upon receipt thereof, one copy of each written audit
report submitted to the Borrower or any Subsidiary by independent
accountants resulting from (i) any annual or interim audit submitted after
the occurrence and during the continuance of a Default or Unmatured Default
and (ii) any special audit submitted at any time, in each case, made by
them of the books of the Borrower or any Subsidiary.
(h) As soon as available and in any event not later than April 30 of
each calendar year, an engineering and economic analysis of the producing
properties of the Borrower and its Subsidiaries prepared by an independent
firm of consulting petroleum engineers and in form, substance and detail
consistent with past practice.
(i) Promptly and in any event within five Business Days after an
Authorized Officer obtains knowledge thereof, notice of the occurrence of a
Default or Unmatured Default, together with the details of such event and
the actions, if any, the Borrower has taken or intends to take with respect
thereto.
(j) Such other information (including nonfinancial information) as the
Administrative Agent or any Lender may from time to time reasonably
request.
6.2 Affirmative Covenants. The Borrower will, and will cause each
Subsidiary, to:
6.2.1. Reports and Inspection. Keep proper books and records in good order
in accordance with sound business practice and prepare its financial statements
in accordance with Agreement Accounting Principles and permit the Administrative
Agent or any Lender, at its own expense, by its representatives and agents, to
inspect any of the properties, corporate books and financial records of the
Borrower and each Subsidiary, to examine and make copies of the books of
accounts and other financial records of the Borrower and each Subsidiary, and to
discuss the affairs, finances and accounts of the Borrower and each Subsidiary
with, and to be advised as to the same by, their respective officers at such
reasonable times and intervals during regular business hours as the
Administrative Agent or such Lender may designate, provided that such inquiry
shall be limited to the purpose of evaluating the Borrower's financial condition
or compliance with this Agreement.
6.2.2 Conduct of Business. Carry on and conduct its principal business of
exploration for, and production, transportation, distribution, refinement,
processing, storage, marketing and gathering of oil and other hydrocarbons and
petroleum, and natural, synthetic or other gas in substantially the same manner
and in substantially the same fields of enterprise as it is presently conducted;
and do all things necessary to remain duly incorporated, validly existing and in
good standing as a domestic corporation in its jurisdiction of incorporation
(unless the corporate existence or ownership by the Borrower of any Subsidiary
shall be discontinued as a result of a merger, consolidation or sale of assets
as permitted by Section 6.3.2) and maintain all requisite authority to conduct
its business in each jurisdiction in which the failure to have such authority
could reasonably be expected to have a Material Adverse Effect.
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6.2.3 Insurance. Maintain insurance with reputable insurance companies or
associations in such forms and amounts and covering such risks as are customary
for companies of established reputation and similar size engaged in similar
businesses and owning and operating similar properties; provided that it is
agreed that, as of the date of this Agreement, the insurance coverage of the
Borrower and its Subsidiaries set forth on Schedule 6.2 hereto satisfies the
requirements of this Section 6.2.3.
6.2.4 Taxes. Promptly pay and discharge all material taxes, assessments and
governmental charges or levies imposed upon the Borrower or any Subsidiary (but
in the case of a Subsidiary, only to the extent that such Subsidiary's assets
shall be sufficient for the purpose), respectively, or upon or in respect of all
or any part of the property and business of the Borrower or any Subsidiary, and
all due and payable claims for work, labor or materials, which if unpaid might
become a Lien upon any property of the Borrower or any Subsidiary (other than
claims against any such Subsidiary in a proceeding under any bankruptcy or
similar law), provided that the Borrower or such Subsidiary shall not be
required to pay any such tax, assessment, charge, levy or claim if the validity
thereof shall concurrently be contested in good faith by appropriate proceedings
and if the Borrower or such Subsidiary shall set aside on its or their books
reserves deemed by it or them to be required with respect thereto in accordance
with generally accepted accounting principles.
6.2.5 Compliance with Laws. Maintain all franchises, licenses and permits
necessary for the conduct of its businesses, and comply with all laws, rules,
regulations, orders, writs, judgments, injunctions, decrees or awards to which
it may be subject, including, without limitation, (i) all provisions of ERISA,
which, if violated, might result in a Lien or charge upon any property of the
Borrower or any Subsidiary, and (ii) all material provisions of the Occupational
Safety and Health Act of 1970 and the rules and regulations thereunder and
applicable statutes, regulations, orders and restrictions relating to
environmental standards or controls, except to the extent that failure to
maintain or comply with any of the foregoing, singly and in the aggregate, could
not reasonably be expected to have a Material Adverse Effect.
6.2.6 Maintenance of Properties. Do all things necessary to maintain,
preserve, protect and keep its material properties (whether owned in fee or a
leasehold interest) in good repair, working order and condition, and make all
proper repairs, renewals and replacements so that its business carried on in
connection therewith may be properly conducted at all times; provided that,
subject to Section 6.3.2 and all other terms of this Agreement, nothing in this
Section shall prevent the Borrower or any of its Subsidiaries from discontinuing
the operation and maintenance of any of its properties (x) if such
discontinuance is, in the judgment of the Borrower or such Subsidiary, desirable
in the conduct of its business or (y) if such discontinuance or disposal could
not reasonably be expected to have a Material Adverse Effect.
6.3 Negative Covenants. The Borrower will not, nor (where applicable) will
it permit any Subsidiary to:
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6.3.1 Restricted Payments. Declare or pay any dividends on its capital
stock (other than dividends payable in its own capital stock) or redeem,
repurchase or otherwise acquire or retire any of its capital stock at any time
outstanding or any warrants, rights or options to purchase or acquire any shares
of its capital stock or permit any Subsidiary to purchase any shares of stock of
the Borrower, except that any Subsidiary may declare and pay dividends to the
Borrower or another Wholly-Owned Subsidiary.
6.3.2 Merger and Sale of Assets. Merge or consolidate with or into any
other Person or lease, sell or otherwise dispose of all, or substantially all,
of its property, assets (other than inventory, physical assets sold in the
ordinary course of business or obsolete, worn out or excess property) or
business to any other Person except that:
(1) the Borrower may merge or consolidate with or sell all of its assets to
any other solvent corporation, provided that (i) the surviving, continuing or
resulting corporation (if not the Borrower) shall (x) expressly assume by a
written instrument reasonably satisfactory to the Administrative Agent and the
Lenders (which shall be provided with an opportunity to review and comment upon
it prior to the consummation of any transaction) the due and punctual payment of
the principal of all Obligations and the due performance and observance of all
covenants, conditions and agreements on the part of the Borrower under this
Agreement, (y) deliver to the Administrative Agent and the Lenders an opinion of
counsel, in form and substance reasonably satisfactory to the Administrative
Agent and the Lenders, to the effect that such written instrument has been duly
authorized, executed and delivered by such surviving, continuing or resulting
corporation and constitutes a legal, valid and binding instrument enforceable
against such surviving, continuing or resulting corporation in accordance with
its terms, and to such further effects as the Administrative Agent and the
Lenders may reasonably request, and (z) have an investment grade rating from
Moody's Investors Service, Inc. and Standard & Poor's Rating Group, (ii) the
surviving, continuing or resulting corporation shall be a corporation organized
and existing under the laws of the United States of America or any State thereof
or the District of Columbia, and (iii) immediately after such merger,
consolidation or sale, no Default or Unmatured Default would exist;
(2) any Subsidiary may merge into the Borrower or another Subsidiary which
is a Wholly-Owned Subsidiary, and may sell, lease or otherwise dispose of any of
its assets to the Borrower or another Subsidiary which is a Wholly-Owned
Subsidiary;
(3) any Subsidiary may merge or consolidate with any corporation other than
the Borrower or another Subsidiary, provided that (i) the surviving, continuing
or resulting corporation shall be a Subsidiary, and (ii) immediately after such
merger or consolidation, no Default or Unmatured Default would exist; and
(4) the Borrower may sell, lease or otherwise dispose of all or any part of
its assets to any Person, and any Subsidiary may sell, lease or otherwise
dispose of all or any part of its assets to any Person other than the Borrower
or another Subsidiary, in each case, for a consideration which represents the
fair value at the time of such sale or other disposition,
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provided that (x) immediately after such sale, lease or other disposition (and
the application of the proceeds thereof as provided in clause (y)) no Default or
Unmatured Default would exist and (y) to the extent applicable, the Net Cash
Proceeds of such sale, lease or other disposition are applied as required by
Sections 2.7 and 2.8; and provided, further, that no sale, lease or other
disposition shall be permitted (unless the cash proceeds of such sale, lease or
other disposition will be applied to reduce the Aggregate Commitment to zero)
if, after giving effect to such transaction, the aggregate fair market value of
all non-cash proceeds received by the Borrower and its Subsidiaries from all
sales, leases and other dispositions after the date of this Agreement, less all
cash proceeds which have been received from such non-cash proceeds, would exceed
$20,000,000.
6.3.3 Liens. Create, incur, assume or suffer to exist any Lien on (a) any
Productive Property, (b) any Principal Transmission Facility or (c) any shares
of stock of any Subsidiary, except:
(i) Liens for taxes, assessments or governmental charges or levies
on its property if the same shall not at the time be delinquent or
thereafter can be paid without penalty or, provided the Borrower or any
Subsidiary knew or should have known of such Liens, are being actively
contested in good faith and by appropriate proceedings and for which
adequate reserves shall have been set aside on its books in accordance
with Agreement Accounting Principles,
(ii) Liens imposed by law, such as carriers', warehousemen's,
operators', royalty, surface damages and mechanics' liens and other
similar liens arising in the ordinary course of business which secure
payment of obligations not more than 60 days past due or which are
being contested in good faith by appropriate proceedings and for which
adequate reserves shall have been set aside on its books in accordance
with Agreement Accounting Principles,
(iii) Liens incurred in the ordinary course of business (a) arising
out of pledges or deposits under workmen's compensation laws,
unemployment insurance, old age pensions, or other social security or
retirement benefits, or similar legislation, (b) to secure the
performance of letters of credit, bids, tenders, sales contracts,
leases (including rent security deposits), statutory obligations,
surety, appeal and performance bonds, joint operating agreements or
other similar agreements and other similar obligations not incurred in
connection with the borrowing of money, the obtaining of advances or
the payment of the deferred purchase price of property or (c)
consisting of deposits which secure public or statutory obligations of
the Borrower or any Subsidiary, or surety, custom or appeal bonds to
which the Borrower or any Subsidiary is a party, or the payment of
contested taxes or import duties of the Borrower or any Subsidiary,
(iv) utility easements, building restrictions and such other
encumbrances or charges against real property as are of a nature
generally existing with respect
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to properties of a similar character and which do not in any material
way affect the marketability of the same or interfere with the use
thereof in the business of the Borrower or the Subsidiaries,
(v) Liens on drilling equipment and facilities in order to secure
the financing for the construction of such equipment and facilities not
constructed as of the date hereof, provided that such financing is
permitted pursuant to Section 6.4,
(vi) attachment, judgment and other similar Liens arising in
connection with court proceedings; provided the execution or other
enforcement of such Liens is effectively stayed or the claims secured
thereby are being actively contested in good faith and by appropriate
proceedings; and provided, further, the Borrower or any Subsidiary knew
or should have known of such Liens,
(vii) Liens on property of a Subsidiary, provided such Liens secure
only obligations owing to the Borrower or a Wholly-Owned Subsidiary,
(viii) purchase money mortgages or other mortgages or other Liens
on assets of the Borrower or any Subsidiary securing Indebtedness
hereafter incurred by the Borrower or such Subsidiary for the
acquisition of such assets, provided no such mortgage or other Lien
shall extend to any other property (unless such mortgage or Lien is
permitted under another clause of this Section 6.3.3) and the amount
thereby secured shall not exceed the purchase price of such asset plus
interest, if any, accrued thereon and shall be permitted pursuant to
Section 6.4,
(ix) Liens on property hereafter acquired (including shares of
stock hereafter acquired of any Person (including any Person in which
the Borrower or any Subsidiary already owns an interest)) existing at
the time of acquisition and liens assumed by the Borrower or a
Subsidiary as a result of a merger of another corporation into the
Borrower or a Subsidiary or the acquisition by the Borrower or a
Subsidiary of the assets and liabilities of another corporation,
provided that in each case such Liens shall not have been created in
anticipation of such transaction,
(x) any right which any municipal or governmental body or agency
may have by virtue of any franchise, license, contract or statute to
purchase, or designate a purchaser of or order the sale of, any
property of the Borrower or any Subsidiary upon payment of reasonable
compensation therefor or to terminate any franchise, license or other
rights or to regulate the property and business of the Borrower or any
Subsidiary,
(xi) easements or reservations in respect of any property of the
Borrower or any Subsidiary for the purpose of rights-of-way and similar
purposes,
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reservations, restrictions, covenants, party wall agreements,
conditions of record and other encumbrances (other than to secure the
payment of money) and minor irregularities or deficiencies in the
record and evidence of title, which in the reasonable opinion of the
Borrower (at the time of the acquisition of the property affected or
subsequently) will not interfere in any material way with the proper
operation and development of the property affected thereby,
(xii) Liens existing on the date hereof and set forth on Schedule
5.19 hereto,
(xiii) Liens on property to secure all or any part of the cost of
construction, alteration or repair of any building, equipment or other
improvement on all or any part of such property, including any
pipeline, or to secure any Indebtedness incurred prior to, at the time
of, or within 360 days after, the completion of such construction,
alteration or repair to provide funds for the payment of all or any
part of such cost,
(xiv) rights of lessors under oil, gas or mineral leases arising in
the ordinary course of business,
(xv) any extension, renewal or replacement (or successive
extensions, renewals or replacements), in whole or in part, of any Lien
referred to in the foregoing clauses; provided that the principal
amount of Indebtedness secured thereby shall not exceed the principal
amount of Indebtedness so secured at the time of such extension,
renewal or replacement and such extension, renewal or replacement Lien
shall be limited to all or a part of the property which secured the
Lien so extended, renewed or replaced (plus improvements on such
property),
(xvi) Liens which may hereafter be attached to undeveloped real
estate not containing oil or gas reserves presently owned by the
Borrower in the ordinary course of the Borrower's real estate sales,
development and rental activities,
(xvii) Liens not otherwise permitted by the foregoing clauses of
this Section 6.3.3 securing Indebtedness in an aggregate principal
amount which, at the time of incurrence, does not exceed 5% of
Stockholders' Equity as of the end of the most recently completed
fiscal quarter of the Borrower as shown on the consolidated balance
sheet related thereto, and
(xviii) Liens not otherwise permitted by the foregoing clauses of
this Section 6.3.3 in an aggregate principal amount in excess of 5% of
Stockholders' Equity; provided that at the time such Lien is created,
the Obligations will be secured pari passu with the obligations such
Lien is securing pursuant to documentation in form and substance
satisfactory to the Administrative Agent
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and the Lenders (drafts of which documentation shall be furnished to
the Administrative Agent and the Lenders sufficiently in advance to
provide the Administrative Agent and the Lenders with an opportunity to
review and comment upon it prior to the granting of any such Lien).
6.4 Financial Covenants. The Borrower will not:
6.4.1 Debt to Capitalization Ratio. Permit the Debt to Capitalization Ratio
at any time to exceed 0.8 to 1.
6.4.2 Fixed Charge Coverage Ratio. Permit the Fixed Charge Coverage Ratio
as of the last day of any fiscal quarter of the Borrower to be less than 2.5 to
1.
6.4.3 Net Worth. Permit Stockholder's Equity at any time to be less than
$120,000,000.
6.4.4 Subsidiary Indebtedness. Permit the aggregate outstanding amount of
all Indebtedness of Subsidiaries (excluding (i) Indebtedness outstanding on the
date hereof and renewals, extensions and refinancings thereof so long as the
principal amount thereof is not increased) and (ii) Indebtedness of any
Subsidiary to the Company or a Wholly-Owned Subsidiary) to exceed $20,000,000
unless provision has been made for all Subsidiaries (other than Subsidiaries
which would not constitute a Material Group of Subsidiaries) to guarantee the
Obligations pursuant to documentation (and related certificates and opinions)
reasonably satisfactory to the Administrative Agent and the Syndication Agent.
ARTICLE VII
DEFAULTS
7.1 Events of Default. The occurrence and continuance of any one or more of
the following events shall constitute a Default:
7.1.1 Representations and Warranties. Any representation or warranty made
or deemed made by or on behalf of the Borrower to either Agent or any Lender in
this Agreement or in any certificate or instrument delivered in connection
herewith shall be materially false as of the date on which made.
7.1.2 Payment Default. Nonpayment of any principal, interest, fee or other
obligation hereunder within ten days after the same becomes due.
7.1.3 Breach of Certain Covenants. The breach by the Borrower of (i) any of
the terms or provisions of Section 6.1(i), 6.3.1, 6.3.2 or 6.4 or (ii) any of
the terms or provisions of Section 6.3.3 which is not remedied within ten days
after written notice from the Administrative Agent or the Syndication Agent.
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7.1.4 Other Breach of this Agreement. The breach by the Borrower (other
than a breach which constitutes a Default under Section 7.1.1, 7.1.2 or 7.1.3)
of any term or provision of this Agreement which is not remedied within 30 days
after written notice from the Administrative Agent or the Syndication Agent.
7.1.5 ERISA. An event or condition specified in Section 6.1(d) shall occur
or exist with respect to any Plan or any Multiemployer Plan and, as a result or
such event or condition, together with all other such events or conditions then
outstanding, the Borrower or any member or the Controlled Group shall incur, or
shall be reasonably likely to incur, a liability to any Plan, any Multiemployer
Plan or the PBGC (or any combination of the foregoing) that would have a
Material Adverse Effect.
7.1.6 Cross-Default. Failure of the Borrower or any Significant Subsidiary
to pay any Indebtedness when due (after giving effect to any period of grace set
forth in any agreement under which such Indebtedness was created or is
governed); or the default by the Borrower or any Significant Subsidiary in the
performance of any other term, provision or condition contained in any agreement
under which any of their respective Indebtedness was created or is governed, the
effect of which is to cause, or to permit the holder or holders of such
Indebtedness to cause, such Indebtedness to become due prior to its stated
maturity; or any Indebtedness of the Borrower or any Significant Subsidiary
shall become due and payable or be required to be prepaid (other than by a
regularly scheduled payment) prior to the stated maturity thereof; provided
that, in each case, the principal amount of Indebtedness as to which such a
payment default shall occur and be continuing, or such a failure to perform or
other event causing or permitting acceleration shall occur and be continuing,
exceeds $5,000,000; and provided, further, that no payment or other default
under the Private Placement Debt resulting solely from a breach of Section 6.A
or 6.B of the Private Placement Agreement shall constitute a Default or an
Unmatured Default hereunder.
7.1.7 Voluntary Bankruptcy, etc. The Borrower, or any Significant
Subsidiary or a Material Group of Subsidiaries shall (i) not pay, or admit in
writing its inability to pay, its debts generally as they become due, (ii) make
an assignment for the benefit of creditors, (iii) apply for, seek, consent to,
or acquiesce in, the appointment of a receiver, custodian, trustee, examiner,
liquidator or similar official for the Borrower, such Significant Subsidiary or
such Material Group of Subsidiaries, (iv) institute any proceeding seeking an
order for relief under the Federal bankruptcy laws as now or hereafter in effect
or seeking to adjudicate it a bankrupt or insolvent, or seeking dissolution,
winding up, liquidation, reorganization, arrangement, adjustment or composition
of it or its debts under any law relating to bankruptcy, insolvency or
reorganization or relief of debtors or (v) take any corporate action to
authorize or effect any of the foregoing actions set forth in this Section
7.1.7.
7.1.8 Involuntary Bankruptcy, etc. Without the application, approval or
consent of the Borrower, the applicable Significant Subsidiary or the applicable
Material Group of Subsidiaries, a receiver, trustee, examiner, liquidator or
similar official shall be appointed for the Borrower, any Significant Subsidiary
or such Material Group of Subsidiaries, or a proceeding described in
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Section 7.1.7(iv) shall be instituted against the Borrower, any Significant
Subsidiary or such Material Group of Subsidiaries and such appointment continues
undischarged or such proceeding continues undismissed or unstayed for a period
of 60 consecutive days.
7.1.9 Judgments. The Borrower or any Significant Subsidiary shall fail
within 30 days to pay, bond or otherwise discharge any final judgment or order
for the payment of money in excess of $2,500,000, which is not stayed on appeal
or otherwise being appropriately contested in good faith.
7.1.10 Environmental Matters. The Borrower, any Significant Subsidiary or
any Material Group of Subsidiaries shall suffer any adverse determination
pertaining to the release by the Borrower, any Significant Subsidiary or any
other Person of any toxic or hazardous waste or substance into the environment,
or any violation of any federal, state or local environmental, health or safety
law or regulation, which, in either case, could reasonably be expected to have a
Material Adverse Effect.
ARTICLE VIII
ACCELERATION, WAIVERS, AMENDMENTS AND REMEDIES
8.1 Acceleration. If any Default described in Section 7.1.6 or 7.1.7 occurs
with respect to the Borrower, the obligations of the Lenders to make Loans
hereunder shall automatically terminate and the Obligations shall immediately
become due and payable without any election or action on the part of either
Agent or any Lender. If any other Default occurs, the Required Lenders (or the
Administrative Agent with the consent of the Required Lenders) may terminate or
suspend the obligations of the Lenders to make Loans hereunder, or declare the
Obligations to be due and payable, or both, whereupon the Obligations shall
become immediately due and payable, without presentment, demand, protest or
notice of any kind, all of which the Borrower hereby expressly waives.
If, within 30 days after acceleration of the maturity of the Obligations or
termination of the obligations of the Lenders to make Loans hereunder as a
result of any Default (other than any Default as described in Section 7.1.6 or
7.1.7 with respect to the Borrower) and before any judgment or decree for the
payment of the Obligations due shall have been obtained or entered, the Required
Lenders (in their sole discretion) shall so direct, the Administrative Agent
shall, by notice to the Borrower, rescind and annul such acceleration and/or
termination.
8.2 Amendments. Subject to the provisions of this Article VIII, the
Required Lenders (or the Administrative Agent with the consent in writing of the
Required Lenders) and the Borrower may enter into agreements supplemental hereto
for the purpose of adding or modifying any provisions to the Loan Documents or
changing in any manner the rights of the Lenders or the Borrower hereunder or
waiving any Default hereunder; provided that no such supplemental agreement
shall, without the consent of all of the Lenders:
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(i) Extend the final maturity of any Loan or forgive all or any portion
of the principal amount thereof, or reduce the rate or extend the
time of payment of interest or fees thereon.
(ii) Reduce the percentage specified in the definition of Required
Lenders.
(iii) Extend the Final Maturity Date, or reduce the amount or extend the
payment date for, the mandatory payments required under Section 2.2,
or increase the amount of the Aggregate Commitment or of the
Commitment of any Lender hereunder, or permit the Borrower to assign
its rights under this Agreement.
(iv) Amend this Section 8.2.
No amendment of any provision of this Agreement relating to the Administrative
Agent shall be effective without the written consent of such Agent. The
Administrative Agent may waive payment of the fee required under Section 12.3.2
without obtaining the consent of any other party to this Agreement.
8.3 Preservation of Rights. No delay or omission of the Lenders or either
Agent to exercise any right under the Loan Documents shall impair such right or
be construed to be a waiver of any Default or an acquiescence therein, and the
making of a Loan notwithstanding the existence of a Default or the inability of
the Borrower to satisfy the conditions precedent to such Loan shall not
constitute any waiver or acquiescence. Any single or partial exercise of any
such right shall not preclude other or further exercise thereof or the exercise
of any other right, and no waiver, amendment or other variation of the terms,
conditions or provisions of the Loan Documents whatsoever shall be valid unless
in writing signed by the Lenders required pursuant to Section 8.2, and then only
to the extent in such writing specifically set forth. All remedies contained in
the Loan Documents or by law afforded shall be cumulative and all shall be
available to the Agents and the Lenders until the Obligations have been paid in
full.
ARTICLE IX
GENERAL PROVISIONS
9.1 Survival of Representations. All representations and warranties of the
Borrower contained in this Agreement shall survive the making of the Loans
herein contemplated.
9.2 Governmental Regulation. Anything contained in this Agreement to the
contrary notwithstanding, no Lender shall be obligated to extend credit to the
Borrower in violation of any limitation or prohibition provided by any
applicable statute or regulation.
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9.3 Headings. Section headings in the Loan Documents are for convenience of
reference only, and shall not govern the interpretation of any of the provisions
of the Loan Documents.
9.4 Entire Agreement. The Loan Documents embody the entire agreement and
understanding among the Borrower, the Agents and the Lenders and supersede all
prior agreements and understandings among the Borrower, the Agents and the
Lenders relating to the subject matter thereof.
9.5 Several Obligations; Benefits of this Agreement. The respective
obligations of the Lenders hereunder are several and not joint and no Lender
shall be the partner or agent of any other (except to the extent to which the
Administrative Agent is authorized to act as such). The failure of any Lender to
perform any of its obligations hereunder shall not relieve any other Lender from
any of its obligations hereunder. This Agreement shall not be construed so as to
confer any right or benefit upon any Person other than the parties to this
Agreement and their respective successors and assigns, provided that the parties
hereto expressly agree that the Arrangers shall enjoy the benefits of the
provisions of Sections 9.6, 9.10 and 10.11 to the extent specifically set forth
therein and shall have the right to enforce such provisions on its own behalf
and in its own name to the same extent as if it were a party to this Agreement.
9.6 Expenses; Indemnification. (i) The Borrower shall reimburse the Agents
and the Arrangers for all reasonable costs, internal charges and out-of-pocket
expenses (including, subject to any limit on fees which is separately agreed to,
reasonable attorneys' fees and reasonable time charges of attorneys for either
Agent, which attorneys may be employees of such Agent) paid or incurred by
either Agent or either Arranger in connection with the preparation, negotiation,
execution, delivery, syndication, review, amendment, modification, and
administration of the Loan Documents. The Borrower also agrees to reimburse the
Agents, the Arrangers and the Lenders for all reasonable costs, internal charges
and out-of-pocket expenses (including reasonable attorneys' fees and reasonable
time charges of attorneys for the Agents, the Arrangers and the Lenders, which
attorneys may be employees of an Agent, either Arranger or the Lenders) paid or
incurred by either Agent, either Arranger or any Lender in connection with the
collection and enforcement of the Loan Documents.
(ii) The Borrower hereby further agrees to indemnify the Agents, the
Arrangers, each Lender, their respective affiliates, and each of their
directors, officers and employees against all losses, claims, damages,
penalties, judgments, liabilities and reasonable expenses (including, without
limitation, all reasonable expenses of litigation or preparation therefor
whether or not an Agent, an Arranger, any Lender or any affiliate is a party
thereto) which any of them may pay or incur arising out of or relating to this
Agreement, the other Loan Documents, the transactions contemplated hereby or the
direct or indirect application or proposed application of the proceeds of any
Loan hereunder except to the extent that they are determined in a final
non-appealable judgment by a court of competent jurisdiction to have resulted
from the gross negligence or willful misconduct of the party seeking
indemnification. The obligations of the Borrower under this Section 9.6 shall
survive the termination of this Agreement.
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9.7 Numbers of Documents. All statements, notices, closing documents, and
requests hereunder shall be furnished to the Administrative Agent with
sufficient counterparts so that the Administrative Agent may furnish one to each
of the Lenders.
9.8 Accounting. Except as provided to the contrary herein, all accounting
terms used herein shall be interpreted and all accounting determinations
hereunder shall be made in accordance with Agreement Accounting Principles.
9.9 Severability of Provisions. Any provision in any Loan Document that is
held to be inoperative, unenforceable, or invalid in any jurisdiction shall, as
to that jurisdiction, be inoperative, unenforceable, or invalid without
affecting the remaining provisions in that jurisdiction or the operation,
enforceability, or validity of that provision in any other jurisdiction, and to
this end the provisions of all Loan Documents are declared to be severable.
9.10 Nonliability of Lenders. The relationship between the Borrower on the
one hand and the Lenders and the Agents on the other hand shall be solely that
of borrower and lender. None of either Agent, either Arranger or any Lender
shall have any fiduciary responsibilities to the Borrower. None of either Agent,
either Arranger or any Lender undertakes any responsibility to the Borrower to
review or inform the Borrower of any matter in connection with any phase of the
Borrower's business or operations. The Borrower agrees that none of either
Agent, either Arranger or any Lender shall have liability to the Borrower
(whether sounding in tort, contract or otherwise) for losses suffered by the
Borrower in connection with, arising out of, or in any way related to, the
transactions contemplated and the relationship established by the Loan
Documents, or any act, omission or event occurring in connection therewith,
unless it is determined in a final non-appealable judgment by a court of
competent jurisdiction that such losses resulted from the gross negligence or
willful misconduct of the party from which recovery is sought. None of either
Agent, either Arranger or any Lender shall have any liability with respect to,
and the Borrower hereby waives, releases and agrees not to sue for, any special,
indirect or consequential damages suffered by the Borrower in connection with,
arising out of, or in any way related to the Loan Documents or the transactions
contemplated thereby.
9.11 Confidentiality. Each Lender agrees to hold any confidential
information which it may receive from the Borrower pursuant to this Agreement in
confidence, except for disclosure (i) to the extent permitted by law or
regulation, to its Affiliates and to other Lenders and their respective
Affiliates, (ii) to legal counsel, accountants, and other professional advisors
to such Lender or to a Transferee, (iii) to regulatory officials, (iv) to any
Person as required by law, regulation, or legal process, (v) to any Person in
connection with any legal proceeding to which such Lender is a party to the
extent required by law, regulation or legal process, (vi) permitted by Section
12.4, (vii) to rating agencies if required by such agencies in connection with a
rating relating to the Advances hereunder, and (viii) to the extent required in
connection with the exercise of any remedy or any enforcement of this Agreement
by such Lender or the Administrative Agent.
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9.12 Nonreliance. Each Lender hereby represents that it is not relying on
or looking to any margin stock (as defined in Regulation U of the Board of
Governors of the Federal Reserve System) for the repayment of the Loans provided
for herein.
9.13 Disclosure. The Borrower and each Lender hereby (i) acknowledge and
agree that Bank One and/or its Affiliates from time to time may hold investments
in, make other loans to or have other relationships with the Borrower and its
Affiliates, and (ii) waive any liability of Bank One or such Affiliate of Bank
One to the Borrower or any Lender, respectively, arising out of or resulting
from such investments, loans or relationships other than liabilities arising out
of the gross negligence or willful misconduct of Bank One or its Affiliates.
ARTICLE X
THE AGENTS
10.1 Appointment; Nature of Relationship. Bank One and Bank of America,
N.A., are hereby appointed by each of the Lenders as the Administrative Agent
and the Syndication Agent, respectively, hereunder and under each other Loan
Document, and each of the Lenders irrevocably authorizes each Agent to act as
the contractual representative of such Lender with the rights and duties
expressly set forth herein and in the other Loan Documents. Each Agent agrees to
act as an Agent upon the express conditions contained in this Article X.
Notwithstanding the use of the defined term "Administrative Agent" or
"Syndication Agent," it is expressly understood and agreed that neither Agent
shall have any fiduciary responsibilities to any Lender by reason of this
Agreement or any other Loan Document and that each Agent is merely acting as the
contractual representative of the Lenders with only those duties as are
expressly set forth in this Agreement and the other Loan Documents. In its
capacity as an Agent (i) neither Agent hereby assumes any fiduciary duties to
any of the Lenders, (ii) is a "representative" of the Lenders within the meaning
of Section 9-105 of the Uniform Commercial Code and (iii) each Agent is acting
as an independent contractor, the rights and duties of which are limited to
those expressly set forth in this Agreement and the other Loan Documents. Each
of the Lenders hereby agrees to assert no claim against either Agent on any
agency theory or any other theory of liability for breach of fiduciary duty, all
of which claims each Lender hereby waives.
10.2 Powers. Each Agent shall have and may exercise such powers under the
Loan Documents as are specifically delegated to such Agent by the terms of each
thereof, together with such powers as are reasonably incidental thereto. Neither
Agent shall have any implied duties to the Lenders, or any obligation to the
Lenders to take any action thereunder except any action specifically provided by
the Loan Documents to be taken by such Agent.
10.3 General Immunity. Neither an Agent nor any of such Agent's respective
directors, officers, agents or employees shall be liable to the Borrower, the
Lenders or any Lender for any action taken or omitted to be taken by it or them
hereunder or under any other
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Loan Document or in connection herewith or therewith except to the extent such
action or inaction is determined in a final non-appealable judgment by a court
of competent jurisdiction to have arisen from the gross negligence or willful
misconduct of such Person.
10.4 No Responsibility for Loans, Recitals, etc. Neither an Agent nor any
of such Agent's directors, officers, agents or employees shall be responsible
for or have any duty to ascertain, inquire into, or verify (a) any statement,
warranty or representation made in connection with any Loan Document or any
borrowing hereunder; (b) the performance or observance of any of the covenants
or agreements of any obligor under any Loan Document, including, without
limitation, any agreement by an obligor to furnish information directly to each
Lender; (c) the satisfaction of any condition specified in Article IV, except,
in the case of the Administrative Agent receipt of items required to be
delivered solely to Administrative Agent; (d) the existence or possible
existence of any Default or Unmatured Default; (e) the validity, enforceability,
effectiveness, sufficiency or genuineness of any Loan Document or any other
instrument or writing furnished in connection therewith; or (f) the financial
condition of the Borrower or of any of the Borrower's Subsidiaries. Neither
Agent shall have any duty to disclose to the Lenders information that is not
required to be furnished by the Borrower to such Agent at such time, but is
voluntarily furnished by the Borrower to such Agent (either in its capacity as
an Agent or in its individual capacity).
10.5 Action on Instructions of Lenders. Each Agent shall in all cases be
fully protected in acting, or in refraining from acting, hereunder and under any
other Loan Document in accordance with written instructions signed by the
Required Lenders (or, when expressly required hereunder, all of the Lenders),
and such instructions and any action taken or failure to act pursuant thereto
shall be binding on all of the Lenders. The Lenders hereby acknowledge that
neither Agent shall be under any duty to take any discretionary action permitted
to be taken by it pursuant to the provisions of this Agreement or any other Loan
Document unless it shall be requested in writing to do so by the Required
Lenders. Each Agent shall be fully justified in failing or refusing to take any
action hereunder and under any other Loan Document unless it shall first be
indemnified to its satisfaction by the Lenders pro rata against any and all
liability, cost and expense that it may incur by reason of taking or continuing
to take any such action. The Administrative Agent agrees, upon the request of
any Lender at any time an Unmatured Default exists, to give a written notice to
the Borrower of the type described in Section 7.1.3 or 7.1.4.
10.6 Employment of Agents and Counsel. Each Agent may execute any of its
duties as an Agent hereunder and under any other Loan Document by or through
employees, agents, and attorneys-in-fact and shall not be answerable to the
Lenders, except as to money or securities received by it or its authorized
agents, for the default or misconduct of any such agents or attorneys-in-fact
selected by it with reasonable care. Each Agent shall be entitled to advice of
counsel concerning the contractual arrangement between such Agent and the
Lenders and all matters pertaining to such Agent's duties hereunder and under
any other Loan Document.
10.7 Reliance on Documents; Counsel. Each Agent shall be entitled to rely
upon any Note, notice, consent, certificate, affidavit, letter, telegram,
statement, paper or document
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believed by it to be genuine and correct and to have been signed or sent by the
proper person or persons, and, in respect to legal matters, upon the opinion of
counsel selected by such Agent, which counsel may be employees of such Agent.
10.8 Agents' Reimbursement and Indemnification. The Lenders agree to
reimburse and indemnify each Agent ratably in proportion to their respective
Commitments (or, if the Commitments have been terminated, in proportion to their
Commitments immediately prior to such termination) (i) for any amounts not
reimbursed by the Borrower for which either Agent is entitled to reimbursement
by the Borrower under the Loan Documents, (ii) for any other expenses incurred
by either Agent on behalf of the Lenders, in connection with the preparation,
execution, delivery, administration and enforcement of the Loan Documents
(including, without limitation, for any expenses incurred by an Agent in
connection with any dispute between either Agent and any Lender or between two
or more of the Lenders) and (iii) for any liabilities, obligations, losses,
damages, penalties, actions, judgments, suits, costs, expenses or disbursements
of any kind and nature whatsoever which may be imposed on, incurred by or
asserted against either Agent in any way relating to or arising out of the Loan
Documents or any other document delivered in connection therewith or the
transactions contemplated thereby (including, without limitation, for any such
amounts incurred by or asserted against an Agent in connection with any dispute
between either Agent and any Lender or between two or more of the Lenders), or
the enforcement of any of the terms of the Loan Documents or of any such other
documents, provided that (i) no Lender shall be liable to any Agent for any of
the foregoing to the extent any of the foregoing is found in a final
non-appealable judgment by a court of competent jurisdiction to have resulted
from the gross negligence or willful misconduct of such Agent and (ii) any
indemnification required pursuant to Section 3.5(vii) shall, notwithstanding the
provisions of this Section 10.8, be paid by the relevant Lender in accordance
with the provisions thereof. The obligations of the Lenders under this Section
10.8 shall survive payment of the Obligations and termination of this Agreement.
10.9 Notice of Default. Neither Agent shall be deemed to have knowledge or
notice of the occurrence of any Default or Unmatured Default hereunder unless
such Agent has received written notice from a Lender or the Borrower referring
to this Agreement describing such Default or Unmatured Default and stating that
such notice is a "notice of default". In the event that either Agent receives
such a notice, such Agent shall give prompt notice thereof to the Lenders.
10.10 Rights as a Lender. In the event an Agent is a Lender, such Agent
shall have the same rights and powers hereunder and under any other Loan
Document with respect to its Commitment and its Loans as any Lender and may
exercise the same as though it were not an Agent, and the term "Lender" or
"Lenders" shall, at any time when an Agent is a Lender, unless the context
otherwise indicates, include such Agent in its individual capacity. Each Agent
and its respective Affiliates may accept deposits from, lend money to, and
generally engage in any kind of trust, debt, equity or other transaction, in
addition to those contemplated by this Agreement or any other Loan Document,
with the Borrower or any of its Subsidiaries in which
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<PAGE>
the Borrower or such Subsidiary is not restricted hereby from engaging with any
other Person. Neither Agent, in its individual capacity, is obligated to remain
a Lender.
10.11 Lender Credit Decision. Each Lender acknowledges that it has,
independently and without reliance upon either Agent, either Arranger or any
other Lender and based on the financial statements prepared by the Borrower and
such other documents and information as it has deemed appropriate, made its own
credit analysis and decision to enter into this Agreement and the other Loan
Documents. Each Lender also acknowledges that it will, independently and without
reliance upon either Agent, either Arranger or any other Lender and based on
such documents and information as it shall deem appropriate at the time,
continue to make its own credit decisions in taking or not taking action under
this Agreement and the other Loan Documents.
10.12 Successor Agent. Each Agent may resign at any time by giving written
notice thereof to the Lenders and the Borrower, such resignation to be effective
(i) in the case of the Syndication Agent, immediately, and (ii) in the case of
the Administrative Agent, upon the appointment of a successor Agent, or, if no
successor Agent has been appointed, forty-five days after the retiring Agent
gives notice of its intention to resign. Either Agent may be removed at any time
with or without cause by written notice received by such Agent from the Required
Lenders, such removal to be effective on the date specified by the Required
Lenders. Upon any resignation or removal of the Administrative Agent, the
Required Lenders shall have the right (with, so long as no Default or Unmatured
Default exists, the consent of the Borrower, which shall not be unreasonably
withheld) to appoint, on behalf of the Borrower and the Lenders, a successor
Administrative Agent. If no successor Administrative Agent shall have been so
appointed by the Required Lenders within thirty days after the resigning
Administrative Agent's giving notice of its intention to resign, then the
resigning Administrative Agent may appoint, on behalf of the Borrower and the
Lenders, a successor Administrative Agent. Notwithstanding the previous
sentence, the Administrative Agent may at any time without the consent of any
Lender and with the consent of the Borrower, not to be unreasonably withheld or
delayed, appoint any of its Affiliates which is a commercial bank as a successor
Administrative Agent hereunder. If the Administrative Agent has resigned or been
removed and no successor Administrative Agent has been appointed, the Lenders
may perform all the duties of the Administrative Agent hereunder and the
Borrower shall make all payments in respect of the Obligations to the applicable
Lender and for all other purposes shall deal directly with the Lenders. No
successor Administrative Agent shall be deemed to be appointed hereunder until
such Administrative Agent has accepted the appointment. Any such successor
Administrative Agent shall be a commercial bank having capital and retained
earnings of at least $100,000,000. Upon the acceptance of any appointment as
Administrative Agent hereunder by a successor Administrative Agent, such
successor Administrative Agent shall thereupon succeed to and become vested with
all the rights, powers, privileges and duties of the resigning or removed
Administrative Agent. Upon the effectiveness of the resignation or removal of
either Agent, the resigning or removed Agent shall be discharged from its duties
and obligations hereunder and under the Loan Documents. After the effectiveness
of the resignation or removal of an Agent, the provisions of this Article X
shall continue in effect for the benefit of such Agent in respect of any actions
taken or omitted to be
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<PAGE>
taken by such Agent while such Agent was acting as an Agent hereunder and under
the other Loan Documents. In the event that there is a successor to the
Administrative Agent by merger, or the Administrative Agent assigns its duties
and obligations to an Affiliate pursuant to this Section 10.12, then the term
"Prime Rate" as used in this Agreement shall mean the prime rate, base rate or
other analogous rate of the new Administrative Agent.
10.13 Delegation to Affiliates. The Borrower and the Lenders agree that
each Agent may delegate any of its duties under this Agreement to any of its
respective Affiliates. Any such Affiliate (and such Affiliate's directors,
officers, agents and employees) which performs duties in connection with this
Agreement shall be entitled to the same benefits of the indemnification, waiver
and other protective provisions to which the Agents are entitled under Articles
IX and X.
ARTICLE XI
SETOFF; RATABLE PAYMENTS
11.1 Setoff. In addition to, and without limitation of, any rights of the
Lenders under applicable law, if the Borrower becomes insolvent, however
evidenced, or any Default occurs, any and all deposits (including all account
balances, whether provisional or final and whether or not collected or
available) and any other Indebtedness at any time held or owing by any Lender or
any Affiliate of any Lender to or for the credit or account of the Borrower may
be offset and applied toward the payment of the Obligations owing to such
Lender, whether or not the Obligations, or any part thereof, shall then be due.
11.2 Ratable Payments. If any Lender, whether by setoff or otherwise, has
payment made to it upon its Loans (other than payments received pursuant to
Section 3.1, 3.2, 3.4 or 3.5) in a greater proportion than that received by any
other Lender, such Lender agrees, promptly upon demand, to purchase a portion of
the Loans held by the other Lenders so that after such purchase each Lender will
hold its ratable proportion of Loans. If any Lender, whether in connection with
setoff or amounts which might be subject to setoff or otherwise, receives
collateral or other protection for its Obligations or such amounts which may be
subject to setoff, such Lender agrees, promptly upon demand, to take such action
necessary such that all Lenders share in the benefits of such collateral ratably
in proportion to their Loans. In case any such payment is disturbed by legal
process, or otherwise, appropriate further adjustments shall be made.
ARTICLE XII
BENEFIT OF AGREEMENT; ASSIGNMENTS; PARTICIPATIONS
12.1 Successors and Assigns. The terms and provisions of the Loan Documents
shall be binding upon and inure to the benefit of the Borrower and the Lenders
and their respective
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<PAGE>
successors and assigns, except that (i) the Borrower shall not have the right to
assign its rights or obligations under the Loan Documents and (ii) any
assignment by any Lender must be made in compliance with Section 12.3. The
parties to this Agreement acknowledge that clause (ii) of this Section 12.1
relates only to absolute assignments and does not prohibit assignments creating
security interests, including, without limitation, any pledge or assignment by
any Lender of all or any portion of its rights under this Agreement and any Note
to a Federal Reserve Bank; provided that no such pledge or assignment creating a
security interest shall release the transferor Lender from its obligations
hereunder unless and until the parties thereto have complied with the provisions
of Section 12.3. The Administrative Agent may treat the Person which made any
Loan or which holds any Note as the owner thereof for all purposes hereof unless
and until such Person complies with Section 12.3; provided that the
Administrative Agent may in its discretion (but shall not be required to) follow
instructions from the Person which made any Loan or which holds any Note to
direct payments relating to such Loan or Note to another Person. Any assignee of
the rights to any Loan or any Note agrees by acceptance of such assignment to be
bound by all the terms and provisions of the Loan Documents. Any request,
authority or consent of any Person, who at the time of making such request or
giving such authority or consent is the owner of the rights to any Loan (whether
or not a Note has been issued in evidence thereof), shall be conclusive and
binding on any subsequent holder or assignee of the rights to such Loan.
12.2 Participations.
12.2.1. Permitted Participants; Effect. Any Lender may, in the ordinary
course of its business and in accordance with applicable law, at any time
sell to one or more banks or other entities ("Participants") participating
interests in any Loan owing to such Lender, any Note held by such Lender,
any Commitment of such Lender or any other interest of such Lender under
the Loan Documents. In the event of any such sale by a Lender of
participating interests to a Participant, such Lender's obligations under
the Loan Documents shall remain unchanged, such Lender shall remain solely
responsible to the other parties hereto for the performance of such
obligations, such Lender shall remain the owner of its Loans and the holder
of any Note issued to it in evidence thereof for all purposes under the
Loan Documents, all amounts payable by the Borrower under this Agreement
(including under Article III) shall be determined as if such Lender had not
sold such participating interests, and the Borrower and the Administrative
Agent shall continue to deal solely and directly with such Lender in
connection with such Lender's rights and obligations under the Loan
Documents.
12.2.2. Voting Rights. Each Lender shall retain the sole right to
approve, without the consent of any Participant, any amendment,
modification or waiver of any provision of the Loan Documents other than
any amendment, modification or waiver with respect to any Loan or
Commitment in which such Participant has an interest which forgives
principal, interest or fees or reduces the interest rate or fees payable
with respect to any such Loan or Commitment, extends the Final Maturity
Date, or postpones any date fixed for any regularly scheduled payment of
principal of, or interest or fees on, any such Loan or Commitment.
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<PAGE>
12.3 Assignments.
12.3.1. Permitted Assignments. Any Lender may, in the ordinary course
of its business and in accordance with applicable law, at any time assign
to one or more banks or other entities ("Purchasers") all or any part of
its rights and obligations under the Loan Documents. Such assignment shall
be substantially in the form of Exhibit C or in such other form as may be
agreed to by the parties thereto. The consent of the Borrower, the
Administrative Agent and the Syndication Agent (which consent shall not be
unreasonably withheld or delayed by any such party) shall be required prior
to an assignment becoming effective with respect to a Purchaser which is
not a Lender or an Affiliate thereof; provided that if a Default has
occurred and is continuing, the consent of the Borrower shall not be
required; provided, further, that no assignment shall be permitted if, as
of the date thereof, any event or circumstance exists which would result in
the Borrower being obligated to pay any greater amount hereunder to the
Purchaser than the Borrower is obligated to pay to the assigning Lender.
Each such assignment with respect to a Purchaser which is not a Lender or
an Affiliate thereof shall (unless each of the Borrower and the
Administrative Agent otherwise consents) be in an amount not less than the
lesser of (i) $5,000,000 or (ii) the remaining amount of the assigning
Lender's Commitment (calculated as at the date of such assignment) or
outstanding Loans (if the applicable Commitment has been terminated).
12.3.2. Effect; Effective Date. Upon (i) delivery to the Administrative
Agent of an assignment, together with any consents required by Section
12.3.1, and (ii) payment of a $4,000 fee to the Administrative Agent for
processing such assignment (unless such fee is waived by the Administrative
Agent), such assignment shall become effective on the effective date
specified in such assignment. The assignment shall contain a representation
by the Purchaser to the effect that none of the consideration used to make
the purchase of the Commitment and Loans under the applicable assignment
agreement constitutes "plan assets" as defined under ERISA and that the
rights and interests of the Purchaser in and under the Loan Documents will
not be "plan assets" under ERISA. On and after the effective date of such
assignment, such Purchaser shall for all purposes be a Lender party to this
Agreement and any other Loan Document executed by or on behalf of the
Lenders and shall have all the rights and obligations of a Lender under the
Loan Documents, to the same extent as if it were an original party hereto,
and no further consent or action by the Borrower, the Lenders, the
Administrative Agent or the Syndication Agent shall be required to release
the transferor Lender with respect to the percentage of the Aggregate
Commitment and Loans assigned to such Purchaser. Upon the consummation of
any assignment to a Purchaser pursuant to this Section 12.3.2, the
transferor Lender, the Administrative Agent and the Borrower shall, if the
transferor Lender or the Purchaser desires that its Loans be evidenced by
Notes, make appropriate arrangements so that new Notes or, as appropriate,
replacement Notes are issued to such transferor Lender and new Notes or, as
appropriate, replacement Notes, are issued to such Purchaser, in each case
in principal amounts reflecting their respective Commitments, as adjusted
pursuant to such assignment.
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<PAGE>
12.4 Dissemination of Information. The Borrower authorizes each Lender to
disclose to any Participant or Purchaser or any other Person acquiring an
interest in the Loan Documents by operation of law (each a "Transferee") and any
prospective Transferee any and all information in such Lender's possession
concerning the creditworthiness of the Borrower and its Subsidiaries, including
without limitation any information contained in any Reports; provided that each
Transferee and prospective Transferee agrees to be bound by Section 9.11 of this
Agreement.
12.5 Tax Treatment. If any interest in any Loan Document is transferred to
any Transferee which is organized under the laws of any jurisdiction other than
the United States or any State thereof, the transferor Lender shall cause such
Transferee, concurrently with the effectiveness of such transfer, to comply with
the provisions of Section 3.5(iv) and the Borrower shall not be required to
indemnify such Transferee pursuant to Section 3.5 hereof for any Taxes withheld
as a result of the failure of the Transferee to so comply.
ARTICLE XIII
NOTICES
13.1 Notices. Except as otherwise permitted by Section 2.15 with respect to
borrowing notices, all notices, requests and other communications to any party
hereunder shall be in writing (including electronic transmission, facsimile
transmission or similar writing) and shall be given to such party: (x) in the
case of the Borrower or an Agent, at its address or facsimile number set forth
on the signature pages hereof, (y) in the case of any Lender, at its address or
facsimile number set forth in its administrative questionnaire or (z) in the
case of any party, at such other address or facsimile number as such party may
hereafter specify for the purpose by notice to the Administrative Agent and the
Borrower in accordance with the provisions of this Section 13.1. Each such
notice, request or other communication shall be effective (i) if given by
facsimile transmission, when transmitted to the facsimile number specified in
this Section and confirmation of receipt is received, or (ii) if given by any
other means, when delivered (or, in the case of electronic transmission,
received) at the address specified in this Section; provided that notices to the
Administrative Agent under Article II shall not be effective until received.
13.2 Change of Address. The Borrower, each Agent and any Lender may each
change the address for service of notice upon it by a notice in writing to the
other parties hereto.
ARTICLE XIV
COUNTERPARTS
This Agreement may be executed in any number of counterparts, all of which
taken together shall constitute one agreement, and any of the parties hereto may
execute this
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Agreement by signing any such counterpart. This Agreement shall be effective
when it has been executed by the Borrower, the Agents and the Lenders and each
party has notified the Administrative Agent by facsimile transmission or
telephone that it has taken such action.
ARTICLE XV
CHOICE OF LAW; CONSENT TO JURISDICTION;
WAIVER OF JURY TRIAL; MAXIMUM INTEREST RATE
15.1 CHOICE OF LAW. THE LOAN DOCUMENTS (OTHER THAN THOSE CONTAINING A
CONTRARY EXPRESS CHOICE OF LAW PROVISION) SHALL BE CONSTRUED IN ACCORDANCE WITH
THE INTERNAL LAWS (INCLUDING, WITHOUT LIMITATION, 735 ILCS SECTION 105/5-1 ET
SEQ, BUT OTHERWISE WITHOUT REGARD TO THE CONFLICT OF LAWS PROVISIONS) OF THE
STATE OF ILLINOIS, BUT GIVING EFFECT TO FEDERAL LAWS APPLICABLE TO NATIONAL
BANKS.
15.2 CONSENT TO JURISDICTION. THE BORROWER HEREBY IRREVOCABLY SUBMITS TO
THE NON-EXCLUSIVE JURISDICTION OF ANY UNITED STATES FEDERAL OR ILLINOIS STATE
COURT SITTING IN CHICAGO, ILLINOIS IN ANY ACTION OR PROCEEDING ARISING OUT OF OR
RELATING TO ANY LOAN DOCUMENTS AND THE BORROWER HEREBY IRREVOCABLY AGREES THAT
ALL CLAIMS IN RESPECT OF SUCH ACTION OR PROCEEDING MAY BE HEARD AND DETERMINED
IN ANY SUCH COURT AND IRREVOCABLY WAIVES ANY OBJECTION IT MAY NOW OR HEREAFTER
HAVE AS TO THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN SUCH A
COURT OR THAT SUCH COURT IS AN INCONVENIENT FORUM. NOTHING HEREIN SHALL LIMIT
THE RIGHT OF EITHER AGENT OR ANY LENDER TO BRING PROCEEDINGS AGAINST THE
BORROWER IN THE COURTS OF ANY OTHER JURISDICTION. ANY JUDICIAL PROCEEDING BY THE
BORROWER AGAINST EITHER AGENT OR ANY LENDER OR ANY AFFILIATE OF EITHER AGENT OR
ANY LENDER INVOLVING, DIRECTLY OR INDIRECTLY, ANY MATTER IN ANY WAY ARISING OUT
OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT SHALL BE BROUGHT ONLY IN A
COURT IN CHICAGO, ILLINOIS.
15.3 WAIVER OF JURY TRIAL. THE BORROWER, THE ADMINISTRATIVE AGENT AND EACH
LENDER HEREBY WAIVE TRIAL BY JURY IN ANY JUDICIAL PROCEEDING INVOLVING, DIRECTLY
OR INDIRECTLY, ANY MATTER (WHETHER SOUNDING IN TORT, CONTRACT OR OTHERWISE) IN
ANY WAY ARISING OUT OF, RELATED TO, OR CONNECTED WITH ANY LOAN DOCUMENT OR THE
RELATIONSHIP ESTABLISHED THEREUNDER.
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15.4 Maximum Interest Rate. No provision of the Loan Documents shall
require the payment or permit the collection of interest in excess of the
maximum permitted by applicable law ("Maximum Rate"). If any interest in excess
of the Maximum Rate is provided for or shall be adjudicated to be provided for
in the Notes or otherwise in connection with this Agreement, the provisions of
this Section 15.4 shall govern and prevail and neither the Borrower nor the
sureties, guarantors, successors or assigns of the Borrower shall be obligated
to pay the excess amount of the interest or any other excess sum paid for the
use, forbearance, or detention of sums loaned. In the event either Agent or any
Lender ever receives, collects or applies as interest any amount in excess of
the Maximum Rate, the amount by which such amount exceeds the Maximum Rate shall
be applied as a payment and reduction of the principal of indebtedness evidenced
by the Loans, and, if the principal amount of the Loans has been paid in full,
any remaining excess shall forthwith be paid to the Borrower.
15.5 Termination of Existing Agreements. Each of the parties hereto (to the
extent applicable) agrees that, concurrently with the making of the initial
Advance hereunder, each of the Agreements referred to in clause (a) of the first
paragraph of Section 4.1 shall be terminated (without regard to any requirement
for notice of termination of any commitment thereunder) and each such Agreement
shall be of no further force or effect (except for any provision thereof which
by its terms survives termination thereof).
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IN WITNESS WHEREOF, the Borrower, the Lenders and the Agents have executed
this Agreement as of the date first above written.
SOUTHWESTERN ENERGY COMPANY
By:____________________________________
Executive Vice President and
Chief Financial Officer
1083 Sain Street
P.O. Box 1408
Fayetteville, Arkansas 72702
Attention: Greg Kerley
Fax: 501-521-1147
S-1
<PAGE>
BANK ONE, NA,
Individually and as Administrative Agent
By:____________________________________
Title:_______________________________
1 Bank One Plaza
Chicago, Illinois 60670
Attention: Madeleine Pember
Fax: 312-732-9727
S-2
<PAGE>
BANK OF AMERICA, N.A.,
Individually and as Syndication Agent
By:____________________________________
J. Scott Fowler
Managing Director
S-3
<PAGE>
SCHEDULE 1A
COMMITMENTS
<TABLE>
<CAPTION>
Lender Amount of Commitment
------ --------------------
<S> <C>
Bank One, NA $ 90,000,000
Bank of America, N.A. $ 90,000,000
-------------------- ------------
Aggregate Commitment $180,000,000
</TABLE>
<PAGE>
SCHEDULE 1B
EXISTING INDEBTEDNESS
<TABLE>
<CAPTION>
Outstanding Principal
Designation Obligor Holders as of July 10, 2000 Amount as of July 10, 2000
----------- ------- --------------------------- --------------------------
<S> <C> <C> <C>
Private Placement Debt Company Various Investors $22,000,000
Senior Notes Company Bank One, NA (then known as $125,000,000
The First National Bank of
Chicago), as Trustee
Medium Term Notes Company Bank One, NA (then known as $100,000,000
The First National Bank of
Chicago), as Trustee
Guaranty Agreement Re: Company The Bank of New York, as $45,600,000
NOARK Pipeline System Trustee
</TABLE>
<PAGE>
SCHEDULE 2.7(a)
EXCLUDED ASSET SALES
A.W. Realty Sale
An undivided 2/3 interest in Lot1-B of Vantage Square, a Joint Venture, or a
portion of Lot 1-B yet to be determined. Lot 1-B containing 5.86 acres is
located in the northeast quarter of the northeast quarter of Section 26,
Township 17 north, range 30 west of Washington County, Arkansas. Anticipated
sales proceeds of approximately $1.2 million.
Oklahoma E&P Properties
Southwestern Energy Production Company's working interest in approximately 135
oil and gas producing properties located primarily in the Anadarko Basin in
western Oklahoma. Properties will be auctioned at the Oil & Gas Asset
Clearinghouse Auction scheduled for the week of July 10, 2000 with proceeds
expected to be between $11 million and $13 million.
<PAGE>
SCHEDULE 2.7(b)
ASSETS TO BE SWAPPED
Southwestern Energy Production Company's working interest in approximately 300
oil and gas producing properties in the Anadarko Basin of Oklahoma. Properties
represent the remaining Anadarko properties not sold at auction during the week
of July 10, 2000. Properties would be anticipated to be sold at a price ranging
from $20 million to $30 million.
<PAGE>
SCHEDULE 5.4
SUBSIDIARIES
Arkansas Western Gas Company
Southwestern Energy Production Company
Southwestern Energy Pipeline Company
SEECO, Inc.
A.W. Realty Company
Southwestern Energy Services Company
Diamond M Production Company
All of the above are 100% wholly-owned by the Company and are Arkansas
corporations.
Arkansas Gas Gathering Company, an Arkansas corporation, is 100% wholly-owned by
SEECO, Inc.
<PAGE>
SCHEDULE 5.13
LITIGATION
Enron v. Southwestern Energy Company, et. al
In its Form 8-K filed July 2, 1996, the Borrower disclosed that this lawsuit
relating to overriding royalty interests in certain Arkansas oil and gas
properties had been filed against it and two of its wholly-owned subsidiaries.
The lawsuit, which was brought by a party who was originally included in (but
opted out of) the Case, involves claims similar to those upon which judgment was
rendered against the Borrower and its Subsidiaries. In September 1998, another
party who opted out of the class threatened the Borrower with similar
litigation. While the amounts of these pending and threatened claims could be
significant, management believes, based on its extensive investigations and
trial preparation, that these claims are without merit, and that the Borrower's
ultimate liability, if any, will not be material to its consolidated financial
position or results of operation. This matter went to a non-jury trial as to
liability on January 10, 2000 and the Borrower is awaiting the Court's ruling.
<PAGE>
SCHEDULE 5.19
NEGATIVE PLEDGES
Listed below are all of the documents evidencing Indebtedness of
Southwestern Energy Company and its Subsidiaries which contain limitations on
the creation, incurrence, or assumption of Liens on any of their properties.
9.36% Senior Notes due 2011, Series C issued by the Borrower.
Indenture dated as of December 1, 1995, between the Borrower and Bank One,
NA (then known as The First National Bank of Chicago), as Trustee.
<PAGE>
SCHEDULE 6.2
INSURANCE
1. Property "all risk" insurance including earthquake coverage for buildings,
personal property, equipment and inventory. Minimum limit of $15,000,000.
2. Workers' Compensation with Statutory Limits and Employer's Liability with
$1,000,000 per accident or occupational disease covering all employees in
compliance with the laws of the States of Arkansas, Oklahoma, New Mexico
and Texas. Such policy is endorsed to provide United States Longshoremen's
& Harbor Workers' Compensation Act and Maritime Coverages.
3. Comprehensive General Liability Insurance with bodily injury and death
limits of $1,000,000 for injury to or death of one person and $2,000,000
for the death or injury of more than one person in one occurrence and
property damage limits of $1,000,000 for each occurrence.
4. Automobile Public Liability Insurance covering bodily injury or death and
property damage of at least $1,000,000 per occurrence, combined single
limit.
5. Control of Well Coverage with $10,000,000 combined single limit for
operator's extra expense/care, custody and control;
redrilling/recompletion; and seepage, pollution and containment.
6. Umbrella Liability Insurance with minimum limits of at least $30,000,000 to
apply in excess of the primary limits of the above stated policies.
<PAGE>
EXHIBIT A
FORM OF BORROWING NOTICE
Reference is made to the Credit Agreement dated as of July 17, 2000 (as from
time to time amended, the "Agreement") among Southwestern Energy Company, an
Arkansas corporation (the "Borrower"), various financial institutions, and Bank
One, NA, as Administrative Agent (the "Administrative Agent"). Capitalized terms
used but not defined herein have the respective meanings given to such terms in
the Agreement.
Pursuant to the Agreement, the Borrower hereby requests that an Advance in the
amount of $_________ to be made on ____________, ____. The Borrower requests
that the Advance to be made hereunder shall be [a Floating Rate Advance] [a
Eurodollar Advance] [a Transaction Rate Advance] [and shall have an Interest
Period/Transaction Rate Interest Period of _______________.]
The Borrower certifies that:
(a) The representations and warranties of the Borrower set forth in
Article V of the Agreement are true and correct on and as of the date hereof,
with the same effect as though such representations and warranties had been made
on and as of the date hereof or, if such representations and warranties are
expressly limited to particular dates, as of such particular dates.
(b) No Default or Unmatured Default exists or will result from the
Borrower's receipt and application of the proceeds of the Advance requested
hereby.
IN WITNESS WHEREOF, this instrument is executed as of _________, ____.
SOUTHWESTERN ENERGY COMPANY
By:____________________________________
Name:__________________________________
Title:_________________________________
<PAGE>
EXHIBIT B
FORM OF OPINION
___________, 2000
The Administrative Agent and the Lenders who are parties to the Credit Agreement
described below.
Gentlemen/Ladies:
I am counsel for Southwestern Energy Company (the "Borrower"), and have
represented the Borrower in connection with its execution and delivery of a
Credit Agreement dated as of July 17, 2000 (the "Agreement") among the Borrower,
the Lenders named therein, and Bank One, NA, as Administrative Agent, and
providing for Advances in an aggregate principal amount not exceeding
$180,000,000 at any one time outstanding. All capitalized terms used in this
opinion and not otherwise defined herein shall have the meanings attributed to
them in the Agreement.
I have examined the Borrower's **[describe constitutive documents of
Borrower and appropriate evidence of authority to enter into the transaction]**,
the Loan Documents and such other matters of fact and law which we deem
necessary in order to render this opinion. Based upon the foregoing, it is our
opinion that:
l. Each of the Borrower and its Subsidiaries is a corporation, partnership
or limited liability Borrower duly and properly incorporated or organized, as
the case may be, validly existing and (to the extent such concept applies to
such entity) in good standing under the laws of its jurisdiction of
incorporation or organization and has all requisite authority to conduct its
business in each jurisdiction in which its business is conducted.
2. The execution and delivery by the Borrower of the Loan Documents and the
performance by the Borrower of its obligations thereunder have been duly
authorized by proper corporate proceedings on the part of the Borrower and will
not:
(a) require any consent of the Borrower's shareholders or members
(other than any such consent as has already been given and remains in full
force and effect);
(b) violate (i) any law, rule, regulation, order, writ, judgment,
injunction, decree or award binding on the Borrower or any of its
Subsidiaries or (ii) the Borrower's or any Subsidiary's articles or
certificate of incorporation, partnership agreement, certificate of
partnership, articles or certificate of organization, bylaws, or operating
or
<PAGE>
other management agreement, as the case may be, or (iii) the provisions of
any indenture, instrument or agreement to which the Borrower or any of its
Subsidiaries is a party or is subject, or by which it, or its Property, is
bound, or conflict with or constitute a default thereunder; or
(c) result in, or require, the creation or imposition of any Lien in,
of or on the Property of the Borrower or a Subsidiary pursuant to the terms
of any indenture, instrument or agreement binding upon the Borrower or any
of its Subsidiaries.
3. The Loan Documents have been duly executed and delivered by the Borrower
and constitute legal, valid and binding obligations of the Borrower enforceable
against the Borrower in accordance with their terms except to the extent the
enforcement thereof may be limited by bankruptcy, insolvency or similar laws
affecting the enforcement of creditors' rights generally and subject also to the
availability of equitable remedies if equitable remedies are sought.
4. Except for the litigation disclosed in Borrower's Form 8-K filed July 2,
1996 and updated in the Borrower's most recent Form 10-Q, there is no
litigation, arbitration, governmental investigation, proceeding or inquiry
pending or, to the best of our knowledge after due inquiry, threatened against
the Borrower or any of its Subsidiaries which, if adversely determined, could
reasonably be expected to have a Material Adverse Effect.
5. No order, consent, adjudication, approval, license, authorization, or
validation of, or filing, recording or registration with, or exemption by, or
other action in respect of any governmental or public body or authority, or any
subdivision thereof, which has not been obtained by the Borrower or any of its
Subsidiaries, is required to be obtained by the Borrower or any of its
Subsidiaries in connection with the execution and delivery of the Loan
Documents, the borrowings under the Agreement, the payment and performance by
the Borrower of the Obligations, or the legality, validity, binding effect or
enforceability of any of the Loan Documents.
This opinion may be relied upon by the Agents, the Lenders and their
participants, assignees and other transferees.
Very truly yours,
<PAGE>
EXHIBIT C
ASSIGNMENT AGREEMENT
This Assignment Agreement (this "Assignment Agreement") between ___________
(the "Assignor") and _____________ (the "Assignee") is dated as of ________, ___
20___. The parties hereto agree as follows:
1. PRELIMINARY STATEMENT. The Assignor is a party to a Credit Agreement
(which, as it may be amended, modified, renewed or extended from time to time is
herein called the "Credit Agreement") described in Item 1 of Schedule 1 attached
hereto ("Schedule 1"). Capitalized terms used herein and not otherwise defined
herein shall have the meanings attributed to them in the Credit Agreement.
2. ASSIGNMENT AND ASSUMPTION. The Assignor hereby sells and assigns to the
Assignee, and the Assignee hereby purchases and assumes from the Assignor, an
interest in and to the Assignor's rights and obligations under the Credit
Agreement and the other Loan Documents, such that after giving effect to such
assignment the Assignee shall have purchased pursuant to this Assignment
Agreement the percentage interest specified in Item 3 of Schedule 1 of all
outstanding rights and obligations under the Credit Agreement and the other Loan
Documents relating to the facilities listed in Item 3 of Schedule 1. The
aggregate Commitment (or Loans, if the applicable Commitment has been
terminated) purchased by the Assignee hereunder is set forth in Item 4 of
Schedule 1.
3. EFFECTIVE DATE. The effective date of this Assignment Agreement (the
"Effective Date") shall be the later of the date specified in Item 5 of Schedule
1 or two Business Days (or such shorter period agreed to by the Administrative
Agent) after this Assignment Agreement, together with any consents required
under the Credit Agreement, are delivered to the Administrative Agent. In no
event will the Effective Date occur if the payments required to be made by the
Assignee to the Assignor on the Effective Date are not made on the proposed
Effective Date.
4. PAYMENT OBLIGATIONS. In consideration for the sale and assignment of
Loans hereunder, the Assignee shall pay the Assignor, on the Effective Date, the
amount agreed to by the Assignor and the Assignee. On and after the Effective
Date, the Assignee shall be entitled to receive from the Administrative Agent
all payments of principal, interest and fees with respect to the interest
assigned hereby. The Assignee will promptly remit to the Assignor any interest
on Loans and fees received from the Administrative Agent which relate to the
portion of the Commitment or Loans assigned to the Assignee hereunder for
periods prior to the Effective Date and not previously paid by the Assignee to
the Assignor. In the event that either party hereto receives any payment to
which the other party hereto is entitled under this Assignment Agreement, then
the party receiving such amount shall promptly remit it to the other party
hereto.
<PAGE>
5. RECORDATION FEE. The Assignor and Assignee each agree to pay one-half of
the recordation fee required to be paid to the Administrative Agent in
connection with this Assignment Agreement unless otherwise specified in Item 6
of Schedule 1.
6. REPRESENTATIONS OF THE ASSIGNOR; LIMITATIONS ON THE ASSIGNOR'S
LIABILITY. The Assignor represents and warrants that (i) it is the legal and
beneficial owner of the interest being assigned by it hereunder, (ii) such
interest is free and clear of any adverse claim created by the Assignor and
(iii) the execution and delivery of this Assignment Agreement by the Assignor is
duly authorized. It is understood and agreed that the assignment and assumption
hereunder are made without recourse to the Assignor and that the Assignor makes
no other representation or warranty of any kind to the Assignee. Neither the
Assignor nor any of its officers, directors, employees, agents or attorneys
shall be responsible for (i) the due execution, legality, validity,
enforceability, genuineness, sufficiency or collectability of any Loan Document,
including without limitation, documents granting the Assignor and the other
Lenders a security interest in assets of the Borrower or any guarantor, (ii) any
representation, warranty or statement made in or in connection with any of the
Loan Documents, (iii) the financial condition or creditworthiness of the
Borrower or any guarantor, (iv) the performance of or compliance with any of the
terms or provisions of any of the Loan Documents, (v) inspecting any of the
property, books or records of the Borrower, (vi) the validity, enforceability,
perfection, priority, condition, value or sufficiency of any collateral securing
or purporting to secure the Loans or (vii) any mistake, error of judgment, or
action taken or omitted to be taken in connection with the Loans or the Loan
Documents.
7. REPRESENTATIONS AND UNDERTAKINGS OF THE ASSIGNEE. The Assignee (i)
confirms that it has received a copy of the Credit Agreement, together with
copies of the financial statements requested by the Assignee and such other
documents and information as it has deemed appropriate to make its own credit
analysis and decision to enter into this Assignment Agreement, (ii) agrees that
it will, independently and without reliance upon either Agent, the Assignor or
any other Lender and based on such documents and information at it shall deem
appropriate at the time, continue to make its own credit decisions in taking or
not taking action under the Loan Documents, (iii) appoints and authorizes the
Agents to take such action as agent on its behalf and to exercise such powers
under the Loan Documents as are delegated to the Agents by the terms thereof,
together with such powers as are reasonably incidental thereto, (iv) confirms
that the execution and delivery of this Assignment Agreement by the Assignee is
duly authorized, (v) agrees that it will perform in accordance with their terms
all of the obligations which by the terms of the Loan Documents are required to
be performed by it as a Lender, (vi) agrees that its payment instructions and
notice instructions are as set forth in the attachment to Schedule 1, (vii)
confirms that none of the funds, monies, assets or other consideration being
used to make the purchase and assumption hereunder are "plan assets" as defined
under ERISA and that its rights, benefits and interests in and under the Loan
Documents will not be "plan assets" under ERISA, (viii) agrees to indemnify and
hold the Assignor harmless against all losses, costs and expenses (including,
without limitation, reasonable attorneys' fees) and liabilities incurred by the
Assignor in connection with or arising in any manner from the Assignee's
nonperformance of the obligations assumed under this Assignment Agreement, and
2
<PAGE>
(ix) if applicable, attaches the forms prescribed by the Internal Revenue
Service of the United States certifying that the Assignee is entitled to receive
payments under the Loan Documents without deduction or withholding of any United
States federal income taxes.
8. GOVERNING LAW. This Assignment Agreement shall be governed by the
internal law, and not the law of conflicts, of the State of Illinois.
9. NOTICES. Notices shall be given under this Assignment Agreement in the
manner set forth in the Credit Agreement. For the purpose hereof, the addresses
of the parties hereto (until notice of a change is delivered) shall be the
address set forth in the attachment to Schedule 1.
10. COUNTERPARTS; DELIVERY BY FACSIMILE. This Assignment Agreement may be
executed in counterparts. Transmission by facsimile of an executed counterpart
of this Assignment Agreement shall be deemed to constitute due and sufficient
delivery of such counterpart and such facsimile shall be deemed to be an
original counterpart of this Assignment Agreement.
IN WITNESS WHEREOF, the duly authorized officers of the parties hereto have
executed this Assignment Agreement by executing Schedule 1 hereto as of the date
first above written.
3
<PAGE>
SCHEDULE 1
to Assignment Agreement
1. Description and Date of Credit Agreement:
Credit Agreement dated as of July 17, 2000 among Southwestern Energy
Company, the lenders named therein including the Assignor, and Bank One, NA
individually and as Administrative Agent for such lender, as it may be
amended from time to time.
2. Date of Assignment Agreement:_________ , 20__
3. Amounts (As of Date of Item 2 above):
a. Assignee's percentage
of Aggregate Commitment
(Advances) purchased
under the Assignment
Agreement** ____%
b. Amount of
Assignor's Commitment
purchased
under the Assignment
Agreement** $______
4. Assignee's Commitment (or Loans
with respect to terminated
Commitments) purchased
hereunder: $___________________
5. Proposed Effective Date: ___________________
6. Non-standard Recordation Fee
Arrangement
N/A***
[Assignor/Assignee
to pay 100% of fee]
[Fee waived by Administrative Agent]
Accepted and Agreed:
[NAME OF ASSIGNOR] [NAME OF ASSIGNEE]
By:______________________ By:_____________________
Title____________________ Title:___________________
4
<PAGE>
ACCEPTED AND CONSENTED TO****
SOUTHWESTERN ENERGY COMPANY
By:_______________________________
Title:____________________________
** Percentage taken to 10 decimal places
*** If fee is split 50-50, pick N/A as option
**** Delete if not required by Credit Agreement
ACCEPTED AND CONSENTED
TO BY BANK ONE, NA,
as Administrative Agent
By:_______________________________
Title:____________________________
ACCEPTED AND CONSENTED
TO BY BANK OF AMERICA, N.A.,
as Syndication Agent
By:_______________________________
Title:____________________________
5
<PAGE>
Attachment to SCHEDULE 1 to ASSIGNMENT AGREEMENT
ADMINISTRATIVE INFORMATION SHEET
Attach Assignor's Administrative Information Sheet, which must
include notice addresses for the Assignor and the Assignee
(Sample form shown below)
ASSIGNOR INFORMATION
Contact:
Name:_____________________________ Telephone No.:__________________________
Fax No.:__________________________ Telex No.:______________________________
Answerback:_____________________________
Payment Information:
Name & ABA # of Destination Bank: ______________________
Account Name & Number for Wire Transfer:_______________________________________
_______________________________________________________________________________
Other Instructions:____________________________________________________________
Address for Notices for Assignor:______________________________________________
ASSIGNEE INFORMATION
Credit Contact:
Name:_____________________________ Telephone No.:__________________________
Fax No.:__________________________ Telex No.:______________________________
Answerback:_____________________________
Key Operations Contacts:
Booking Installation: Booking Installation:
Name: Name:
Telephone No.: Telephone No.:
Fax No.: Fax No.:
Telex No.: Telex No.:
Answerback: Answerback:
6
<PAGE>
Payment Information:
Name & ABA # of Destination Bank:
Account Name & Number for Wire Transfer:_______________________________
Other Instructions:
Address for Notices for Assignee:
7
<PAGE>
BANK ONE INFORMATION
Assignee will be called promptly upon receipt of the signed agreement.
Initial Funding Contact: Subsequent Operations Contact:
Name: Name:
Telephone No.: (312) Telephone No.: (312)
Fax No.: (312) Fax No.: (312)
Bank One Telex No.: 190201 (Answerback: FNBC UT)
Initial Funding Standards:
Libor Fund 2 days after rates are set.
Bank One Wire Instructions: Bank One, NA, ABA # 071000013
LS2 Incoming Account # 481152860000
Ref:________________
Address for Notices for Bank One : 1 Bank One Plaza, Chicago, IL 60670
Attn: Agency Compliance Division,
Suite IL1-0353
Fax No. (312) 7322038 or (312) 7324339
8
<PAGE>
EXHIBIT D
LOAN/CREDIT RELATED MONEY TRANSFER INSTRUCTION
To Bank One, NA,
as Administrative Agent (the "Administrative Agent") under the Credit
Agreement
Described Below.
Re: Credit Agreement, dated as of July 17, 2000 (as the same may be amended
or modified, the "Credit Agreement"), among Southwestern Energy Company (the
"Borrower"), the Lenders named therein and the Administrative Agent. Capitalized
terms used herein and not otherwise defined herein shall have the meanings
assigned thereto in the Credit Agreement.
The Administrative Agent is specifically authorized and directed to act
upon the following standing money transfer instructions with respect to the
proceeds of Advances or other extensions of credit from time to time until
receipt by the Administrative Agent of a specific written revocation of such
instructions by the Borrower, provided that the Administrative Agent may
otherwise transfer funds as hereafter directed in writing by the Borrower in
accordance with Section 13.1 of the Credit Agreement or based on any telephonic
notice made in accordance with Section 2.15 of the Credit Agreement.
Facility Identification Number(s)________________________________________
Customer/Account Name: [Borrower]
Transfer Funds To_________________________________________________________
_________________________________________________________
For Account No.___________________________________________________________
Reference/Attention To____________________________________________________
Authorized Officer (Customer Representative) Date________________
____________________________________________ _________________________
(Please Print) Signature
Bank Officer Name Date________________
____________________________________________ _________________________
(Please Print) Signature
(Deliver Completed Form to Credit Support Staff For Immediate Processing)
<PAGE>
EXHIBIT E
NOTE
[Date]
Southwestern Energy Company, an Arkansas corporation (the "Borrower"),
promises to pay to the order of ____________________________________ (the
"Lender") the aggregate unpaid principal amount of all Loans made by the Lender
to the Borrower pursuant to Article II of the Agreement (as hereinafter
defined), in immediately available funds at the main office of Bank One, NA in
Chicago, Illinois, as Administrative Agent, together with interest on the unpaid
principal amount hereof at the rates and on the dates set forth in the
Agreement. The Borrower shall pay the principal of and accrued and unpaid
interest on the Loans in full on the Final Maturity Date.
The Lender shall, and is hereby authorized to, record on the schedule
attached hereto, or to otherwise record in accordance with its usual practice,
the date and amount of each Loan and the date and amount of each principal
payment hereunder.
This Note is one of the Notes issued pursuant to, and is entitled to
the benefits of, the Credit Agreement dated as of July 17, 2000 (which, as it
may be amended or modified and in effect from time to time, is herein called the
"Agreement"), among the Borrower, the lenders party thereto, including the
Lender, and Bank One, NA, as Administrative Agent, to which Agreement reference
is hereby made for a statement of the terms and conditions governing this Note,
including the terms and conditions under which this Note may be prepaid or its
maturity date accelerated. Capitalized terms used herein and not otherwise
defined herein are used with the meanings attributed to them in the Agreement.
Notwithstanding anything to the contrary in this Note, no provision of
this Note shall require the payment or permit the collection of interest in
excess of the maximum permitted by applicable law ("Maximum Rate"). If any
interest in excess of the Maximum Rate is provided for or shall be adjudicated
to be so provided, in this Note or otherwise in connection with the loan
transaction, the provisions of this paragraph shall govern and prevail, and
neither the Borrower nor the sureties, guarantors, successors or assigns of the
Borrower shall be obligated to pay the excess of the interest or any other
excess sum paid for the use, forbearance, or detention of sums loaned. If for
any reason interest in excess of the Maximum Rate shall be deemed charged,
required or permitted by any court of competent jurisdiction, the excess shall
be applied as payment and reduction of the principal of indebtedness evidenced
by this Note, and, if the principal amount has been paid in full, any remaining
excess shall forthwith be paid to the Borrower.
<PAGE>
This Note shall be construed in accordance with the internal laws (and
not the law of conflicts) of the State of Illinois, but giving effect to Federal
laws applicable to national banks.
SOUTHWESTERN ENERGY COMPANY
By:____________________________________
Print Name:____________________________
Title:_________________________________
2
<PAGE>
SCHEDULE OF LOANS AND PAYMENTS OF PRINCIPAL
TO
NOTE
DATED JULY 17, 2000
- --------------------------------------------------------------------------------
: : Principal : Maturity : Principal : :
: Date : Amount of Loan : of Interest Period : Amount Paid : Unpaid Balance :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
: : : : : :
- --------------------------------------------------------------------------------
i
<PAGE>
EXHIBIT F
FORM OF COMPLIANCE CERTIFICATE
The undersigned, the _________________ of Southwestern Energy Company
(the "Borrower") hereby (a) delivers this Certificate pursuant to Section 6.1(c)
of the Credit Agreement dated as of July 17, 2000 (the "Agreement"; capitalized
terms used but not defined herein have the respective meanings given thereto in
the Agreement) among the Borrower, various financial institutions and Bank One,
NA, as Administrative Agent, and (b) certifies to each Lender as follows:
1. Attached as Schedule I are the financial statements of the Borrower as
of and for the Fiscal Year Quarter (check one) ended _____________, ________ .
2. Such financial statements have been prepared in accordance with
Agreement Accounting Principles and fairly present in all material respects the
financial condition of the Borrower as of the date indicated therein and the
results of operations for the respective periods covered thereby.
3. Attached as Schedule II are detailed calculations used by the Borrower
to establish whether the Borrower was in compliance with the requirements of
Section 6.4 of the Agreement on the date of the financial statements attached as
Schedule I.
4. Unless otherwise disclosed on Schedule III, neither a Default nor an
Unmatured Default has occurred which is in existence on the date hereof or, if
any Default or Unmatured Default is disclosed on Schedule III, the Borrower has
taken or proposes to take the action to cure such Default or Unmatured Default
set forth on Schedule III.
5. Except as described on Schedule IV, the representations and warranties
of the Borrower set forth in the Agreement are true and correct on and as of the
date hereof, with the same effect as though such representations and warranties
had been made on and as of the date hereof or, if such representations and
warranties are expressly limited to particular dates, as of such particular
dates.
IN WITNESS WHEREOF, the undersigned has duly executed this Certificate as
of __________, ________.
SOUTHWESTERN ENERGY COMPANY
By:____________________________________
Name:__________________________________
Title:_________________________________
<PAGE>
Schedule I
Financial Statements
(to be attached)
<PAGE>
Schedule II
Compliance Calculations
(to be attached)
<PAGE>
Schedule III
Defaults/Remedial Action
(to be attached)
<PAGE>
Schedule IV
Qualifications to Representations and Warranties
<PAGE>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>3
<FILENAME>0003.txt
<DESCRIPTION>CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
<TEXT>
EXHIBIT 23
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 5, 2001 included in this Form 10-K, into the Company's
previously filed Registration Statement on Form S-8 (File Nos. 333-03787,
333-03789, 333-64961 and 333-96161).
Tulsa, Oklahoma
March 30, 2001
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-27
<SEQUENCE>4
<FILENAME>0004.txt
<DESCRIPTION>FINANCIAL DATA SCHEDULE FOR 2000 10-K
<TEXT>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-END> DEC-31-2000
<CASH> 2,386
<SECURITIES> 0
<RECEIVABLES> 77,041
<ALLOWANCES> 0
<INVENTORY> 17,000
<CURRENT-ASSETS> 112,855
<PP&E> 1,118,723
<DEPRECIATION> 554,616
<TOTAL-ASSETS> 705,378
<CURRENT-LIABILITIES> 239,884
<BONDS> 225,000
<PREFERRED-MANDATORY> 0
<PREFERRED> 0
<COMMON> 2,774
<OTHER-SE> 138,517
<TOTAL-LIABILITY-AND-EQUITY> 705,378
<SALES> 353,040
<TOTAL-REVENUES> 363,883
<CGS> 0
<TOTAL-COSTS> 417,352
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 23,230
<INCOME-PRETAX> (74,702)
<INCOME-TAX> (28,905)
<INCOME-CONTINUING> (45,797)
<DISCONTINUED> 0
<EXTRAORDINARY> (890)
<CHANGES> 0
<NET-INCOME> (46,687)
<EPS-BASIC> (1.86)
<EPS-DILUTED> (1.86)
</TABLE>
</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----