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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1997
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or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from ______________ to ______________
Commission file number 1-8246
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SOUTHWESTERN ENERGY COMPANY
(Exact name of Registrant as specified in its charter)
ARKANSAS 71-0205415
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1083 Sain Street, P.O.Box 1408, Fayetteville, Arkansas 72702-1408
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(Address of principal executive offices, including zip code)
Registrant's telephone number, including area code (501) 521-1141
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Common Stock - Par Value $.10 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
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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
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The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $270,018,419 based on the New York Stock Exchange - Composite
Transactions closing price on March 26, 1998 of $11.
The number of shares outstanding as of March 26, 1998, of the
Registrant's Common Stock, par value $.10, was 24,848,237.
DOCUMENTS INCORPORATED BY REFERENCE
Documents incorporated by reference and the Part of the Form 10-K into
which the document is incorporated: (1) Annual Report to holders of the
Registrant's Common Stock for the year ended December 31, 1997 - PARTS I, II,
and IV; and (2) 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 21, 1998 - PART III.
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SOUTHWESTERN ENERGY COMPANY
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 1997
TABLE OF CONTENTS
PART I
Page
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Item 1. Business.......................................................................................... 1
Exploration and Production........................................................................ 1
Natural Gas Distribution ......................................................................... 7
Energy Services................................................................................... 11
Other Items....................................................................................... 13
Item 2. Properties........................................................................................ 14
Item 3. Legal Proceedings................................................................................. 16
Item 4. Submission of Matters to a Vote of Security Holders............................................... 16
Executive Officers of the Registrant.............................................................. 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters............................. 18
Item 6. Selected Financial Data........................................................................... 18
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............. 18
Item 8. Financial Statements and Supplementary Data....................................................... 19
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.............. 19
PART III
Item 10. Directors and Executive Officers of the Registrant................................................ 19
Item 11. Executive Compensation............................................................................ 19
Item 12. Security Ownership of Certain Beneficial Owners and Management.................................... 19
Item 13. Certain Relationships and Related Transactions.................................................... 20
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................. 20
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PART I
Item 1. Business
Southwestern Energy Company (the "Company" or "Southwestern") is an
integrated energy company primarily focused on natural gas. The Company was
organized in 1929 as a local gas distribution company in northwest Arkansas. The
Company is incorporated under the laws of the state of Arkansas and is an exempt
holding company under the Public Utility Holding Company Act of 1935. Today, the
Company's operations are carried out by 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, south Louisiana, and
the Gulf Coast.
2. Natural Gas Distribution -- Engaged in the gathering, distribution and
transmission of natural gas to approximately 177,000 customers in
northern Arkansas and parts of Missouri.
3. Energy Services -- Provides marketing and transportation services to a
variety of commercial and industrial customers in the Mid-Continent
area of the United States. Supply sources include both Company owned
natural gas and oil production as well as third-party production. Owns
a general partnership interest in the NOARK Pipeline System, Limited
Partnership (NOARK).
Financial and operating statistics for Southwestern's business segments are
included in the Company's consolidated financial statements, incorporated by
reference in Part II, Item 8 of this report, "Financial Statements and
Supplementary Data". A discussion of the primary businesses conducted by the
Company through its wholly-owned subsidiaries follows.
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.
Exploration and Production
In 1943, the Company commenced a program of exploration for 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 requirements. Since that time, the Company's
exploration and development activities outside Arkansas have expanded
substantially. The Company's exploration and production activities consist of
ownership of mineral interests in productive and undeveloped leases located
entirely within the United States.
At December 31, 1997, the Company had proved natural gas reserves of 291.4
billion cubic feet (Bcf) and proved oil reserves of 7,852 thousand barrels
(MBbls). Revenues of the exploration and production
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subsidiaries are predominately generated from production of natural gas. Sales
of gas production accounted for 86% of total operating revenues for this segment
in 1997, 90% in 1996, and 93% in 1995.
Areas of Operation
The Company 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 section of the Arkoma Basin. SEPCO conducts
development drilling and exploration programs in areas outside Arkansas,
including the Gulf Coast areas of Louisiana and Texas, the Anadarko Basin of
Oklahoma, and the Permian Basin of Texas and New Mexico. Diamond M operates
properties in the Permian Basin of Texas.
During 1997, Southwestern brought in new senior operating management to
refocus its exploration and production segment. In early 1998, the Company
consolidated its exploration and land efforts to its Houston office and
reorganized its staff into asset management teams. Three exploitation teams were
formed (an Arkoma team, a Mid-Continent team and a Gulf Coast team) to manage
Southwestern's producing properties, and three exploration teams were formed
(two south Louisiana teams and a new ventures team) to provide an area specific
focus in exploration projects.
Arkoma. Southwestern has been active in the Arkansas portion of the Arkoma
Basin since 1943. As a result, it has acquired a substantial acreage position
and reserve base in the basin. At December 31, 1997, the Company had
approximately 213.4 Bcf of natural gas reserves in the Arkoma Basin. This
represents 73% of the Company's natural gas reserves and 63% of total reserves
on a Bcf equivalent basis. Southwestern's average net daily production in 1997
in the Arkoma Basin was 62.0 million cubic feet equivalent (Mmcfe).
In recent years, Southwestern has conducted its Arkansas development
drilling program primarily within the boundaries of its utility gathering
system. In 1997, the Company accelerated the extension of its Arkoma drilling
program outside of its traditional areas to new fields. Southwestern enjoyed
successful stepout drilling in the lightly-explored southern edges of the Arkoma
Basin in Arkansas, as well as positive results from drilling in the western part
of the basin in Oklahoma. Overall, the Company participated in 69 gross wells
(36.6 net) in the Arkoma Basin during 1997, including 28 which were operated by
the Company. These wells contributed 13.1 Bcf to total 1997 reserve additions.
During 1998, Southwestern plans to continue to capitalize on its geological
experience in the Arkoma Basin and increase its emphasis on development drilling
outside of the traditional Arkansas fairway.
Mid-Continent. The Company's activities in this region are primarily
focused on the Anadarko Basin of Oklahoma and Permian Basin of Texas and New
Mexico. Southwestern has been active in the Mid-Continent region since 1971. At
December 31, 1997, the Company had approximately 46.2 Bcf of natural
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gas reserves and 5,172 MBbls of oil reserves in the region, representing 16% and
66%, respectively, of the Company's total gas and oil reserves. Average net
daily production in 1997 for this region was 23.9 Mmcfe.
In recent years, Southwestern has experienced excellent success in the
lower and middle Morrow formations in the Permian Basin in southeast New Mexico.
Since its first exploratory discovery there in 1995, the Company's drilling
program in this area has resulted in 14 successful wells of 15 drilled. The most
recent was the Gaucho #4, which is currently flowing at a rate of 10 MMcf of
natural gas per day. Three wells have now been drilled within the Gaucho
prospect and are producing at a combined daily rate of 25 MMcf of natural gas
and 125 barrels of condensate. Southwestern has a 50% working interest in the
Gaucho unit.
Gulf Coast/South Louisiana. The Company became active in the Gulf Coast
area in 1990. At December 31, 1997, the Company had approximately 30.8 Bcf of
natural gas reserves and 1,480 MBbls of oil reserves in the region, representing
11% and 19%, respectively, of the Company's total gas and oil reserves. Average
net daily production in 1997 for this region was 15.8 Mmcfe. Southwestern's
initial strategy during entry into the upper Texas Gulf Coast and south
Louisiana revolved around participating in wells drilled to prove a prospect.
These exploratory wells had the potential for significant reserve additions, but
development opportunities were limited and a dry hole generally condemned the
prospect. This strategy did not meet Southwestern's reserve growth and
production goals, but it did enable the Company to establish a presence in the
region. As 3-D seismic technology became more widely accepted as an exploration
tool, Southwestern gained entry to a number of high potential joint ventures to
develop multiple, high quality prospects. The Company's typical project relies
on options to obtain access to leasehold acreage over a large prospective area.
The committed acreage is evaluated for leasing after 3-D seismic data is
acquired, thus optimizing the Company's investment.
The Company is actively pursuing its exploration and development strategy
in south Louisiana. Southwestern has an inventory of over 400 square miles of
3-D seismic data and, at the end of 1997, had invested approximately $37.2
million in leasehold and seismic data acquisition costs related to the Company's
major projects in south Louisiana. Each project is in a separate development
stage, which maximizes Southwestern's ability to fully fund their development.
The Company's major exploration projects in south Louisiana are as follows:
East Atchafalaya: Southwestern became involved in this project in mid-1995
through a 50-50 joint venture with Union Pacific Resources. The joint venture
has acquired 113 square miles of 3-D seismic data covering portions of St.
Martin and Iberia Parishes, Louisiana. During 1997, drilling was initiated. The
Company participated in four wells, two deep tests and two shallower wells.
While the first deep test and one shallow well did not find commercially
productive reserves, the other shallow well was completed in the Planulina
formation and is currently producing 4 MMcf of natural gas per day. The fourth
well, located in the Gator prospect, was spudded in December, 1997, to test a
deep Oligocene target and reached its objective total depth of 18,000 feet in
February, 1998. The well did not find hydrocarbons in the primary objective,
however, the well has been completed in a shallower secondary objective.
Additional wildcat drilling is planned in 1998.
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Henry: This project was originated by Southwestern and includes the
acquisition of approximately 110 square miles of 3-D seismic data in Vermillion
Parish, Louisiana. Southwestern's Henry project continued on schedule in 1997
and drilling is expected in the second half of 1998. Southwestern received the
final processed 3-D data in September, 1997, and is in the process of
interpreting this data. To date, a number of prospect leads have been identified
and prospect generation is ongoing. Southwestern plans to drill up to four wells
in Henry during 1998. The Company presently owns a 100% interest in the project.
Boure[180]: During 1997, Southwestern and its partner initiated a 185
square mile 3-D survey in Assumption Parish adjacent to the East Atchafalaya
project area. Southwestern has a 50% working interest in the project. Actual
shooting of the 3-D program began in January, 1998, with field work likely to
continue through the middle of 1998. Southwestern should begin to receive
portions of the 3-D seismic data in the second half of 1998, with drilling
expected to begin in 1999.
Southwestern also has interests in three other smaller prospect areas in
south Louisiana which are supported by 3-D seismic data and has active
exploration prospects in Oklahoma and New Mexico. The Company's strategy is to
balance the risks inherent in its exploration program with continued development
drilling, primarily in the Arkoma Basin of Arkansas, and with producing property
acquisitions in its core operating areas.
Acquisitions
In recent years, the Company increased its emphasis on acquisitions of
producing properties. However, in 1997, the market for producing property
acquisitions was demand-driven causing existing properties to sell at higher
prices as compared to historical levels. As a result, the Company did not make
any producing property acquisitions in 1997, compared to $45.8 million spent in
1996, $6.0 million spent in 1995, and $13.9 million in 1994. The Company
acquired approximately 32.7 Bcf of gas and 6,350 MBbls of oil during 1996, 4.5
Bcf of gas and 851 MBbls of oil during 1995, and 20.6 Bcf of gas and 1,038 MBbls
of oil during 1994. The 1996 acquisitions were primarily in Texas and Oklahoma,
the 1995 acquisitions were primarily in the Gulf Coast areas of Louisiana and
Texas, and the 1994 acquisitions were primarily in the Anadarko Basin of
Oklahoma. The largest single acquisition completed by the Company was a
transaction in which the Company acquired substantially all the oil and gas
properties owned by L.B. Simmons Energy, Inc. of Houston for $30.9 million. The
acquisition closed on November 1, 1996. Proved reserves acquired were 6 million
barrels of oil and 17 Bcf of natural gas, located primarily in west Texas and
Oklahoma. At the end of 1997, oil accounted for 14% of the Company's proved
reserves, up from 4% at the end of 1995, primarily due to this acquisition.
Capital Spending
The Company expects its 1998 capital expenditures for gas and oil
exploration and development to total $59.2 million, down from $73.5 million in
1997. During 1997, a large portion of capital spending was devoted to land and
seismic data acquisition. Expenditures in 1998 will direct more funds toward the
drilling of exploratory wells, reflecting the inventory of drilling prospects
which has been established.
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Sales and Major Customers
Natural gas equivalent production rose to 104 million cubic feet per day
(MMcfd) in 1997, up from 101 MMcfd in 1996, and 98 MMcfd in 1995. The increase
in production was the ninth in the last ten years, and represented the second
highest level in the Company's history. The Company's gas production was 33.4
Bcf in 1997, down from 34.8 Bcf in 1996, and 34.5 Bcf in 1995. The Company also
produced 749,000 barrels of oil in 1997, up from 391,000 barrels in 1996, and
229,000 barrels in 1995.
The Company's natural gas production received an average wellhead price of
$2.57 per thousand cubic feet (Mcf) in 1997, up from $2.26 per Mcf in 1996 and
$1.72 per Mcf in 1995. Oil prices were weaker, with an average price in 1997 of
$19.02 per barrel, compared to $21.21 per barrel in 1996 and $17.15 per barrel
in 1995.
Southwestern's largest single customer for sales of its gas production is
the Company's utility subsidiary, Arkansas Western Gas Company (Arkansas
Western). These sales are made by SEECO. Sales to Arkansas Western accounted for
approximately 42% of total exploration and production revenues in 1997, 46% in
1996, and 47% in 1995. Sales to unaffiliated purchasers accounted for 62% of
total equivalent oil and gas volumes sold by the exploration and production
segment in 1997, 56% in 1996, and 61% in 1995.
SEECO's production was 21.7 Bcf in 1997, down from 23.1 Bcf in 1996 and
24.3 Bcf in 1995. SEECO's sales to Arkansas Western were 14.3 Bcf in 1997, down
from 16.3 Bcf in 1996 and up from 13.9 Bcf in 1995. SEECO's sales to
unaffiliated purchasers were 7.4 Bcf in 1997, 6.8 Bcf in 1996, and 10.4 Bcf in
1995.
Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas
division (AWG) were 8.6 Bcf in 1997, 10.1 Bcf in 1996, and 8.5 Bcf in 1995.
Through these sales, SEECO furnished 64% of the northwest Arkansas system's
requirements in 1997, 62% in 1996, and 65% in 1995. SEECO also delivered
approximately 1.0 Bcf in 1997, 1.1 Bcf in 1996, and 1.4 Bcf in 1995 directly to
certain large business customers of AWG through a transportation service of the
utility subsidiary. Most of the sales to AWG are 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 hereafter referred to as the "Gas Cost
Settlement." The Gas Cost Settlement became effective July 1, 1994, and calls
for sales under the contract to take place at a price which is equal to a spot
market index plus a premium. The amended contract provides that volumes equal to
the historical level of sales under the contract will be sold at the spot market
index plus a premium of $.95 per thousand cubic feet (Mcf), while incremental
sales volumes receive a premium of $.50 per Mcf. In 1997, 8.2 Bcf (net to the
Company's interest) was sold under the contract, compared to 8.6 Bcf in 1996 and
7.7 Bcf in 1995. The sales price under this contract averaged $3.35 per Mcf in
1997, $3.03 per Mcf in 1996, and $2.40 per Mcf in 1995. This contract expires
July 24, 1998. AWG has proposed to enter into a new intersegment gas supply
contract for a similar portion of its system needs at a price competitive with
the cost of alternative supplies. For further discussion see "Gas Purchases and
Supply" under the "Natural Gas Distribution" section below. In addition to this
contract,
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SEECO also sells gas to AWG under newer long-term contracts with flexible
pricing provisions and under short-term spot market arrangements.
SEECO's sales to Associated Natural Gas Company (Associated), a division of
Arkansas Western which operates natural gas distribution systems in northeast
Arkansas and parts of Missouri, were 5.7 Bcf in 1997, 6.2 Bcf in 1996, and 5.4
Bcf in 1995. These deliveries accounted for approximately 61% of Associated's
total requirements in 1997, 62% in 1996, and 59% in 1995. 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. The sales
price under this contract was $2.20 per Mcf for the contract period ended
September 30, 1995, $1.785 per Mcf for the contract period ended September 30,
1996, and $2.225 per Mcf for the contract period ended September 30, 1997. 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. The sales price under the contract was $2.54 for the month of December,
1997.
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 is also affected by the demand of the utility
for production on its gathering system. SEECO's sales to unaffiliated purchasers
accounted for approximately 15% of total exploration and production revenues in
1997, 14% in 1996, and 21% in 1995.
The combined gas production of SEPCO and Diamond M was 11.7 Bcf in 1997 and
1996, up from 10.3 Bcf in 1995. Oil production was 749 MBbls in 1997, compared
to 391 MBbls in 1996 and 229 MBbls in 1995. The increases in equivalent
production in 1997 and 1996 primarily resulted from acquisitions of producing
properties in recent years. 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 43% of total exploration
and production revenues in 1997, 40% in 1996, and 32% in 1995.
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.
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
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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 which may affect both
the price it receives and contract terms it must offer. Outside Arkansas, the
Company is less well-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 outside Arkansas.
Natural Gas Distribution
The Company's subsidiary Arkansas Western Gas Company operates integrated
natural gas distribution systems concentrated primarily in northern Arkansas and
southeast Missouri. The Arkansas Public Service Commission (APSC) and the
Missouri Public Service Commission (MPSC) regulate the Company's utility rates
and operations. The Company serves approximately 177,000 customers and obtains a
substantial portion of the gas they consume through its Arkoma Basin gathering
facilities.
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 108,000 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 69,000 customers
primarily in northeast Arkansas and southeast Missouri. 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 directly at the wellhead under
long-term contracts. Purchases are made from approximately 246 working interest
owners in 504 producing wells. As previously indicated, SEECO furnished
approximately 64% of AWG's system requirements in 1997, 62% in 1996, and 65% in
1995. A significant portion of AWG's unaffiliated supply comes from market
responsive, long-term contracts.
At December 31, 1997, AWG had a gas supply available to its northwest
Arkansas system of approximately 172 Bcf of proved developed reserves, equal to
10.3 times current annual usage. Of this total, approximately 96 Bcf were net
reserves available from SEECO. A portion of these reserves are utilized to meet
the annual sales volume commitment of 9.0 Bcf (gross) under the amended
long-term contract with AWG. For purposes of determining AWG's available gas
supply, deliveries to AWG's spot market purchasing program or transportation
customers and the reserves related to those deliveries are not considered.
AWG's twenty-year gas supply contract with SEECO expires in July, 1998. In
March, 1997, AWG filed a gas supply plan with the APSC which projects system
load growth patterns and long range gas supply
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needs for the utility's northwest Arkansas system. As part of its long range
supply plan, AWG has proposed to enter into a new intersegment gas supply
contract for a similar portion of its system needs at a price competitive with
the cost of alternative supplies. The APSC has not yet approved AWG's gas supply
plan. The Company expects that the volumes will continue to be sold to AWG.
However, it is possible that the APSC may reject AWG's gas supply plan and
require that the gas supply now provided under this contract be replaced through
a competitive bidding process, involving multiple potential suppliers. If this
occurs, SEECO's continued sales of these volumes to AWG, and the price of any
such sales, will depend on the result of this competitive bidding process.
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 liabilities resulting from these contracts, although the Company's
exposure to take-or-pay liabilities to its gas suppliers has increased in recent
years as a result of a decline in its gas supply requirements. This decline
occurred because some of its large business customers converted to the
transportation service offered by AWG and began to obtain their own gas supplies
directly from other sources. 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 SEECO. Purchases from SEECO are under
a ten-year contract with annual price redeterminations. Purchases from
unaffiliated suppliers are under firm contracts with terms between one and three
years. The rates charged by these suppliers include demand components to ensure
availability of gas supply, administrative fees, and a commodity component which
is based on spot market gas prices. Associated's gas purchases are transported
through eight pipelines. The pipeline transportation rates include demand
charges to reserve pipeline capacity and commodity charges based on volumes
transported. Associated has also contracted with five interstate pipelines 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.
AWG has no restriction on adding new residential or commercial customers
and will supply new industrial customers which 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.
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 155,000 residential, 22,000 commercial, and 300
industrial customers, while also providing gas transportation services to
approximately 50 end-use and off-system customers. Total gas throughput in 1997
was 37.0 Bcf, down from 39.0 Bcf in
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1996, and 42.4 in 1995. Off-system transportation volumes were 2.8 Bcf in 1997,
compared to 3.6 Bcf transported in 1996, and 9.8 Bcf transported in 1995.
Residential and Commercial. Approximately 80% of the utility's revenues are
from residential and commercial markets. Residential and commercial customers
combined accounted for 57% of total gas throughput for the gas distribution
segment in 1997 and 1996, and 46% in 1995. Gas volumes sold to residential
customers were 12.6 Bcf, down from 13.4 Bcf sold in 1996 and up from 12.1 Bcf
sold in 1995. Gas sold to commercial customers totaled 8.4 Bcf in 1997, down
from 8.8 Bcf in 1996 and up from 7.6 Bcf in 1995. The decrease in gas volumes
sold in 1997 was due to weather in Arkansas Western's service territory which
was 5% warmer than in 1996, partially offset by customer growth of 2.2% in its
combined service territories during 1997.
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 as a result of the
recently approved rate filings 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 include end-use transportation deliveries, have increased for the eleventh
consecutive year, reflecting both the success of the Company's industrial
marketing efforts and the continued economic strength of its service territory.
Industrial customers, which are generally smaller concerns using gas for plant
heating or product processing, accounted for 13.2 Bcf in gas deliveries in 1997
and 1996, and 13.0 Bcf in 1995. No industrial customer accounts for more than 6%
of Arkansas Western's total throughput.
In an effort to more fully meet the service needs of larger business
customers, both AWG and Associated instituted a transportation service in 1991
that allows such customers in Arkansas to obtain their own gas supplies directly
from other suppliers. A total of 45 customers are currently using the Arkansas
transportation service. Eleven of AWG's twelve largest customers in northwest
Arkansas, including the seven largest, are using the transportation service.
Associated's four largest customers in northeast Arkansas and ten of
Associated's eleven largest Missouri customers are currently using
transportation service.
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 which 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 is generally the least expensive, most readily available
fuel in the service territories of AWG and Associated.
The competition from alternative fuels and, in a limited number of cases,
alternative sources of natural gas has intensified in recent years. Industrial
customers are most likely to consider utilization of these
9
<PAGE>
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
nongas 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 and
MPSC. In Arkansas, the Company operates through municipal franchises which are
perpetual by state law. These franchises, however, are not exclusive within a
geographic area. In Missouri, the Company operates through municipal franchises
with various terms of existence.
Over the past several years, changes at the federal level have brought
significant changes to the regulatory structure governing interstate sales and
transportation of natural gas. The Federal Energy Regulatory Commission's (FERC)
Order No. 636 series changed a major portion of the gas acquisition merchant
function provided to gas distributors by interstate pipelines. AWG already
obtains its supply at the wellhead directly from producers and has not been
directly impacted by Order No. 636. Associated has acquired the bulk of its gas
supply at the wellhead since its acquisition by Arkansas Western, but continued
until Order No. 636 to purchase a portion of both its peak and base requirements
from interstate suppliers. The changes mandated by Order No. 636 have placed the
responsibility for arranging firm supplies of natural gas directly on local
distribution companies and have, as a result, lessened the ability of Associated
to purchase gas on the short-term spot market.
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 are presently pending in Arkansas or Missouri, the Company is
aggressively controlling costs and constantly evaluating issues such as system
capacity and reliability, obligation to serve, and rate design, with an eye
toward minimizing any stranded or transition costs.
Gas distribution revenues in future years will be impacted by both customer
growth and rate increases allowed by regulatory commissions. In recent years,
AWG has experienced customer growth of approximately 3% to 4% annually, while
Associated has experienced customer growth of approximately 1% annually. Based
on current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue. AWG and Associated pass along
to customers through an automatic cost of gas adjustment clause any increase or
decrease experienced in purchased gas costs. In December, 1996, AWG received
approval from the APSC for a rate increase of $5.1 million annually. The
10
<PAGE>
Company received approvals in December, 1997 from the APSC and the MPSC for rate
increases and tariff changes for Associated which will allow the utility to
collect an additional $3.0 million annually. Of the $3.0 million increase,
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. Rate increase requests which
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
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.
Energy Services
Gas Marketing
The energy services 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.
During 1997, the group expanded its presence in natural gas marketing, building
a diverse customer base and providing a broad range of services at competitive
prices. In the future, the energy services group plans to further expand its
natural gas marketing activities, with particular emphasis on third-party
marketing in the Mid-Continent region of the United States. The planned merger
of NOARK with the Ozark Gas Transmission System (Ozark) discussed below will
afford greater supply and market opportunities, allowing the group to expand its
marketing operations in Oklahoma. Southwestern expects the contributions by this
segment to increase in significance as the pace of deregulation in the energy
industry accelerates.
The Company's marketing operations include the marketing of Southwestern's
own gas production and third-party natural gas. The segment marketed 36.2 Bcf of
natural gas in 1997, compared to 13.0 Bcf in 1996, and 19.9 Bcf in 1995. Of the
total volumes marketed, purchases from the Company's exploration and production
subsidiaries accounted for 23% in 1997, 56% in 1996, and 59% in 1995.
Pipeline Operations
A portion of the activity of the energy services segment involves the NOARK
Pipeline System, Limited Partnership. At December 31, 1997, the Company held a
48% general partnership interest in NOARK and served as the pipeline's operator.
The 258-mile long intrastate natural gas transmission system originates near the
Fort Chaffee military reservation in western Arkansas and terminates in
northeast Arkansas, crossing three major interstate pipelines and
interconnecting with the Company's distribution systems. NOARK's main line was
completed and placed in service in September, 1992. A lateral line of NOARK that
allows the Company's gas distribution segment to augment its supply to an
existing market, as well as supply gas to new markets, was completed and placed
in service in November, 1992. Construction of an eight-mile interstate pipeline
connecting NOARK to the distribution system of Associated was completed during
1993.
11
<PAGE>
AWG provides field management services to NOARK under a contract with the
partnership and AWG's gathering system delivers to NOARK a substantial part of
the gas NOARK transports. In 1997, NOARK had an average daily throughput of 40
MMcfd, compared to 58 MMcfd in 1996, and 86 MMcfd in 1995. NOARK's current
capacity is 141 MMcfd. Arkansas Western has contracted for 52.3 MMcfd of firm
capacity on NOARK. The contract expires in 2002 and is renewable year to year
until terminated with 180 days notice.
While NOARK has always accessed good markets, its performance has been
hindered by a lack of adequate gas supply. NOARK has been operating below
capacity and generating losses since it was placed in service. As a result of
these continuing losses, the Company investigated options to improve NOARK's
future financial prospects, including an extension into Oklahoma that would
provide additional access to gas supply. 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
the integration of NOARK with the Ozark Gas Transmission System (Ozark). Ozark
is a 437-mile interstate pipeline system which begins near McAlester, Oklahoma
and terminates near Searcy, Arkansas. Ozark has a throughput capacity of
approximately 170 MMcfd. Enogex has entered into an agreement to acquire Ozark
from NGC Corporation for $55.0 million and will contribute Ozark to the NOARK
partnership when regulatory approvals are obtained. Enogex has also acquired the
NOARK partnership interests not held by Southwestern. Subject to approval by the
Federal Energy Regulatory Commission, NOARK will be converted to an interstate
pipeline and be operated with Ozark as an integrated system.
In addition to its purchase of Ozark, Enogex will fund the integration
project and an expansion of the combined system at an estimated cost of $15.0
million. The two pipelines currently have a minor interconnection and run in
general proximity to each other in western Arkansas, but a larger
interconnecting pipeline and compression will be constructed to enable the Ozark
line in Oklahoma to serve as the supply line for both NOARK and Ozark. The
combined pipelines will have capacity of approximately 330 MMcfd. The integrated
system is expected to be operational in late 1998. After the integration is
complete, Southwestern will have a 25% interest in the expanded project and
Enogex will have a 75% interest.
Competition
The Company's energy 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 proximity of pipelines and other transportation
facilities. The Company believes that its ability to effectively compete within
the energy marketing segment in the future depends upon establishing and
maintaining strong relationships with producers and end-users.
NOARK currently competes with two interstate pipelines, one of which is 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 has been strong and has resulted in NOARK transporting
12
<PAGE>
gas for third parties at rates below the maximum tariffs presently allowed. The
planned integration with Ozark will provide the Company's pipeline operations
with increased supplies to transport to both local markets and markets served by
the three major interstate pipelines that NOARK 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 the integration of
NOARK and Ozark 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 existng 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. While some
regulatory uncertainty remains, Order No. 636 may ultimately enhance the ability
of the Company to market natural gas, although it may also create greater
competition for the Company.
The operations of NOARK are currently regulated by the APSC. The APSC has
established a maximum transportation rate of approximately $.285 per dekatherm
based on NOARK's original construction cost estimate of $73 million. The planned
integration of NOARK with Ozark will result in an interstate pipeline system
subject to FERC regulations and FERC approved tariffs. A filing was made with
the FERC on March 5, 1998, seeking approval for the acquisition of Ozark by
Enogex and the integration of NOARK and Ozark. The APSC will no longer have
jurisdiction over NOARK's transportation rates and services once the integrated
system is placed in service.
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.
13
<PAGE>
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 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 170 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 near the
Company's headquarters in a growing part of Fayetteville, Arkansas. 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
which 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, 1997, the Company had 705 employees, 99 of whom are
represented under a collective bargaining agreement. The Company believes that
its relations with its employees are good.
Item 2. Properties
The portions of the Registrant's 1997 Annual Report to Shareholders (filed
as Exhibit 13 to this filing) listed below are hereby incorporated by reference
for the purpose of describing its properties.
Refer to the Appendix (filed as part of Exhibit 13 to this filing) for
information concerning areas of operation of the Company's business segments.
See the table entitled "Gas Distribution Systems" at the Appendix for
information concerning miles of pipe of the Company's gas distribution systems.
Also, see pages 37 and 38 (Notes 5 and 6 to the financial statements) for
additional information about the Company's gas and oil operations. For
information concerning capital expenditures, refer to page 27 ("Capital
Expenditures" section of "Management's Discussion and Analysis of Financial
Condition and Results of Operations"). Also refer to page 45 ("Financial and
Operating Statistics") for information concerning gas and oil produced.
The following information is provided to supplement that presented in the
1997 Annual Report to Shareholders:
14
<PAGE>
<TABLE>
<CAPTION>
Leasehold Acreage
Undeveloped Developed
Gross Net Gross Net
----------------- -------------------
<S> <C> <C> <C> <C>
Arkansas.................... 234,319 107,140 316,542 141,977
Oklahoma.................... 27,512 14,909 98,268 45,541
Texas....................... 16,905 7,429 96,158 30,825
Louisiana................... 35,144 18,742 39,792 6,485
New Mexico.................. 10,104 7,932 23,859 8,732
Other areas................. - - 17,554 4,773
----------------- -------------------
323,984 156,152 592,173 238,333
================= ===================
</TABLE>
<TABLE>
<CAPTION>
Producing Wells
Gas Oil Total
Gross Net Gross Net Gross Net
----------------- ------------------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Arkansas.................... 784 411.9 - - 784 411.9
Oklahoma.................... 551 238.7 662 152.4 1,213 391.1
Texas....................... 117 34.8 158 119.4 275 154.2
Louisiana................... 14 4.5 26 17.7 40 22.2
New Mexico.................. 9 1.9 15 11.5 24 13.4
Other areas................. - - 50 14.1 50 14.1
----------------- ------------------- -----------------
1,475 691.8 911 315.1 2,386 1,006.9
================= =================== =================
</TABLE>
<TABLE>
<CAPTION>
Net Wells Drilled During the Year
Exploratory
Productive
Year Wells Dry Holes Total
---- ---------- --------- -----
<S> <C> <C> <C>
1997 . . . . 1.3 3.0 4.3
1996 . . . . 5.3 3.0 8.3
1995 . . . . 6.3 7.1 13.4
Development
Productive
Year Wells Dry Holes Total
---- ---------- --------- -----
1997 . . . . 27.5 13.5 41.0
1996 . . . . 29.4 11.8 41.2
1995 . . . . 37.5 19.4 56.9
</TABLE>
15
<PAGE>
<TABLE>
<CAPTION>
Wells in Progress as of December 31, 1997
Type of Well Gross Net
------------ ----- ---
<S> <C> <C>
Exploratory............................ 3.0 1.6
Development............................ 9.0 4.4
----- ---
Total.................................. 12.0 6.0
===== ===
</TABLE>
No individually significant discovery or other major favorable or adverse
event has occurred since December 31, 1997.
During 1997, 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 1997 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 May, 1996, a lawsuit was filed against the Company involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties. In a related matter, a purported class action suit was filed against
the Company in May, 1996 on behalf of royalty owners alleging improprieties in
the disbursement of royalty proceeds. The Company feels these claims are
substantially without merit and intends to vigorously contest the claims brought
in each matter. While the amount of the potential claims is significant in the
aggregate, management believes, based on its investigation, that the Company's
ultimate liability, if any, will not be material to its consolidated financial
position or results of operations.
The Company and its subsidiaries are involved in various other legal
proceedings arising in the ordinary course of business. While the outcome of
lawsuits or other proceedings cannot be predicted with certainty, management
expects these matters will not have a material adverse effect on the
consolidated financial position or results of operations 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, 1997, to a vote of security holders, through the solicitation
of proxies or otherwise.
16
<PAGE>
<TABLE>
<CAPTION>
Executive Officers of the Registrant
Years Served as
Name Officer Position Age Officer
---- ---------------- --- -------
<S> <C> <C> <C>
Charles E. Scharlau Chairman of the Board and Chief Executive Officer 70 40
Stanley D. Green Executive Vice President - Finance and Corporate 44 16
Development and Chief Financial Officer
Harold M. Korell Executive Vice President - Operations and 53 1
Chief Operating Officer
Debbie J. Branch Senior Vice President, Southwestern Energy Services 46 2
Company and Southwestern Energy Pipeline Company
Gregory D. Kerley Senior Vice President - Treasurer and Secretary and 42 8
Chief Accounting Officer
Alan H. Stevens Senior Vice President, Southwestern Energy Production 53 -
Company and SEECO, Inc.
Charles V. Stevens Senior Vice President, Arkansas Western Gas Company 48 9
</TABLE>
Mr. Scharlau was elected to his present position in 1979. He has served as
Chief Executive Officer since 1968.
Mr. Green was elected to his present position in 1992 and has served as
Chief Financial Officer since 1987. Previously, he served as Vice President -
Treasurer and Secretary from 1987 to 1992, and as Controller from 1981 to 1990.
Mr. Korell joined the Company in his present position in 1997. 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.
Ms. Branch joined the Company in her present position in 1996. Prior to
joining the Company, she was Executive Vice President of Stalwart Energy Company
from 1994 to 1996 and founder and President of Vesta Energy Company from 1983 to
1993.
17
<PAGE>
Mr. Kerley was elected to his present position in December, 1997 and has
served as Chief Accounting Officer since 1990. Previously, he served as Vice
President - Treasurer and Secretary from 1992 to 1997, and Controller from 1990
to 1992.
Mr. Alan Stevens joined the Company in his present position in January,
1998. Prior to joining the Company, he was President and Chief Operating Officer
for Petsec Energy during 1997. Previously, he was Vice President of Worldwide
Exploration for Occidental Petroleum Company from 1989 to 1997.
Mr. Charles 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.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Shareholder Information on page 46 and "Common Stock Statistics" included
in the Company's Financial and Operating Statistics on page 44 of the 1997
Annual Report to Shareholders (filed as Exhibit 13 to this filing) are hereby
incorporated by reference for information concerning the market for and prices
of the Company's Common Stock, the number of shareholders, and cash dividends
paid.
The terms of certain of the Company's long-term debt instruments and
agreements impose restrictions on the payment of cash dividends. At December 31,
1997, $129.1 million of retained earnings was available for payment as cash
dividends. These covenants generally limit the payment of dividends in a fiscal
year to the total of net income plus $20.0 million less dividends paid and
purchases, redemptions or retirements of capital stock during the period since
January 1, 1990. Dividends totaling $5.9 million were paid during 1997.
The Company paid dividends at an annual rate of $.24 per share in 1997 and
1996. While the Board of Directors intends to continue the practice of paying
dividends quarterly, amounts and dates of such dividends as may be declared will
necessarily be dependent upon the Company's future earnings and capital
requirements.
Item 6. Selected Financial Data, and
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations, and
18
<PAGE>
Item 8. Financial Statements and Supplementary Data
The following portions of the 1997 Annual Report to Shareholders (filed as
Exhibit 13 to this filing) are hereby incorporated by reference.
Refer to pages 44 and 45 ("Financial and Operating Statistics") for
selected financial data of the Company.
Refer to the text on pages 23 through 28 for "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
Refer to pages 30 through 45 for financial statements and supplementary
data.
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 21, 1998 (the 1998 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
"Security Ownership of Directors, Nominees, and Executive Officers" 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 1998 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about executive compensation. Refer to the
section "Executive Compensation."
Item 12. Security Ownership of Certain Beneficial Owners and Management
The 1998 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 "Security Ownership of Directors, Nominees, and Executive
Officers" for information about security ownership of certain beneficial owners
and management.
19
<PAGE>
Item 13. Certain Relationships and Related Transactions
The 1998 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about related transactions. Refer to the
section "Security Ownership of Directors, Nominees, and Executive Officers" 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 following consolidated financial statements of the Company and
its subsidiaries, included on pages 30 through 43 of its 1997 Annual Report to
Shareholders (filed as Exhibit 13 to this filing) and the report of independent
public accountants on page 29 of such report are hereby incorporated by
reference:
Report of Independent Public Accountants.
Consolidated Balance Sheets as of December 31, 1997 and 1996.
Consolidated Statements of Income for the years ended December 31,
1997, 1996, and 1995.
Consolidated Statements of Cash Flows for the years ended December
31, 1997, 1996, and 1995.
Consolidated Statements of Retained Earnings for the years ended
December 31, 1997, 1996, and 1995.
Notes to Consolidated Financial Statements,December 31, 1997, 1996,
and 1995.
(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 22 - 24)
are filed as part of, or incorporated by reference into, this Report.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the quarter ended
December 31, 1997.
20
<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 27, 1998 BY: /s/ STANLEY D. GREEN
----------------------------
Stanley D. Green,
Executive Vice President - Finance
and Corporate Development 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 27, 1998.
/s/ CHARLES E. SCHARLAU Director, Chairman, and
- ---------------------------- Chief Executive Officer
Charles E. Scharlau
/s/ STANLEY D. GREEN Executive Vice President -
- ---------------------------- Finance and Corporate Development
Stanley D. Green and Chief Financial Officer
/s/ GREGORY D. KERLEY Senior Vice President -
- ---------------------------- Treasurer and Secretary and
Gregory D. Kerley Chief Accounting Officer
/s/ JOHN PAUL HAMMERSCHMIDT Director
- ----------------------------
John Paul Hammerschmidt
/s/ ROBERT L. HOWARD Director
- ----------------------------
Robert L. Howard
/s/ KENNETH R. MOURTON Director
- ----------------------------
Kenneth R. Mourton
/s/ CHARLES E. SANDERS Director
- ----------------------------
Charles E. Sanders
Supplemental Information to be Furnished With Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered Securities
Pursuant to Section 12 of the Act.
Not Applicable
21
<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 Shareholder Rights Agreement, dated May 5, 1989 (incorporated by
reference to Exhibit 1 filed with the Company's Form 8-K on May 10,
1989).
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).
Material Contracts:
10.1 Gas Purchase Contract between SEECO, Inc., and Arkansas Western Gas
Company, dated July 24, 1978, as amended May 21, 1979, and Amended and
Restated as of July 1, 1994 (incorporated by reference to Exhibit 10.1
to Annual Report on Form 10-K for the year ended December 31, 1994).
10.2 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
filed herewith).
10.3 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) Summary of Southwestern Energy Company Incentive Compensation
Plan, effective January 1, 1993 (incorporated by reference to
Exhibit 10.4(b) to Annual Report on Form 10-K for the year ended
December 31, 1993).
(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) (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).
22
<PAGE>
Exhibit
No. Description
(d) Southwestern Energy Company 1993 Stock Incentive Plan, dated
April 7, 1993 (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).
(e) Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors, dated April 7, 1993 (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).
10.4 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).
10.5 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).
10.6 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).
10.7 Split-Dollar Life Insurance Agreement for Stanley D. Green, effective
February 1, 1996 (incorporated by reference to Exhibit 10.8 to Annual
Report on Form 10-K for the year ended December 31, 1995).
10.8 Executive Severance Agreement for Charles E. Scharlau, effective August
4, 1989 (incorporated by reference to Exhibit 10 to Annual Report on
Form 10-K for the year ended December 31, 1989).
10.9 Executive Severance Agreement for Stanley D. Green, effective August 4,
1989 (incorporated by reference to Exhibit 10 to Annual Report on Form
10-K for the year ended December 31, 1989).
10.10 Executive Severance Agreement for B. Brick Robinson, effective August 4,
1989 (incorporated by reference to Exhibit 10 to Annual Report on Form
10-K for the year ended December 31, 1989).
10.11 Executive Severance Agreement for Gregory D. Kerley, effective December
14, 1994 (incorporated by reference to Exhibit 10.11 to Annual Report on
Form 10-K for the year ended December 31, 1994).
10.12 Executive Severance Agreement for Debbie J. Branch, effective July 9,
1997 (filed herewith).
10.13 Executive Severance Agreement for Alan H. Stevens, effective January 2,
1998 (filed herewith).
23
<PAGE>
Exhibit
No. Description
10.14 Employment Agreement for Charles E. Scharlau, dated December 18, 1990,
effective January 1, 1991, as amended December 7, 1994 (original
agreement incorporated by reference to Exhibit 10 to Annual Report on
Form 10-K for the year ended December 31, 1990; amended agreement
incorporated by reference to Exhibit 10.12 to Annual Report on Form 10-K
for the year ended December 31, 1994).
10.15 Employment Agreement for Harold M. Korell, effective April 28, 1997
(filed herewith).
10.16 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).
10.17 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 (filed herewith).
10.18 Amended and Restated Limited Partnership Agreement of NOARK Pipeline
System, Limited Partnership dated January 12, 1998 (filed herewith).
13. 1997 Annual Report to Shareholders, except for those portions not
expressly incorporated by reference into this Report. Those portions not
expressly incorporated by reference are not deemed to be filed with the
Securities and Exchange Commission as part of this Report (filed
herewith).
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).
27.1 Financial Data Schedule for 1997(filed herewith).
27.2 Restated Financial Data Schedule for 1996(filed herewith).
27.3 Restated Financial Data Schedule for 1995(filed herewith).
24
AMENDMENT
TO GAS PURCHASE CONTRACT
The undersigned parties, in consideration of the mutual covenants contained
herein, hereby agree to amend, as described below, the gas purchase contract
("Contract") dated October 1, 1990 between Arkansas Western Gas Company
("Buyer") for the account of Associated Natural Gas Company, a division of
Arkansas Western Gas Company, and SEECO, Inc. ("Seller").
1. The phrase "Contract Annual Quantity" shall be changed to "Contract
Annual Volume" wherever it appears throughout the Contract.
2. Section 2(B) shall be deleted in its entirety and replaced with the
following:
(B) It is understood that Seller shall deliver to Buyer on a
daily basis the quantity requested by Buyer up to the Maximum
Daily Quantity. Should Buyer desire a daily quantity in excess
of such quantities, Seller shall advise Buyer of the
availability or nonavailability of such gas and, if available,
when deliveries can commence. However, notwithstanding
anything contained in this contract, Buyer's receipts of gas
hereunder shall fluctuate only to the extent such fluctuations
are required by the demands of Buyer's utility customers in
northeast Arkansas and southeast Missouri. Seller shall have
no obligation to deliver gas to Buyer under this contract to
be used for resale to third parties other than Buyer's
northeast Arkansas and southeast Missouri utility customers.
Buyer shall take gas hereunder at monthly rates which match as
closely as reasonably possible Buyer's historical monthly
takes under this contract.
3. Section 6(A) shall be deleted in its entirety and replaced with the
following:
(A) Subject to the provisions hereinafter set forth, the price
payable hereunder shall be the price contained in the
currently effective contract pricing schedule attached to this
contract. The first such contract pricing schedule shall be
effective October 1, 1997. Each time the price payable under
this contract is redetermined, a new contract pricing schedule
which identifies the redetermined price shall be attached to
this contract, and shall supersede the previous contract
pricing schedule.
4. Section (A) (c) of the General Terms and Conditions shall be deleted
in its entirety and replaced with the following:
(c)The volume of gas shall be measured at each Point of
Delivery by orifice meters installed and operated and
computations made as prescribed in the latest accepted version
of the American Gas Association Gas Measurement Committee
Report No. 3, except as the parties may otherwise agree or may
<PAGE>
otherwise have provided elsewhere herein. The values of the
Reynolds number factor, expansion factor, and manometer
factor, or any of them, may be assumed by Buyer to be one (1).
Dated September 30, 1997.
ARKANSAS WESTERN GAS COMPANY SEECO, INC
By: /s/ CHARLES V. STEVENS By: /s/ DEBBIE J. BRANCH
------------------------- --------------------------
Charles V. Stevens Debbie J. Branch
Vice President and Senior Vice President
Assistant to Chairman Southwestern Energy Services
Company, Agent for SEECO,
Inc.
<PAGE>
CONTRACT PRICING SCHEDULE
TO OCTOBER 1, 1990 GAS PURCHASE CONTRACT
Effective October 1, 1997, the price payable for gas purchased
hereunder shall be as follows:
Monthly Reservation Fee: $91,250
Commodity Cost Per MMBtu: The index as published in Inside
FERC's Gas Market Report (Prices
of Spot Gas Delivered to Pipelines,
per MMBtu dry) for the first day of
the applicable month for deliveries
into NorAm Gas Transmission
Company (East)
Commodity Price Cap: $16,250 per month from October
1997 through September 1998. The
commodity cost per MMBtu dry
(excluding reservation fee and price
cap fee) shall not exceed $3.60
NorAm East for the first 300,000
MMBtu purchased in November
1997, the first 450,000 MMBtu
purchased in December 1997, the
first 450,000 MMBtu purchased in
January 1998, and the first 300,000
MMBtu purchased in February 1998.
Dated September 30, 1997.
ARKANSAS WESTERN GAS COMPANY SEECO, INC
By: /s/ CHARLES V. STEVENS By: /s/ DEBBIE J. BRANCH
-------------------------- --------------------------
Charles V. Stevens Debbie J. Branch
Vice President and Senior Vice President
Assistant to Chairman Southwestern Energy Services
Company, Agent for SEECO,
Inc.
EXECUTIVE SEVERANCE AGREEMENT
This agreement (this "Agreement") is made as of the 9th day of
July, 1997, between Southwestern Energy Company, an Arkansas corporation with
its principal offices at 1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas
72702-1408 (hereinafter called the "Company"), and Debbie J. Branch (hereinafter
called the "Employee"), residing at
WITNESSETH THAT:
WHEREAS, should the Company or shareholders of the Company
receive any proposal from a third person concerning a possible business
combination with the Company or an acquisition of equity securities of the
Company, the Board of Directors of the Company (hereinafter called the "Board")
believes it imperative that the Company and the Board be able to rely upon the
Employee to continue in his position, and that the Company and the Board be able
to receive and rely upon his advice, if they request it, as to the best
interests of the Company and its shareholders, without concern that he might be
distracted or that his advice might be affected by the personal uncertainties
and risks created by such a proposal;
WHEREAS, the Company desires to provide the benefits provided
for herein in order to enable it to attract and retain qualified executives such
as the Employee, without a current expense to the Company;
<PAGE>
NOW, THEREFORE, to assure the Company that it will have the
continued dedication of the Employee and the availability of his advice and
counsel notwithstanding the possibility, threat or occurrence of a bid to take
over control of the Company and to induce the Employee to remain in the employ
of the Company, and for other good and valuable consideration, the Company and
the Employee hereby agree as follows:
1. Definitions.
(i) "Cause," when used in connection with the termination of
the Employee's employment by the Company, shall mean (a) the willful and
continued failure by the Employee substantially to perform his duties and
obligations to the Company (other than any such failure resulting from his
Disability) which failure continues after the Company has given notice thereof
to the Employee or (b) the willful engaging by the Employee in misconduct which
is materially injurious to the Company. For purposes of this definition, no act,
or failure to act, on the Employee's part shall be considered "willful" unless
done, or omitted to be done, by the Employee in bad faith and without reasonable
belief that his action or omission was in the best interests of the Company.
(ii) "Change in Control" shall mean the occurrence of any of
the following:
(a) any "person" (as such term is used in Sections 13(d) and
14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), an
"Acquiring Person") becomes the
2
<PAGE>
"beneficial owner" (as such term is defined in Rule 13d-3 promulgated
under the Exchange Act), directly or indirectly, of securities of the
Company representing 20% or more of the combined voting power of the
Company's then outstanding securities, excluding any employee benefit
plan sponsored or maintained by the Company (or any trustee of such
plan acting as trustee);
(b) the Company's stockholders approve an agreement to merge
or consolidate the Company with another corporation (other than a
corporation 50% or more of which is controlled by, or is under common
control with, the Company);
(c) any individual who is nominated by the Board for election
to the Board on any date fails to be so elected as a direct or indirect
result of any proxy fight or contested election for positions on the
Board;
(d) a "change in control" of the Company of a nature that
would be required to be reported in response to Item 6(e) of Schedule
14A of Regulation 14A promulgated under the Exchange Act occurs; or
(e) a majority of the Board determines in its sole and
absolute discretion that there has been a Change in Control of the
Company or that there will be a Change in Control of the Company upon
the occurrence of certain specified events and such events occur;
Notwithstanding Subparagraphs (a) through (d) of this
Paragraph (ii), a Change in Control shall not occur by reason of
3
<PAGE>
any event which would otherwise constitute a Change in Control if, immediately
after the occurrence of such event, individuals who are Acquiring Persons and
who were employees of the Company immediately prior to the occurrence of such
event own, on a fully diluted basis, securities of the Company representing (A)
5% or more of the combined voting power of the Company's then outstanding
securities or (B) 5% or more of the value of the Company's then outstanding
equity securities.
(iii) "Committee" shall mean the Compensation Committee of the
Board.
(iv) "Compensation" shall mean the "base amount" as such term
is defined in Section 280G of the Internal Revenue Code of 1986, as amended from
time to time (the "Code") and the regulations promulgated thereunder.
(v) "Contract Period" shall mean the period defined in Section
2 hereof.
(vi) "Disability" shall mean a physical or mental incapacity
of the Employee which entitles the Employee to benefits at least equal to
two-thirds of his base salary during the period of such incapacity under any
long term disability plan applicable to him and maintained by the Company as in
effect immediately prior to a Change in Control.
(vii) "Good Reason," when used with reference to a termination
by the Employee of his employment with the Company, shall mean:
4
<PAGE>
(a) the assignment to the Employee of any duties inconsistent
with, or the reduction of powers or functions associated with, his
positions, duties, responsibilities and status with the Company
immediately prior to a Change in Control, or any removal of the
Employee from, or any failure to reelect the Employee to, any positions
or offices the Employee held immediately prior to a Change in Control,
except in connection with the termination of the Employee's employment
by the Company for Cause or on account of Disability pursuant to the
requirements of this Agreement;
(b) a reduction by the Company of the Employee's base salary
as in effect immediately prior to a Change in Control, except in
connection with the termination of the Employee's employment by the
Company for Cause or on account of Disability pursuant to the
requirements of this Agreement;
(c) a change in the Employee's principal work location to a
location more than forty (40) miles from Tulsa, Oklahoma, except for
required travel on the Company's business to an extent substantially
consistent with the Employee's business travel obligations immediately
prior to a Change in Control;
(d) (1) the failure by the Company to continue in effect any
employee benefit plan, program or arrangement (including, without
limitation, "employee benefit plans" within the meaning of Section 3(3)
of the Employee
5
<PAGE>
Retirement Income Security Act of 1974) in which the Employee was
participating immediately prior to a Change in Control (or substitute
plans, programs or arrangements providing the Employee with
substantially similar benefits), (2) the taking of any action, or the
failure to take any action, by the Company which could (A) adversely
affect the Employee's participation in, or materially reduce the
Employee's benefits under, any of such plans, programs or arrangements,
(B) materially adversely affect the basis for computing benefits under
any of such plans, programs or arrangements or (C) deprive the Employee
of any material fringe benefit enjoyed by the Employee immediately
prior to a Change in Control or (3) the failure by the Company to
provide the Employee with the number of paid vacation days to which the
Employee was entitled immediately prior to a Change in Control in
accordance with the Company's vacation policy applicable to the
Employee then in effect, except, in each case, in connection with the
termination of the Employee's employment by the Company for Cause or on
account of Disability pursuant to the requirements of this Agreement;
(e) the failure by the Company to pay the Employee any portion
of the Employee's current compensation, or any portion of the
Employee's compensation deferred under any plan, agreement or
arrangement of or with the Company, within seven (7) days of the date
such compensation is due;
6
<PAGE>
(f) a material increase in the required working hours of the
Employee from that required prior to a Change in Control;
(g) the failure by the Company to obtain an assumption of the
obligations of the Company under this Agreement by any successor to the
Company; or
(h) any termination of the Employee's employment by the
Company during the Contract Period which is not effected pursuant to
the requirements of this Agreement.
(viii) "Termination Date" shall mean the effective date as
provided hereunder of the termination of the Employee's employment.
2. Application of Agreement. This Agreement shall apply only
to a termination of employment of the Employee during a period (the "Contract
Period") commencing on the date immediately preceding the date of a Change in
Control and terminating on the third anniversary of the date of the Change in
Control; provided, however, that such Change in Control occurs during the period
commencing as of the date hereof and terminating on the first anniversary of the
date hereof or as further extended pursuant to the following sentence. On the
first anniversary of the date hereof, and on each anniversary of the date hereof
thereafter, the period during which this Agreement shall automatically apply
shall be extended for one additional year, unless on or before such anniversary
the Company notifies the Employee that it elects not to extend such period.
7
<PAGE>
Any reference herein to the Employee's employment or termination of employment
by or with the Company shall include the Employee's employment or termination of
employment by or with any subsidiary or affiliated company of the Company.
3. Termination of Employment of the Employee By the Company
During the Contract Period.
(i) During the Contract Period, the Company shall have the
right to terminate the Employee's employment hereunder for Cause, for Disability
or without Cause by following the procedures hereinafter specified.
(ii) Termination of the Employee's employment for Disability
shall become effective thirty (30) days after a notice of intent to terminate
the Employee's employment, specifying Disability as the basis for such
termination, is given to the Employee by the Committee.
(iii) The Employee may not be terminated for Cause unless and
until a notice of intent to terminate the Employee's employment for Cause,
specifying the particulars of the conduct of the Employee forming the basis for
such termination, is given to the Employee by the Committee and, subsequently, a
majority of the Board finds, after reasonable notice to the Employee (but in no
event less than fifteen (15) days' prior notice) and an opportunity for the
Employee and his counsel to be heard by the Board, that termination of the
Employee's employment for Cause is justified. Termination of the Employee's
employment for Cause shall become effective after such finding has been made by
the
8
<PAGE>
Board and five (5) business days after the Board gives to the Employee notice
thereof, specifying in detail the particulars of the conduct of the Employee
found by the Board to justify such termination for Cause.
(iv) The Company shall have the absolute right to terminate
the Employee's employment without Cause at any time during the Contract Period
by vote of a majority of the Board. Termination of the Employee's employment
without Cause shall be effective five (5) business days after the Board gives to
the Employee notice thereof, specifying that such termination is without Cause.
(v) Upon a termination of the Employee's employment for Cause
during the Contract Period, the Employee shall have no right to receive any
compensation or benefits hereunder other than those benefits provided in
Paragraph (i)(a) of Section 5 hereof. Upon a termination of the Employee's
employment without Cause during the Contract Period, the Employee shall be
entitled to receive the benefits provided in Section 5 hereof. This Agreement
shall not apply to, and the Employee shall have no right to receive any
compensation or benefits hereunder in connection with any termination of the
Employee's employment by the Company other than during the Contract Period.
4. Termination of Employment By the Employee During the
Contract Period. During the Contract Period, the Employee shall be entitled to
terminate his employment with the Company, and shall be entitled to the benefits
hereunder as follows. If
9
<PAGE>
the Employee terminates his employment with the Company during the twelve-month
period beginning immediately preceding the date of a Change in Control, the
Employee shall not be entitled to receive the benefits provided for in Section 5
hereof (other than those provided for in Paragraph (i)(a) thereof) unless the
termination is for Good Reason. If the Employee shall terminate his employment
with the Company after the expiration of such twelve-month period and during the
Contract Period (or with respect to the benefits provided for in Section 5(i)(a)
hereof, at any time during the contract period), the Employee shall be entitled
to receive the benefits provided in Section 5 hereof if such termination is for
any reason or without reason. The Employee shall give the Company notice of
voluntary termination of employment pursuant to this Section 4, which notice
need specify only the Employee's desire to terminate his employment and, if such
termination is during the twelve-month period beginning immediately following a
Change in Control and is for Good Reason, set-forth in reasonable detail the
facts and circumstances claimed by the Employee to constitute Good Reason.
Termination of the Employee's employment by the Employee pursuant to this
Section 4 shall be effective five (5) business days after the Employee gives
notice thereof to the Company. This Agreement shall not apply to, and the
Employee shall have no right to receive, any compensation or benefits hereunder
in connection with any termination of the Employee's employment by the Employee
other than during the Contract Period. This Agreement shall not
10
<PAGE>
apply to, and the Employee shall have no right to receive, any compensation or
benefits hereunder in connection with a termination of the Employee's employment
on account of the Employee's death, whether or not during the Contract Period.
5. Benefits Upon Termination in Certain Circumstances.
(i) Upon the termination of the employment of the
Employee by the Company pursuant to Section 3(iv) (or with respect to the
benefits in Subparagraph (a) of this Paragraph, Section 3(iv) or 3(v)) hereof
or, by the Employee pursuant to Section 4 hereof, the Employee shall be entitled
to receive the following payments and benefits:
(a) The Company shall pay to the Employee, not later than the
Termination Date, a lump sum cash amount equal to the sum of (I) the
full base salary earned by the Employee through the Termination Date
and unpaid at the Termination Date, calculated at the highest rate of
base salary in effect at any time during the twelve months immediately
preceding the Termination Date, (II) the amount of any base salary
attributable to vacation earned by the Employee but not taken before
the Termination Date, (III) any annualized bonus accrued to the
Employee through the Termination Date and unpaid at the Termination
Date, plus (IV) all other amounts earned by the Employee and unpaid at
the Termination Date.
11
<PAGE>
(b) The Company shall pay to the Employee, not later than the
Termination Date, a lump sum cash amount equal to the product of the
Employee's Compensation times 2.99.
(ii) If the Employee's employment is terminated by the Company
pursuant to Section 3(ii) or 3(iv) hereof, or by the Employee pursuant to
Section 4 hereof, the employee shall be entitled to receive the following
payments and benefits:
(a) The Company shall maintain in full force and effect for
the Employee's continued benefit all life, medical, dental,
prescription drug and long- and short-term disability plans, programs
or arrangements, whether group or individual, in which the Employee was
entitled to participate at any time during the twelve month-period
prior to the Termination Date, until the earliest to occur of (I) three
years after the Termination Date; (II) the Employee's death (provided
that benefits payable to his beneficiaries shall not terminate upon his
death); or (III) with respect to any particular plan, program or
arrangement, the date he is afforded a comparable benefit at a
comparable cost to the Employee by a subsequent employer. In the event
that the Employee's participation in any such plan, program or
arrangement of the Company is prohibited, the Company shall arrange to
provide the Employee with benefits substantially similar to those which
the Employee is entitled to receive under such plan, program or
arrangement for such period.
12
<PAGE>
(b) The Company shall pay to the Employee all legal fees and
expenses (including legal fees and expenses incurred in connection with
an arbitration proceeding engaged in pursuant to Section 10 hereof)
incurred by the Employee as a result of such termination of employment
(including all such fees and expenses, if any, incurred in contesting
or disputing any such termination or in seeking to obtain or enforce
any right or benefit provided to the Employee by this Agreement or
under any other plan, program or arrangement of the Company or
agreement with the Company), as and when such fees and expenses become
due.
(iii) The Employee shall not be required to mitigate the
amount of any payment or benefit provided for in this Section 5 by seeking other
employment or otherwise.
(iv) The amount of any payment or benefit provided for in this
Section 5 shall not be reduced by any compensation, benefits or other amounts
paid to or earned by the Employee as the result of employment with another
employer after the Termination Date or otherwise.
(v) In the event that any payment hereunder, together with any
other payment or the value of any benefit received in connection with a Change
in Control or the termination or the Employee's employment pursuant to this
Agreement or any plan, agreement or other arrangement between the Company and
the Employee (or any member of Company's affiliated group as such term is
defined in Section 1504 of the Code, without regard to
13
<PAGE>
Section 1504(b) thereof) would result in the imposition of an excise tax under
Section 4999 of the Code, the payment hereunder may, at the election of the
Employee, be reduced by the amount necessary to prevent the imposition of such
excise tax. The Company shall engage tax counsel selected by the Employee and
reasonably acceptable to the Company to advise the Employee regarding any
potential excise tax liability under Section 4999 of the Code and as to any
benefit or detriment to the Employee of making the reduction election provided
for hereunder. In making the determinations required in order to give the advice
contemplated by this Paragraph (v), tax counsel may rely on benefit consultants,
accountants and other experts. The Company agrees to pay all fees and expenses
of such tax counsel and other experts.
6. Payment Obligations Absolute. The Company's obligation to
pay the Employee the amounts provided for hereunder shall be absolute and
unconditional and shall not be affected by any circumstances, including, without
limitation, any set-off, counterclaim, recoupment, defense or other right which
the Company may have against him or anyone else and, including without
limitation, any defense or claim based on a breach by the Employee of the
covenants contained herein. All amounts payable by the Company hereunder shall
be paid without notice or demand. Except as expressly provided herein, the
Company waives all rights which it may now have or may hereafter have conferred
upon it, by statute or otherwise, to amend, terminate, cancel or
14
<PAGE>
rescind this Agreement in whole or in part. Subject to the right of the Company
to seek arbitration under Section 10 hereof and recover any payment made
hereunder, each and every payment made hereunder by the Company shall be final,
and the Company shall not seek to recover all or any part of such payment from
the Employee or from whomsoever may be entitled thereto, for any reason
whatsoever.
7. Covenant Not to Solicit.
(i) In the event the Employee's employment is
terminated by the Company pursuant to Section 3(iv) hereof or by the Employee
pursuant to Section 4 hereof, the Employee agrees during the three-year period
following the Termination Date not to:
(a) offer employment to any officer or employee of the Company
or any subsidiary or affiliated company of the Company or attempt to
induce any such officer or employee to leave the employ of the Company
or any subsidiary or affiliated company of the Company; or
(b) attempt to persuade or induce, or persuade or induce, any
officer, director, agent, customer, client or supplier of the Company
or any subsidiary or affiliated company of the Company to discontinue
his or her relationship with the Company or any subsidiary or
affiliated company of the Company.
(ii) In the event of any breach of the foregoing covenant, the
Employee acknowledges that the Company's remedy at
15
<PAGE>
law is inadequate and that the Company shall be entitled to seek
injunctive relief.
8. Successors; Binding Agreement.
(i) This Agreement shall be binding upon any successor
(whether direct or indirect, by purchase, merger, consolidation, liquidation or
otherwise) to all or substantially all of the business and/or assets of the
Company. Additionally, the Company shall require any such successor expressly to
agree to assume and to assume all of the obligations of the Company under this
Agreement upon or prior to such succession taking place. A copy of such
assumption and agreement shall be delivered to the Employee promptly after its
execution by the successor. Failure of the Company to obtain such agreement
prior to the effectiveness of any such succession shall be a breach of this
Agreement and, as a result of such breach, the Company shall pay to the Employee
the benefits as provided in Section 5 hereof as if the Company had terminated
the Employee's employment on the date on which such succession becomes
effective, without Cause, upon a Change in Control. As used in this Agreement,
"Company" shall mean the Company as hereinbefore defined and any successor to
its business and or assets as aforesaid, whether or not such successor executes
and delivers the agreement provided for in this Section 8(i).
(ii) This Agreement is personal to the Employee and the
Employee may not assign or transfer any part of his rights or duties hereunder,
or any compensation due to him hereunder, to
16
<PAGE>
any other person, except that this Agreement shall inure to the benefit of and
be enforceable by the Employee's personal or legal representatives, executors,
administrators, heirs, distributees, devises, legatees or beneficiaries. No
payment pursuant to any will or the laws of descent and distribution shall be
made hereunder unless the Company shall have been furnished with a copy of such
will and/or such other evidence as the Board may deem necessary to establish the
validity of the payment.
9. Modification; Waiver. No provisions of this Agreement may
be modified, waived or discharged unless such waiver, modification or discharge
is agreed to in a writing signed by the Employee and such director or officer as
may be specifically designated by the Board. Waiver by any party of any breach
of or failure to comply with any provision of this Agreement by the other party
shall not be construed as, or constitute, a continuing waiver of such provision,
or a waiver of any other breach of, or failure to comply with, any other
provision of this Agreement.
10. Arbitration of Disputes.
(i) Any disagreement, dispute, controversy or claim arising
out of or relating to this Agreement or the interpretation or validity hereof
shall be settled exclusively and finally by arbitration except that in the event
of the Employee's breach of the covenant contained in Section 7 hereof, the
Company shall be entitled to seek injunctive relief pursuant to Section 7(ii)
hereof. It is specifically understood and agreed that any
17
<PAGE>
disagreement, dispute or controversy which cannot be resolved between the
parties, including without limitation any matter relating to the interpretation
of this Agreement, may be submitted to arbitration irrespective of the magnitude
thereof, the amount in controversy or whether such disagreement, dispute or
controversy otherwise would be considered justiciable or ripe for resolution by
a court or arbitral tribunal.
(ii) The arbitration shall be conducted in accordance with the
Commercial Arbitration Rules (the "Arbitration Rules") of the American
Arbitration Association (the "AAA").
(iii) The arbitral tribunal shall consist of one arbitrator.
The parties to the arbitration jointly shall directly appoint such arbitrator
within 30 days of initiation of the arbitration. If the parties shall fail to
appoint such arbitrator as provided above, such arbitrator shall be appointed by
the AAA as provided in the Arbitration Rules and shall be a person who (a)
maintains his principal place of business within 30 miles of the City of
Fayetteville, Arkansas, and (b) has had substantial experience (whether
practical or academic) in mergers and acquisitions or, if no such person is
available, in employee benefits. The Company shall pay all of the fees, if any,
and expenses of such arbitrator.
(iv) The arbitration shall be conducted within 30 miles of the
City of Fayetteville, Arkansas or in such other city in the United States of
America as the parties to the dispute may designate by mutual written consent.
18
<PAGE>
(v) At any oral hearing of evidence in connection with the
arbitration, each party thereto or its legal counsel shall have the right to
examine its witnesses and to cross-examine the witnesses of any opposing party.
No evidence of any witness shall be presented unless the opposing party or
parties shall have the opportunity to cross-examine such witness, except as the
parties to the dispute otherwise agree in writing or except under extraordinary
circumstances where the interests of justice require a different procedure.
(vi) Any decision or award of the arbitral tribunal shall be
final and binding upon the parties to the arbitration proceeding. The parties
hereto hereby waive, to the extent permitted by law, any rights to appeal or to
seek review of such award by any court or tribunal. The parties hereto agree
that the arbitral award may be enforced against the parties to the arbitration
proceeding or their assets wherever they may be found and that a judgment upon
the arbitral award may be entered in any court having jurisdiction.
(vii) Nothing herein contained shall be deemed to give the
arbitral tribunal any authority, power, or right to alter, change, amend,
modify, add to, or subtract from any of the provisions of this Agreement.
11. Notice. All notices, requests, demands and other
communications required or permitted to be given by either party to the other
party by this Agreement (including, without limitation, any notice of
termination of employment and any
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notice under the Arbitration Rules of an intention to arbitrate) shall be in
writing and shall be deemed to have been duly given when delivered personally or
received by certified or registered mail, return receipt requested, postage
prepaid, at the address of the other party, as follows:
If to the Company, to:
Southwestern Energy Company
1083 Sain Street
P.O. Box 1408
Fayetteville, Arkansas 72702-1408
Attention: Board of Directors and Secretary
If to the Employee, to:
Either party hereto may change its address for purposes of this Section 11 by
giving fifteen (15) days' prior notice to the other party hereto.
12. Severability. If any term or provision of this Agreement
or the application thereof to any person or circumstance shall to any extent be
invalid or unenforceable, the remainder of this Agreement or the application of
such term or provision to persons or circumstances other than those as to which
it is held invalid or unenforceable shall not be affected thereby, and each term
and provision of this Agreement shall be valid and enforceable to the fullest
extent permitted by law.
13. Headings. The headings in this Agreement are inserted for
convenience of reference only and shall not be a part of or control or affect
the meaning of this Agreement.
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14. Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed an original.
15. Governing Law. This Agreement has been executed and
delivered in the State of Arkansas and shall in all respects be governed by, and
construed and enforced in accordance with, the laws of the State of Arkansas.
16. Payroll and Withholding Taxes. The Company may withhold
from any amounts payable to the Employee hereunder all federal, state, city or
other taxes that the Company may reasonably determine are required to be
withheld pursuant to any applicable law or regulation.
17. Entire Agreement. Except as explicitly provided for
herein, this Agreement supersedes any and all other oral or written agreements
heretofore made relating to the subject matter hereof and constitutes the entire
agreement of the parties relating to the subject matter hereof; provided, that,
this Agreement shall not supersede or limit or in any way affect the amount of
compensation or benefits to which the Employee would be entitled under any other
agreement, plan, program or arrangement with the Company including any such
agreement, plan, program or arrangement providing for benefits in the nature of
severance pay.
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<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement as of the
date first written above.
Southwestern Energy Company
By: /s/ CHARLES E. SCHARLAU
---------------------------
Chairman of the Board of
Southwestern Energy Company
By: /s/ DEBBIE J. BRANCH
---------------------------
22
EXECUTIVE SEVERANCE AGREEMENT
This agreement (this "Agreement") is made as of the 2nd day of
January, 1998, between Southwestern Energy Company, an Arkansas corporation with
its principal offices at 1083 Sain Street, P.O. Box 1408, Fayetteville, Arkansas
72702-1408 (hereinafter called the "Company"), and Alan H. Stevens (hereinafter
called the "Employee"), residing at
WITNESSETH THAT:
WHEREAS, should the Company or shareholders of the Company
receive any proposal from a third person concerning a possible business
combination with the Company or an acquisition of equity securities of the
Company, the Board of Directors of the Company (hereinafter called the "Board")
believes it imperative that the Company and the Board be able to rely upon the
Employee to continue in his position, and that the Company and the Board be able
to receive and rely upon his advice, if they request it, as to the best
interests of the Company and its shareholders, without concern that he might be
distracted or that his advice might be affected by the personal uncertainties
and risks created by such a proposal;
<PAGE>
WHEREAS, the Company desires to provide the benefits provided
for herein in order to enable it to attract and retain qualified executives such
as the Employee, without a current expense to the Company;
NOW, THEREFORE, to assure the Company that it will have the
continued dedication of the Employee and the availability of his advice and
counsel notwithstanding the possibility, threat or occurrence of a bid to take
over control of the Company and to induce the Employee to remain in the employ
of the Company, and for other good and valuable consideration, the Company and
the Employee hereby agree as follows:
1. Definitions.
(i) "Cause," when used in connection with the termination of
the Employee's employment by the Company, shall mean (a) the willful and
continued failure by the Employee substantially to perform his duties and
obligations to the Company (other than any such failure resulting from his
Disability) which failure continues after the Company has given notice thereof
to the Employee or (b) the willful engaging by the Employee in misconduct which
is materially injurious to the Company. For purposes of this definition, no act,
or failure to act, on the Employee's part shall be considered "willful" unless
2
<PAGE>
done, or omitted to be done, by the Employee in bad faith and without reasonable
belief that his action or omission was in the best interests of the Company.
(ii) "Change in Control" shall mean the occurrence of any of
the following:
(a) any "person" (as such term is used in Sections 13(d) and
14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), an
"Acquiring Person") becomes the
"beneficial owner" (as such term is defined in Rule 13d-3 promulgated
under the Exchange Act), directly or indirectly, of securities of the
Company representing 20% or more of the combined voting power of the
Company's then outstanding securities, excluding any employee benefit
plan sponsored or maintained by the Company (or any trustee of such
plan acting as trustee);
(b) the Company's stockholders approve an agreement to merge
or consolidate the Company with another corporation (other than a
corporation 50% or more of which is controlled by, or is under common
control with, the Company);
(c) any individual who is nominated by the Board for election
to the Board on any date fails to be so elected as
3
<PAGE>
a direct or indirect result of any proxy fight or contested election
for positions on the Board;
(d) a "change in control" of the Company of a nature that
would be required to be reported in response to Item 6(e) of Schedule
14A of Regulation 14A promulgated under the Exchange Act occurs; or
(e) a majority of the Board determines in its sole and
absolute discretion that there has been a Change in Control of the
Company or that there will be a Change in Control of the Company upon
the occurrence of certain specified events and such events occur;
Notwithstanding Subparagraphs (a) through (d) of this
Paragraph (ii), a Change in Control shall not occur by reason of
any event which would otherwise constitute a Change in Control if, immediately
after the occurrence of such event, individuals who are Acquiring Persons and
who were employees of the Company immediately prior to the occurrence of such
event own, on a fully diluted basis, securities of the Company representing (A)
5% or more of the combined voting power of the Company's then outstanding
securities or (B) 5% or more of the value of the Company's then outstanding
equity securities.
4
<PAGE>
(iii) "Committee" shall mean the Compensation Committee of the
Board.
(iv) "Compensation" shall mean the "base amount" as such term
is defined in Section 280G of the Internal Revenue Code of 1986, as amended from
time to time (the "Code") and the regulations promulgated thereunder.
(v) "Contract Period" shall mean the period defined in Section
2 hereof.
(vi) "Disability" shall mean a physical or mental incapacity
of the Employee which entitles the Employee to benefits at least equal to
two-thirds of his base salary during the period of such incapacity under any
long term disability plan applicable to him and maintained by the Company as in
effect immediately prior to a Change in Control.
(vii) "Good Reason," when used with reference to a termination
by the Employee of his employment with the Company, shall mean:
(a) the assignment to the Employee of any duties inconsistent
with, or the reduction of powers or functions associated with, his
positions, duties, responsibilities and status with the Company
immediately prior to a Change in Control, or any removal of the
Employee from, or any failure
5
<PAGE>
to reelect the Employee to, any positions or offices the Employee held
immediately prior to a Change in Control, except in connection with the
termination of the Employee's employment by the Company for Cause or on
account of Disability pursuant to the requirements of this Agreement;
(b) a reduction by the Company of the Employee's base salary
as in effect immediately prior to a Change in Control, except in
connection with the termination of the Employee's employment by the
Company for Cause or on account of Disability pursuant to the
requirements of this Agreement;
(c) a change in the Employee's principal work location to a
location more than forty (40) miles from Houston, Texas, except for
required travel on the Company's business to an extent substantially
consistent with the Employee's business travel obligations immediately
prior to a Change in Control;
(d) (1) the failure by the Company to continue in effect any
employee benefit plan, program or arrangement (including, without
limitation, "employee benefit plans" within the meaning of Section 3(3)
of the Employee Retirement Income Security Act of 1974) in which the
6
<PAGE>
Employee was participating immediately prior to a Change in Control (or
substitute plans, programs or arrangements providing the Employee with
substantially similar benefits), (2) the taking of any action, or the
failure to take any action, by the Company which could (A) adversely
affect the Employee's participation in, or materially reduce the
Employee's benefits under, any of such plans, programs or arrangements,
(B) materially adversely affect the basis for computing benefits under
any of such plans, programs or arrangements or (C) deprive the Employee
of any material fringe benefit enjoyed by the Employee immediately
prior to a Change in Control or (3) the failure by the Company to
provide the Employee with the number of paid vacation days to which the
Employee was entitled immediately prior to a Change in Control in
accordance with the Company's vacation policy applicable to the
Employee then in effect, except, in each case, in connection with the
termination of the Employee's employment by the Company for Cause or on
account of Disability pursuant to the requirements of this Agreement;
(e) the failure by the Company to pay the Employee any portion
of the Employee's current compensation, or any
7
<PAGE>
portion of the Employee's compensation deferred under any
plan, agreement or arrangement of or with the Company, within seven
(7) days of the date such compensation is due;
(f) a material increase in the required working hours of the
Employee from that required prior to a Change in Control;
(g) the failure by the Company to obtain an assumption of the
obligations of the Company under this Agreement by any successor to the
Company; or
(h) any termination of the Employee's employment by the
Company during the Contract Period which is not effected pursuant to
the requirements of this Agreement.
(viii) "Termination Date" shall mean the effective date as
provided hereunder of the termination of the Employee's employment.
2. Application of Agreement. This Agreement shall apply only
to a termination of employment of the Employee during a period (the "Contract
Period") commencing on the date immediately preceding the date of a Change in
Control and terminating on the third anniversary of the date of the Change in
Control; provided, however, that such Change in Control occurs during the period
commencing as of the date hereof and
8
<PAGE>
terminating on the first anniversary of the date hereof or as further extended
pursuant to the following sentence. On the first anniversary of the date hereof,
and on each anniversary of the date hereof thereafter, the period during which
this Agreement shall automatically apply shall be extended for one additional
year, unless on or before such anniversary the Company notifies the Employee
that it elects not to extend such period. Any reference herein to the Employee's
employment or termination of employment by or with the Company shall include the
Employee's employment or termination of employment by or with any subsidiary or
affiliated company of the Company.
3. Termination of Employment of the Employee By the Company
During the Contract Period.
(i) During the Contract Period, the Company shall have the
right to terminate the Employee's employment hereunder for Cause, for Disability
or without Cause by following the procedures hereinafter specified.
(ii) Termination of the Employee's employment for Disability
shall become effective thirty (30) days after a notice of intent to terminate
the Employee's employment, specifying Disability as the basis for such
termination, is given to the Employee by the Committee.
9
<PAGE>
(iii) The Employee may not be terminated for Cause unless and
until a notice of intent to terminate the Employee's employment for Cause,
specifying the particulars of the conduct of the Employee forming the basis for
such termination, is given to the Employee by the Committee and, subsequently, a
majority of the Board finds, after reasonable notice to the Employee (but in no
event less than fifteen (15) days' prior notice) and an opportunity for the
Employee and his counsel to be heard by the Board, that termination of the
Employee's employment for Cause is justified. Termination of the Employee's
employment for Cause shall become effective after such finding has been made by
the Board and five (5) business days after the Board gives to the Employee
notice thereof, specifying in detail the particulars of the conduct of the
Employee found by the Board to justify such termination for Cause.
(iv) The Company shall have the absolute right to terminate
the Employee's employment without Cause at any time during the Contract Period
by vote of a majority of the Board. Termination of the Employee's employment
without Cause shall be effective five (5) business days after the Board gives to
the Employee notice thereof, specifying that such termination is without Cause.
10
<PAGE>
(v) Upon a termination of the Employee's employment for Cause
during the Contract Period, the Employee shall have no right to receive any
compensation or benefits hereunder other than those benefits provided in
Paragraph (i)(a) of Section 5 hereof. Upon a termination of the Employee's
employment without Cause during the Contract Period, the Employee shall be
entitled to receive the benefits provided in Section 5 hereof. This Agreement
shall not apply to, and the Employee shall have no right to receive any
compensation or benefits hereunder in connection with any termination of the
Employee's employment by the Company other than during the Contract Period.
4. Termination of Employment By the Employee During
the Contract Period. During the Contract Period, the Employee shall be entitled
to terminate his employment with the Company, and shall be entitled to the
benefits hereunder as follows. If the Employee terminates his employment with
the Company during the twelve-month period beginning immediately preceding the
date of a Change in Control, the Employee shall not be entitled to receive the
benefits provided for in Section 5 hereof (other than those provided for in
Paragraph (i)(a) thereof) unless the termination is for Good Reason. If the
Employee shall terminate his employment with the Company after the expiration of
such
11
<PAGE>
twelve-month period and during the Contract Period (or with respect to the
benefits provided for in Section 5(i)(a) hereof, at any time during the contract
period), the Employee shall be entitled to receive the benefits provided in
Section 5 hereof if such termination is for any reason or without reason. The
Employee shall give the Company notice of voluntary termination of employment
pursuant to this Section 4, which notice need specify only the Employee's desire
to terminate his employment and, if such termination is during the twelve-month
period beginning immediately following a Change in Control and is for Good
Reason, set-forth in reasonable detail the facts and circumstances claimed by
the Employee to constitute Good Reason. Termination of the Employee's employment
by the Employee pursuant to this Section 4 shall be effective five (5) business
days after the Employee gives notice thereof to the Company. This Agreement
shall not apply to, and the Employee shall have no right to receive, any
compensation or benefits hereunder in connection with any termination of the
Employee's employment by the Employee other than during the Contract Period.
This Agreement shall not apply to, and the Employee shall have no right to
receive, any compensation or benefits hereunder in connection with a termination
of the Employee's employment on account of the
12
<PAGE>
Employee's death, whether or not during the Contract Period.
5. Benefits Upon Termination in Certain Circumstances.
(i) Upon the termination of the employment of the
Employee by the Company pursuant to Section 3(iv) (or with respect to the
benefits in Subparagraph (a) of this Paragraph, Section 3(iv) or 3(v)) hereof
or, by the Employee pursuant to Section 4 hereof, the Employee shall be entitled
to receive the following payments and benefits:
(a) The Company shall pay to the Employee, not later than the
Termination Date, a lump sum cash amount equal to the sum of (I) the
full base salary earned by the Employee through the Termination Date
and unpaid at the Termination Date, calculated at the highest rate of
base salary in effect at any time during the twelve months immediately
preceding the Termination Date, (II) the amount of any base salary
attributable to vacation earned by the Employee but not taken before
the Termination Date, (III) any annualized bonus accrued to the
Employee through the Termination Date and unpaid at the Termination
Date, plus (IV) all other amounts earned by the Employee and unpaid at
the Termination Date.
13
<PAGE>
(b) The Company shall pay to the Employee, not later than the
Termination Date, a lump sum cash amount equal to the product of the
Employee's Compensation times 2.99.
(ii) If the Employee's employment is terminated by the Company
pursuant to Section 3(ii) or 3(iv) hereof, or by the Employee pursuant to
Section 4 hereof, the employee shall be entitled to receive the following
payments and benefits:
(a) The Company shall maintain in full force and effect for
the Employee's continued benefit all life, medical, dental,
prescription drug and long- and short-term disability plans, programs
or arrangements, whether group or individual, in which the Employee was
entitled to participate at any time during the twelve month-period
prior to the Termination Date, until the earliest to occur of (I) three
years after the Termination Date; (II) the Employee's death (provided
that benefits payable to his beneficiaries shall not terminate upon his
death); or (III) with respect to any particular plan, program or
arrangement, the date he is afforded a comparable benefit at a
comparable cost to the Employee by a subsequent employer. In the event
that the Employee's participation in any such plan, program or
arrangement of the Company is prohibited, the Company shall
14
<PAGE>
arrange to provide the Employee with benefits substantially similar to
those which the Employee is entitled to receive under such plan,
program or arrangement for such period.
(b) The Company shall pay to the Employee all legal fees and
expenses (including legal fees and expenses incurred in connection with
an arbitration proceeding engaged in pursuant to Section 10 hereof)
incurred by the Employee as a result of such termination of employment
(including all such fees and expenses, if any, incurred in contesting
or disputing any such termination or in seeking to obtain or enforce
any right or benefit provided to the Employee by this Agreement or
under any other plan, program or arrangement of the Company or
agreement with the Company), as and when such fees and expenses become
due.
(iii) The Employee shall not be required to mitigate the
amount of any payment or benefit provided for in this Section 5 by seeking other
employment or otherwise.
(iv) The amount of any payment or benefit provided for in this
Section 5 shall not be reduced by any compensation, benefits or other amounts
paid to or earned by the Employee as the result of employment with another
employer after the Termination Date or otherwise.
15
<PAGE>
(v) In the event that any payment hereunder, together with any
other payment or the value of any benefit received in connection with a Change
in Control or the termination or the Employee's employment pursuant to this
Agreement or any plan, agreement or other arrangement between the Company and
the Employee (or any member of Company's affiliated group as such term is
defined in Section 1504 of the Code, without regard to Section 1504(b) thereof)
would result in the imposition of an excise tax under Section 4999 of the Code,
the payment hereunder may, at the election of the Employee, be reduced by the
amount necessary to prevent the imposition of such excise tax. The Company shall
engage tax counsel selected by the Employee and reasonably acceptable to the
Company to advise the Employee regarding any potential excise tax liability
under Section 4999 of the Code and as to any benefit or detriment to the
Employee of making the reduction election provided for hereunder. In making the
determinations required in order to give the advice contemplated by this
Paragraph (v), tax counsel may rely on benefit consultants, accountants and
other experts. The Company agrees to pay all fees and expenses of such tax
counsel and other experts.
16
<PAGE>
6. Payment Obligations Absolute. The Company's obligation to
pay the Employee the amounts provided for hereunder shall be absolute and
unconditional and shall not be affected by any circumstances, including, without
limitation, any set-off, counterclaim, recoupment, defense or other right which
the Company may have against him or anyone else and, including without
limitation, any defense or claim based on a breach by the Employee of the
covenants contained herein. All amounts payable by the Company hereunder shall
be paid without notice or demand. Except as expressly provided herein, the
Company waives all rights which it may now have or may hereafter have conferred
upon it, by statute or otherwise, to amend, terminate, cancel or rescind this
Agreement in whole or in part. Subject to the right of the Company to seek
arbitration under Section 10 hereof and recover any payment made hereunder, each
and every payment made hereunder by the Company shall be final, and the Company
shall not seek to recover all or any part of such payment from the Employee or
from whomsoever may be entitled thereto, for any reason whatsoever.
7. Covenant Not to Solicit.
(i) In the event the Employee's employment is terminated by
the Company pursuant to Section 3(iv) hereof or by
17
<PAGE>
the Employee pursuant to Section 4 hereof, the Employee agrees during the
three-year period following the Termination Date not to:
(a) offer employment to any officer or employee of the Company
or any subsidiary or affiliated company of the Company or attempt to
induce any such officer or employee to leave the employ of the Company
or any subsidiary or affiliated company of the Company; or
(b) attempt to persuade or induce, or persuade or induce, any
officer, director, agent, customer, client or supplier of the Company
or any subsidiary or affiliated company of the Company to discontinue
his or her relationship with the Company or any subsidiary or
affiliated company of the Company.
(ii) In the event of any breach of the foregoing covenant, the
Employee acknowledges that the Company's remedy at law is inadequate and that
the Company shall be entitled to seek injunctive relief.
8. Successors; Binding Agreement.
(i) This Agreement shall be binding upon any successor
(whether direct or indirect, by purchase, merger, consolidation, liquidation or
otherwise) to all or substantially all of the
18
<PAGE>
business and/or assets of the Company. Additionally, the Company shall require
any such successor expressly to agree to assume and to assume all of the
obligations of the Company under this Agreement upon or prior to such succession
taking place. A copy of such assumption and agreement shall be delivered to the
Employee promptly after its execution by the successor. Failure of the Company
to obtain such agreement prior to the effectiveness of any such succession shall
be a breach of this Agreement and, as a result of such breach, the Company shall
pay to the Employee the benefits as provided in Section 5 hereof as if the
Company had terminated the Employee's employment on the date on which such
succession becomes effective, without Cause, upon a Change in Control. As used
in this Agreement, "Company" shall mean the Company as hereinbefore defined and
any successor to its business and or assets as aforesaid, whether or not such
successor executes and delivers the agreement provided for in this Section 8(i).
(ii) This Agreement is personal to the Employee and the
Employee may not assign or transfer any part of his rights or duties hereunder,
or any compensation due to him hereunder, to any other person, except that this
Agreement shall inure to the benefit of and be enforceable by the Employee's
personal or legal
19
<PAGE>
representatives, executors, administrators, heirs, distributees, devises,
legatees or beneficiaries. No payment pursuant to any will or the laws of
descent and distribution shall be made hereunder unless the Company shall have
been furnished with a copy of such will and/or such other evidence as the Board
may deem necessary to establish the validity of the payment.
9. Modification; Waiver. No provisions of this Agreement may
be modified, waived or discharged unless such waiver, modification or discharge
is agreed to in a writing signed by the Employee and such director or officer as
may be specifically designated by the Board. Waiver by any party of any breach
of or failure to comply with any provision of this Agreement by the other party
shall not be construed as, or constitute, a continuing waiver of such provision,
or a waiver of any other breach of, or failure to comply with, any other
provision of this Agreement.
10. Arbitration of Disputes.
(i) Any disagreement, dispute, controversy or claim arising
out of or relating to this Agreement or the interpretation or validity hereof
shall be settled exclusively and finally by arbitration except that in the event
of the Employee's breach of the covenant contained in Section 7 hereof, the
Company
20
<PAGE>
shall be entitled to seek injunctive relief pursuant to Section 7(ii) hereof. It
is specifically understood and agreed that any disagreement, dispute or
controversy which cannot be resolved between the parties, including without
limitation any matter relating to the interpretation of this Agreement, may be
submitted to arbitration irrespective of the magnitude thereof, the amount in
controversy or whether such disagreement, dispute or controversy otherwise would
be considered justiciable or ripe for resolution by a court or arbitral
tribunal.
(ii) The arbitration shall be conducted in accordance with the
Commercial Arbitration Rules (the "Arbitration Rules") of the American
Arbitration Association (the "AAA").
(iii) The arbitral tribunal shall consist of one arbitrator.
The parties to the arbitration jointly shall directly appoint such arbitrator
within 30 days of initiation of the arbitration. If the parties shall fail to
appoint such arbitrator as provided above, such arbitrator shall be appointed by
the AAA as provided in the Arbitration Rules and shall be a person who (a)
maintains his principal place of business within 30 miles of the City of
Fayetteville, Arkansas, and (b) has had substantial experience (whether
practical or academic) in mergers and acquisitions or, if no such person is
available, in employee
21
<PAGE>
benefits. The Company shall pay all of the fees, if any, and expenses of such
arbitrator.
(iv) The arbitration shall be conducted within 30 miles of the
City of Fayetteville, Arkansas or in such other city in the United States of
America as the parties to the dispute may designate by mutual written consent.
(v) At any oral hearing of evidence in connection with the
arbitration, each party thereto or its legal counsel shall have the right to
examine its witnesses and to cross-examine the witnesses of any opposing party.
No evidence of any witness shall be presented unless the opposing party or
parties shall have the opportunity to cross-examine such witness, except as the
parties to the dispute otherwise agree in writing or except under extraordinary
circumstances where the interests of justice require a different procedure.
(vi) Any decision or award of the arbitral tribunal shall be
final and binding upon the parties to the arbitration proceeding. The parties
hereto hereby waive, to the extent permitted by law, any rights to appeal or to
seek review of such award by any court or tribunal. The parties hereto agree
that the arbitral award may be enforced against the parties to the arbitration
proceeding or their assets wherever they may be found
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<PAGE>
and that a judgment upon the arbitral award may be entered in any court having
jurisdiction.
(vii) Nothing herein contained shall be deemed to give the
arbitral tribunal any authority, power, or right to alter, change, amend,
modify, add to, or subtract from any of the provisions of this Agreement.
11. Notice. All notices, requests, demands and other
communications required or permitted to be given by either party to the other
party by this Agreement (including, without limitation, any notice of
termination of employment and any notice under the Arbitration Rules of an
intention to arbitrate) shall be in writing and shall be deemed to have been
duly given when delivered personally or received by certified or registered
mail, return receipt requested, postage prepaid, at the address of the other
party, as follows:
If to the Company, to:
Southwestern Energy Company
1083 Sain Street
P.O. Box 1408
Fayetteville, Arkansas 72702-1408
Attention: Board of Directors and Secretary
If to the Employee, to:
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<PAGE>
Either party hereto may change its address for purposes of this Section 11 by
giving fifteen (15) days' prior notice to the other party hereto.
12. Severability. If any term or provision of this Agreement
or the application thereof to any person or circumstance shall to any extent be
invalid or unenforceable, the remainder of this Agreement or the application of
such term or provision to persons or circumstances other than those as to which
it is held invalid or unenforceable shall not be affected thereby, and each term
and provision of this Agreement shall be valid and enforceable to the fullest
extent permitted by law.
13. Headings. The headings in this Agreement are inserted for
convenience of reference only and shall not be a part of or control or affect
the meaning of this Agreement.
14. Counterparts. This Agreement may be executed in several
counterparts, each of which shall be deemed an original.
15. Governing Law. This Agreement has been executed and
delivered in the State of Arkansas and shall in all respects be governed by, and
construed and enforced in accordance with, the laws of the State of Arkansas.
16. Payroll and Withholding Taxes. The Company may withhold
from any amounts payable to the Employee hereunder all
24
<PAGE>
federal, state, city or other taxes that the Company may reasonably determine
are required to be withheld pursuant to any applicable law or regulation.
17. Entire Agreement. Except as explicitly provided for
herein, this Agreement supersedes any and all other oral or written agreements
heretofore made relating to the subject matter hereof and constitutes the entire
agreement of the parties relating to the subject matter hereof; provided, that,
this Agreement shall not supersede or limit or in any way affect the amount of
compensation or benefits to which the Employee would be entitled under any other
agreement, plan, program or arrangement with the Company including any such
agreement, plan, program or arrangement providing for benefits in the nature of
severance pay.
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<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement as of the
date first written above.
Southwestern Energy Company
By: /s/ CHARLES E. SCHARLAU
---------------------------
Chairman of the Board of
Southwestern Energy Company
By: /s/ ALAN H. STEVENS
---------------------------
26
EMPLOYMENT AGREEMENT
THIS EMPLOYMENT AGREEMENT ("Agreement") is made and entered into on
this March 29, 1997, and effective as of April 28, 1997, by and between
SOUTHWESTERN ENERGY COMPANY, an Arkansas business corporation, designated herein
as SWEN, and HAROLD M. KORELL, designated herein as EMPLOYEE.
WITNESSETH:
A. PARTIES
1. SOUTHWESTERN ENERGY COMPANY ("SWEN") is an Arkansas business
corporation with its principal office being situated in Fayetteville, Washington
County, Arkansas, and it is the parent company of the following wholly-owned
subsidiary corporations ("Subsidiaries"):
(a) Arkansas Western Gas Company: Arkansas Western Gas Company
("AWG") is an Arkansas business corporation with its home office being
situated in Fayetteville, Washington County, Arkansas, and it is a
natural gas distribution public utility in the States of Arkansas and
Missouri;
(b) SEECO, Inc.: SEECO, Inc. ("SEECO") is an Arkansas business
corporation with its home office in Fayetteville, Washington County,
Arkansas, and it is engaged in the natural gas exploration, development
and production business in the States of Arkansas, Oklahoma, Texas,
Louisiana and other areas;
(c) Southwestern Energy Production Company: Southwestern
Energy Production Company ("SEPCO") is an Arkansas business corporation
with its home office situated in Fayetteville, Washington County,
Arkansas, and it is engaged in the oil and gas exploration, development
and production business in the States of Arkansas, Oklahoma, Texas,
Louisiana and other areas in the United States and in the Gulf of
Mexico; and
(d) AW Realty Company: AW Realty Company ("AWR") is an
Arkansas business corporation with its home office situated in
Fayetteville, Washington County, Arkansas, and it is engaged in real
estate development and sales and owning and operating rental properties
in Arkansas.
2. HAROLD M. KORELL: Harold M. Korell ("EMPLOYEE") is a natural person,
and is an experienced corporate executive.
<PAGE>
B. RECITALS
1. SWEN, as the parent corporation, and/or all of the Subsidiaries are
engaged in the business of oil and gas exploration and development, the sale and
distribution of oil and gas, the natural gas public utility business, the real
estate development business and/or the ownership of real estate for sale and
rental, all for the production of income.
2. SWEN wishes to be assured of the services of the EMPLOYEE,
particularly with reference to the operation of the business now conducted by
SWEN and the Subsidiaries as specified above and in the areas indicated.
3. The purposes of this Agreement are:
(a) To provide for the employment by SWEN of the EMPLOYEE, for
the benefit of SWEN and all of its Subsidiaries and their shareholders
that benefit from the professional and managerial services rendered and
to be rendered by the EMPLOYEE; and
(b) To secure for SWEN and all of its Subsidiaries the
professional and managerial services of the EMPLOYEE and to provide for
the payment of compensation to the EMPLOYEE for such services to be
rendered directly to SWEN and the Subsidiaries and any other entities
that are now or which may be owned in the future by SWEN and/or the
Subsidiaries.
C. AGREEMENT
FOR AND IN CONSIDERATION of the foregoing recitals and of the mutual
promises set forth herein, SWEN hereby employs the EMPLOYEE and the EMPLOYEE
accepts such employment, and SWEN and the EMPLOYEE each covenant and agree, one
with the other, as follows:
1. Full-time Employment:
(a) The EMPLOYEE's employment under this Agreement shall
commence April 28, 1997 (the "Commencement Date"), and shall continue
until the expiration of three (3) years from and after the Commencement
Date (the "Term of Employment"). During the Term of Employment, the
EMPLOYEE shall perform the services as a full-time employee of SWEN as
designated by the Board of Directors in the area of the Chief Operating
Officer of the exploration and production and utility business
activities of SWEN.
(b) For such services as a full-time employee, SWEN shall
compensate the EMPLOYEE as follows:
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<PAGE>
(i) SWEN shall pay the EMPLOYEE base compensation at
the rate of Two Hundred Seventy-Five Thousand Dollars
($275,000.00) per annum, in approximately equal installments
on SWEN's regularly scheduled payroll dates throughout the
Term of Employment; and, if SWEN's Board of Directors shall
determine, such additional compensation as may be provided
pursuant to any additional compensation plans adopted by SWEN
for its corporate officers as employees.
(ii) A grant, pursuant to SWEN's Stock Incentive
Plan, of 20,000 restricted shares to vest three years from the
date hereof and SWEN further grants to EMPLOYEE a cash "tax"
bonus, calculated using EMPLOYEE's estimated tax rate
(with appropriate adjustments to reflect the additional
taxable income resulting from the tax bonus), to pay for any
federal, state and/or local income taxes EMPLOYEE may
incur if EMPLOYEE elects to currently recognize income for
federal, state and local income tax purposes with respect to
such shares.
(iii) A grant, pursuant to SWEN's Stock Incentive
Plan, of 50,000 shares of Options.
(iv) A car allowance of $7,380 annually spread over
each pay period to compensate for any business use of a
personal vehicle. Any use exceeding 500 miles per month will
be compensated for at the currently allowed IRS rate.
(v) Reimbursement for relocation to Fayetteville,
Arkansas pursuant to the SWEN's employee
Relocation--Established Employees (P-17) reimbursement plan
currently in effect.
(vi) Reimbursement of all out-of-pocket expenses
incurred by the EMPLOYEE in connection with the performance of
his duties hereunder.
(c) The parties hereto contemplate that the base compensation
provided for the EMPLOYEE in paragraph (b)(i) above may be increased by
the Board of Directors of SWEN for any calendar year during the Term of
Employment and continuing thereafter during each successive calendar
year as long as the EMPLOYEE is employed on a full-time basis.
(d) The EMPLOYEE may be appointed to such executive positions
with SWEN as the Board of Directors of each shall determine.
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<PAGE>
(e) SWEN represents to the EMPLOYEE that it established and at
its expense it now maintains in continuous existence for the benefit of
its qualified officers and employees the following:
(i) A qualified retirement plan that is fully
funded through a Trust;
(ii) A stock option and incentive bonus plan;
(iii) A qualified health, medical, hospital and
dental plan that is funded by a group insurance policy issued
by a reputable insurance company authorized to do business in
the State of Arkansas, which plan provides coverage for each
such officer and employee of SWEN and their immediate family;
and
(iv) A group professional liability insurance policy
issued by a reputable insurance company authorized to do
business in the State of Arkansas, covering all of SWEN's
officers, directors and all professional, technical and
related employees with at least minimum coverage.
The EMPLOYEE shall continue to be a participant in each of the
foregoing EMPLOYEE benefit plans and any other plans presently in
existence or that SWEN may create in the future and maintain for its
officer-employees, according to the terms and provisions of each such
plan and/or insurance policy, and shall continue as such participant as
long as he is an employee of SWEN. If SWEN shall create, in the future,
any such additional employee benefit plans, the EMPLOYEE shall become a
participant therein and his interest therein (salary, bonus and other
benefits) shall vest indefeasibly simultaneously with the creation
thereof.
2. Termination of Employment of the EMPLOYEE:
(a) If SWEN shall terminate the employment of the EMPLOYEE at
any time during the Term of Employment, then the termination rights of
the EMPLOYEE hereunder shall be determined pursuant to and under that
certain Executive Severance Agreement dated April 28, 1997 (the
"Executive Severance Agreement"), between SWEN and the EMPLOYEE,
provided that the term "Contract Period" as used in the Executive
Severance Agreement shall be deemed to refer to the Term of Employment
hereunder. The Executive Severance Agreement is hereby referred to for
a full recital of the terms and provisions thereof and by this
reference is made a part hereof. To the extent there is any conflict
between the terms of this Agreement and the terms of the Executive
Severance Agreement, the terms of this Agreement shall control.
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<PAGE>
(b) At any time during the Term of Employment and on or within
thirty (30) days after the expiration of the Term of Employment,
EMPLOYEE shall have the right, at his option, to either (i) continue in
his position with SWEN or at a position appointed by the Board of
Directors or (ii) terminate his employment with SWEN and receive as a
severance payment (the "Severance Payment") a lump sum equal to the
product of (1) the highest monthly rate of base salary in effect during
the previous twelve months immediately preceding the "Termination Date"
(hereinafter defined) and (2) 12. If the EMPLOYEE elects option (i)
above, employment shall be on such terms and conditions as are mutually
acceptable and agreed upon by the EMPLOYEE and SWEN. The EMPLOYEE's
termination rights or conditions shall thereafter be as agreed upon by
contract between the EMPLOYEE and SWEN or as set forth by SWEN Company
policies. If the EMPLOYEE elects option (ii) above, the Severance
Payment shall be paid to the EMPLOYEE no later than the Termination
Date. For the purposes of this Agreement, the term "Termination Date"
shall mean the date that is five (5) business days after the EMPLOYEE
gives notice to SWEN of his election to terminate his employment.
3. Vacation: During the Term of Employment, the EMPLOYEE shall be
entitled to sick leave, holidays and an annual 4-week vacation, during which
time his compensation shall be paid in full. Each vacation shall be taken by
the EMPLOYEE at such times as may be mutually agreed upon by the EMPLOYEE and
SWEN.
4. Successors; Binding Agreement: The assignability and binding nature
of this Agreement shall be governed by the terms of Section 8 of the Executive
Severance Agreement.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement in
original duplicates on this March 29, 1997, effective as of the date April 28,
1997.
SOUTHWESTERN ENERGY COMPANY
By: /s/ CHARLES E. SCHARLAU
----------------------------------
Charles E. Scharlau
ATTEST:
/s/ GRED D. KERLEY
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Greg D. Kerley, Secretary
/s/ HAROLD M. KORELL
-------------------------------------
EMPLOYEE
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<PAGE>
THE STATE OF ARKANSAS
COUNTY OF WASHINGTON
BE IT REMEMBERED, that on this day came before the undersigned, a
Notary Public, within and for the County aforesaid, duly commissioned and
acting, Charles E. Scharlau, President and Greg D. Kerley, Secretary of
Southwestern Energy Company, a corporation, and stated that they had executed
the same for the consideration and purposes therein mentioned and set forth.
WITNESS my hand and seal as such Notary Public this 7th day of April,
1997.
/s/ PAULA J. ZULPO
-----------------------------------
Notary Public
My Commission Expires:
2-1-2003
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THE STATE OF TEXAS
COUNTY OF HARRIS
BE IT REMEMBERED, that on this day came before the undersigned, a
Notary Public, within and for the County aforesaid, duly commissioned and
acting, Harold M. Korell, to me well known as the party in the foregoing
agreement, and stated that he had executed the same for the consideration and
purposes therein mentioned and set forth.
WITNESS my hand and seal as such Notary Public this 29th day of March,
1997.
/s/ EILEEN GRADWOHL
------------------------------------
Notary Public
My Commission Expires:
March 29, 2001
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OMNIBUS PROJECT AGREEMENT
by and among
SOUTHWESTERN ENERGY PIPELINE COMPANY
SOUTHWESTERN ENERGY COMPANY
ENOGEX ARKANSAS PIPELINE CORPORATION
ENOGEX INC.
<PAGE>
<TABLE>
<CAPTION>
TABLE OF CONTENTS
Page No.
<S> <C> <C>
1. Definitions.....................................................................................1
2. Acquisition and Maintenance of Interests in NOARK...............................................6
3. Acquisition of Ozark............................................................................6
4. Acquisition of Searcy Gathering Assets .........................................................7
5. NGSC ...........................................................................................7
6. Acquisition and Merger of AWP...................................................................7
7. Closing.........................................................................................8
8. Ownership in NOARK, and Status of Capital Accounts..............................................8
9. NOARK Debt ....................................................................................9
10. FERC and HSR Applications......................................................................10
11. Representations and Warranties of Enogex and EAPC..............................................11
12. Representations and Warranties of SWN and SWPL.................................................20
13. Expenses.......................................................................................29
14. Conditions to Closing..........................................................................29
15. Indemnification................................................................................32
16. Brokers........................................................................................35
17. Notices........................................................................................35
18. Public Announcements...........................................................................37
19. Dispute Resolution ............................................................................37
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20. Governing Law..................................................................................41
21. Amendments and Waivers.........................................................................41
22. Binding Effect; Non-Assignability and Alienation
of Benefits...................................................................................41
23. Severability...................................................................................42
24. Headings and Exhibits..........................................................................41
25. Construction...................................................................................42
26. Multiple Counterparts..........................................................................42
EXHIBITS
Exhibit A Form of Asset Purchase and Sale Agreement for the Acquisition of the Ozark
Pipeline Assets
Exhibit A-1 Ozark Pipeline Description
Exhibit B The Searcy Gathering Assets
Exhibit C Form of Asset Purchase and Sale Agreement for the Acquisition of the Searcy
Gathering Assets
Exhibit D Mutual Release and Settlement Agreement between SWN, SWPL, SEMCO Energy,
Inc. and their Respective Affiliates
Exhibit E Assets of AWP
Exhibit F Amended and Restated Partnership Agreement of NOARK
Exhibit G Assets of NGSC
Exhibit H Operating Agreement for NES L.L.C.
Exhibit I Operating Agreement for OGG L.L.C.
Exhibit J Description of Interconnection, Integration and Expansion of Pipeline Facilities of
NOARK and Ozark
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Exhibit K Election to Convert
Exhibit L NOARK Debt Structure
Exhibit M Enogex and EAPC Officers' Certificates
Exhibit N SWN and SWPL Officers' Certificates
SCHEDULES
Schedule 7(b) Pipeline Extension Project
Schedule 11(g) Ozark Disclosure Schedule
Schedule 11(h) Searcy Disclosure Schedule
Schedule 12(g)(iii) NOARK Pipeline System and the AWP Pipeline System
Schedule 12(g)(iv) List of all contracts, agreements and commitments to which NOARK or
AWP, or any of their assets, are bound
Schedule 12(g)(v) Material Claims
Schedule 12(g)(ix) Liens
Schedule 12(g)(xiii) Material Adverse Changes
Schedule 12(g)(xv) Tax Examinations
Schedule 12(g)(xix) Intellectual Property
</TABLE>
iii
<PAGE>
OMNIBUS PROJECT AGREEMENT
THIS AGREEMENT ("Agreement") is entered into as of the 12th day of
January 1998, by and among Southwestern Energy Pipeline Company, an Arkansas
corporation ("SWPL"), Southwestern Energy Company, an Arkansas corporation
("SWN"), Enogex Arkansas Pipeline Corporation, an Oklahoma corporation ("EAPC")
and Enogex Inc., an Oklahoma corporation ("Enogex").
R E C I T A L S:
EAPC is currently negotiating to acquire (i) all of the partnership
interests owned by Prudential in NOARK and (ii) all of the partnership interests
owned by SEMCO in NOARK. EAPC is also currently negotiating to enter into
definitive agreements to acquire (i) all of the pipeline assets of Ozark and
(ii) the Searcy Gathering Assets owned by Warren Petroleum Company, L.P. EAPC
intends to form EIT which shall be the entity which enters into the definitive
agreement to acquire all of the pipeline assets of Ozark.
SWPL owns all of the partnership interests of NOARK, other than the
partnership interests owned by SEMCO and Prudential. SWN owns all of the
outstanding capital stock of AWP, and intends to convey such stock to SWPL.
Following such conveyance, SWPL intends to merge AWP into AWP L.L.C., subject to
the receipt of all necessary FERC approvals.
In the event EAPC successfully completes the acquisition of the NOARK
partnership interests owned by Prudential and SEMCO, and EIT executes a
definitive agreement for the acquisition of the pipeline assets of Ozark, EAPC
and SWPL propose to (i) amend and restate the existing limited partnership
agreement of NOARK, (ii) contribute additional assets into NOARK, including
without limitation, all ownership interests of AWP, all ownership interests of
EIT, the assets of NGSC and the Searcy Gathering Assets and (iii) create limited
liability companies involving gas marketing activities and gas gathering
activities, all to be wholly owned by NOARK.
The parties propose to participate in the ownership of NOARK, to
contribute additional assets to NOARK, and to participate in various actions to
be taken by, and with respect to, NOARK, all to the extent set forth in this
Agreement and in accordance with and in the manner contemplated hereby.
NOW, THEREFORE, in consideration of the premises and the mutual
covenants herein contained, the Parties agree as follows:
1. Definitions. For purposes of this Agreement
"Affiliate" or "Affiliates" means with respect to any Person, except as
otherwise provided herein: (i) any person or entity directly or
indirectly controlling, controlled or under common control with such
Person; (ii) any person or entity directly or indirectly owning or
controlling ten percent (10%) or more of the outstanding voting
securities or ownership interests of such Person; (iii) any person or
entity ten percent (10%) or more of whose outstanding voting
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<PAGE>
securities or ownership interests are directly or indirectly owned or
controlled by such Person; (iv) any officer, director, partner, manager
or member of a Person; and (v) any company for which a Person acts as
an officer, director, partner, manager or member.
"AWG" means Arkansas Western Gas Company, an Arkansas corporation, all
of the outstanding capital stock of which is owned by SWN.
"AWP" means Arkansas Western Pipeline Company, an Arkansas corporation,
all of the outstanding capital stock of which is owned by SWN.
"AWP L.L.C." means Arkansas Western Pipeline Company, L.L.C., an
Arkansas limited liability company, into which AWP is proposed to be
merged upon FERC approval thereof.
"AWP Contribution Time" shall have the meaning set forth in Section 12
(g)(xv).
"Closing" means the date and time for the execution of the amended and
restated partnership agreement of NOARK by SWPL and EAPC, and for the
contribution of various assets into NOARK as contemplated by this
Agreement, and "Closing Date" means the date of the Closing.
"Contribution Time" shall have the meaning set forth in Section 11(g).
"EAPC" means Enogex Arkansas Pipeline Corporation, an Oklahoma
corporation, all of the capital stock of which is owned by Enogex Inc.
"EAPC Permitted Liens" means (i) the terms, conditions, restrictions,
exceptions, reservations, limitations and other matters contained in
any of the rights-of-way, permits, or documents under which the Ozark
Pipeline and/or the Searcy Gathering Assets are located, and other
easements, leases, permits or other conveyance instruments provided to
SWPL by EAPC or which do not, and will not, individually and in the
aggregate, interfere materially with the continued ownership, use and
operation of the Ozark Pipeline and the Searcy Gathering Assets, taken
as a whole, in substantially the same manner as the same have been used
by Ozark and Warren Petroleum Company, L.P.; (ii) the contracts
acquired under the Asset Purchase and Sale Agreements attached as
Exhibits "A" and "C"; (iii) liens for property taxes and assessments
that are not yet due and payable (or if delinquent, that are being
contested in good faith by EIT, Ozark or Warren Petroleum Company,
L.P., as applicable, by appropriate legal proceedings); (iv)
mechanics', materialmen's, repairmen's and other statutory liens
arising in the ordinary course and which are not yet due and payable;
(v) any obligations or duties affecting the Ozark Pipeline and/or the
Searcy Gathering Assets as to any governmental authority under any
permit and all applicable laws, rules and regulations of any
governmental authorities, and all rights reserved to or vested in any
governmental authorities, and all rights reserved to or vested in any
governmental authority to control or regulate the Ozark Pipeline and/or
the Searcy Gathering Assets or the
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<PAGE>
operation thereof in any manner (other than in connection with EIT's,
Ozark's or Warren Petroleum Company, L.P.'s non-compliance with or
default under any such permit, applicable laws, rules or regulations);
(vi) utility easements, restrictive covenants, defects in title and
irregularities, and other matters that (A) are of record (to the extent
the same was indicated in the documents provided or made available by
EAPC to SWPL) or (B) do not and will not, individually or in the
aggregate, interfere materially with the continued ownership, use and
operation of the Ozark Pipeline and the Searcy Gathering Assets taken
as a whole, in substantially the same manner as same have been used by
Ozark and Warren Petroleum Company, L.P. in the past; (vii) rights of
priority which may have been acquired by any third party due to the
fact that any of the rights-of-way or documents conveying any of the
property rights to locate the Ozark Pipeline and the Searcy Gathering
Assets may not have been obtained or recorded in the appropriate county
real estate records, and (viii) matters with respect to which SWPL had
actual knowledge prior to the execution hereof.
"EIT" means Enogex Interstate Transmission, L.L.C., an Oklahoma limited
liability company formed by EAPC to acquire the pipeline assets of
Ozark.
"FERC" means the Federal Energy Regulatory Commission.
"HSR Act" means the Hart-Scott-Rodino Antitrust Improvements Act of
1976, as amended, and the rules and regulations promulgated thereunder.
"Lien" means any lien, mortgage, pledge, security interest, charge,
encroachment or encumbrance.
"Material" shall mean for purposes of Sections 11 and 12 of this
Agreement, unless the context requires another meaning, with respect to
i) a material contract, agreement or commitment, a contract, agreement
or commitment involving, or which may reasonably be expected to
involve, the payment or receipt of more than $25,000 in any one year,
or $50,000 over its term, or which is not cancelable upon one month's
notice without penalty, ii) a material claim, breach, demand or other
action, a claim, breach, demand or other action in which the amount in
controversy (or which may reasonably be expected to be in controversy)
exceeds $25,000 or in which, if adversely determined, the applicable
Person's business activities (or any part thereof) could be enjoined or
restricted, iii) material property or assets, any property or assets
having a value in excess of $25,000 and iv) a material breach, default,
or violation of any applicable laws, rules or regulation, a breach,
default or violation in which civil or criminal penalties could
reasonably be expected to be imposed or in which, if found to exist,
the applicable Person's business activities (or any part thereof) could
be enjoined or restricted.
"NES L.L.C." means NOARK Energy Services, L.L.C., the gas marketing
limited liability company to be formed by NOARK as an Oklahoma limited
liability company.
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"NGSC" means NOARK Gas Services Company, an Arkansas general
partnership formed on January 1, 1993 to i) acquire all of the assets,
and to assume all the obligations and liabilities, of NGMC, and which
did acquire and assume such assets, liabilities and obligations, and
ii) provide market development, marketing and other business
development services to NOARK.
"NGMC" means NOARK Gas Marketing Company, a Texas general partnership
formed on March 1, 1990, to provide market development, marketing and
business administration services, to NOARK, primarily during the
construction of NOARK's pipeline system, all of the assets, obligations
and liabilities of which have been conveyed to NGSC.
"NOARK" means NOARK Pipeline System, Limited Partnership, an Arkansas
limited partnership, all of the outstanding general partnership
interests of which are owned by SWPL and SEMCO, and all of the limited
partnership interests of which are owned by Prudential.
"NOARK Debt" means (a) the debt incurred by NOARK pursuant to the terms
of that certain Credit Agreement and related documents dated as of
February 26, 1993 among NOARK, the Lenders and The First National Bank
of Chicago, as Agent, as amended by the First Amendment to NOARK
Pipeline System, Limited Partnership Credit Agreement dated February 1,
1994 and (b) the debt incurred by NOARK pursuant to the terms of that
certain Construction Loan and Note Purchase Agreement and related
documents dated as of October 10, 1991 and as amended by Amendments No.
1 and No. 2 to the Construction Loan and Note Purchase Agreement dated
as of January 29, 1993, and February 24, 1993, respectively, between
NOARK and The Prudential Insurance Company of America.
"NOARK Related Entity" means any Person which is wholly owned by NOARK.
"Ozark" means Ozark Pipeline, Inc., a Delaware corporation, which owns
the Ozark pipeline system, located in Oklahoma and Arkansas.
"Ozark Disclosure Schedule" means the schedule attached hereto as
Schedule 11(g).
"OGG L.L.C." means Ozark Gas Gathering, L.L.C., the gas gathering
limited liability company to be formed by NOARK as an Oklahoma limited
liability company.
"Parties" means the parties to this Agreement.
"Person" means any individual, corporation, limited liability company,
limited or general partnership, joint venture, association, joint stock
company, trust, unincorporated organization, governmental agency (or
any department, agency or political subdivision thereof) or any other
entity.
"Pipeline" has the meaning set forth in Section 12(g)(iii).
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<PAGE>
"Prudential" means The Prudential Insurance Company of America, a New
Jersey corporation.
"Prudential Interest" means all of the limited partnership interests in
NOARK, which interests are owned by Prudential.
"Searcy Contribution Time" has the meaning in Section 11(h).
"Searcy Disclosure Schedule" means the schedule attached hereto as
Schedule 11(h).
"Searcy Gathering Assets" means those gas gathering facilities owned by
Warren Petroleum Company, L.P. which EAPC is negotiating to acquire as
contemplated in Section 4 below.
"SEMCO" means SEMCO Arkansas Pipeline Company, a Michigan corporation,
all of the outstanding capital stock of which is owned by SEMCO Energy
Ventures, Inc.
"SEMCO Interest" means all of the general partnership interests in
NOARK owned by SEMCO.
"SWN" means Southwestern Energy Company, an Arkansas corporation.
"SWPL" means Southwestern Energy Pipeline Company, an Arkansas
corporation, all of the outstanding capital stock of which is owned by
SWN.
"SWPL Interest" means all of the partnership interests in NOARK other
than the Prudential Interest and the SEMCO Interest.
"SWPL Permitted Liens" means (i) the terms, conditions, restrictions,
exceptions, reservations, limitations and other matters contained in
any of the rights-of-way, permits, or documents under which the
Pipeline is located, and other easements, leases, permits or other
conveyance instruments provided to EAPC by SWPL or which do not, and
will not, individually and in the aggregate, interfere materially with
the continued ownership, use and operation of the Pipeline, taken as a
whole, in substantially the same manner as the same have been used by
NOARK or AWP, as applicable, in the past; (ii) the contracts described
on Schedule 12(g)(iv); (iii) liens for property taxes and assessments
that are not yet due and payable (or if delinquent, that are being
contested in good faith by NOARK or AWP, as applicable, by appropriate
legal proceedings); (iv) mechanics', materialmen's, repairmen's and
other statutory liens arising in the ordinary course and which are not
yet due and payable; (v) any obligations or duties affecting the
Pipeline as to any governmental authority under any permit and all
applicable laws, rules and regulations of any governmental authorities,
and all rights reserved to or vested in any governmental authorities,
and all rights reserved to or vested in any governmental authority to
control or regulate the Pipeline or the operation thereof in any manner
(other than in connection with NOARK or AWP non-
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compliance with or default under any such permit, applicable laws,
rules or regulations); (vi) utility easements, restrictive covenants,
defects in title and irregularities, and other matters that (A) are of
record (to the extent the same was indicated in the documents provided
by SWPL to EAPC) or (B) do not and will not, individually or in the
aggregate, interfere materially with the continued ownership, use and
operation of the Pipeline, taken as a whole, in substantially the same
manner as same have been used by NOARK or AWP, as applicable, in the
past; (vii) rights of priority which may have been acquired by any
third party due to the fact that any of the rights-of-way or documents
conveying any of the property rights to locate the Pipeline may not
have been obtained or recorded in the appropriate county real estate
records; (viii) matters with respect to which EAPC had actual
knowledge prior to the execution hereof, and (ix) Liens securing the
NOARK Debt.
"Third Person" means any Person other than SWN, SWPL, Enogex, EAPC and
NOARK and their respective Affiliates.
2. Acquisition and Maintenance of Interests in NOARK.
(a) EAPC shall use its best reasonable efforts to acquire all
of the Prudential Interest.
(b) EAPC shall use its best reasonable efforts to acquire all
of the SEMCO Interest.
(c) SWPL shall continue to own, and shall not dispose of or
otherwise encumber, except as otherwise contemplated hereunder, the
SWPL Interest prior to Closing.
(d) SWPL hereby waives all rights of first refusal,
preferential purchase rights and all other rights it may have under the
Limited Partnership Agreement, dated as of October 10, 1991, and as
amended by Amendment No. 1 dated February 24, 1993 (the "Existing
Agreement"), of the NOARK Pipeline System, Limited Partnership
regarding the acquisitions contemplated by Sections 2(a) and (b) above.
(e) The Parties agree that the events and transactions
contemplated hereunder will not result in a termination of NOARK for
federal income tax purposes or otherwise. However, in the event any
such termination is deemed to have occurred under the Existing
Agreement by reason of the events and transactions contemplated
hereunder, SWPL hereby waives the provisions of Section 15.4 of the
Existing Agreement.
3. Acquisition of Ozark. EAPC shall cause EIT to use its best
reasonable efforts to enter into a definitive agreement with Ozark for the
acquisition of all of the pipeline assets of Ozark and/or the purchase of all of
the outstanding capital stock of Ozark. In the event of the execution of such an
agreement, EAPC will also cause EIT, to use its best reasonable efforts to close
such acquisition. The Parties recognize, however, that certain regulatory
authorizations as contemplated
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by Section 10 below will need to be obtained in order to close such acquisition.
Upon the closing of such acquisition, EAPC shall contribute and assign to NOARK
all of the ownership interest in EIT, and EAPC's capital account in NOARK shall
be credited with an amount equal to all amounts paid by EIT for the purchase of
the Ozark pipeline system, or the stock of Ozark, as applicable, plus the costs
incurred in obtaining the regulatory authorizations contemplated by Section 10
below. Nothing in this Agreement shall be construed to confer upon SWPL, SWN, or
NOARK or their respective successors and assigns, any right, benefit or
obligation under such definitive agreement. Such definitive agreement is in the
form of the Asset Purchase and Sale Agreement attached hereto as Exhibit "A."
Upon the acquisition of such assets and the contribution of EIT to NOARK, the
Parties agree that NOARK promptly will commence the interconnection of the NOARK
pipeline system with the Ozark pipeline system and the expansion of the NOARK
and Ozark pipeline systems as specified in Exhibit J.
4. Acquisition of Searcy Gathering Assets . EAPC shall use its best
reasonable efforts to enter into a definitive agreement with Warren Petroleum
Company, L.P. for the acquisition of the Searcy Gathering Assets described on
Exhibit "B," attached hereto and made a part hereof. In the event of the
execution of such agreement, EAPC will use its best reasonable efforts to close
such acquisition. Upon the closing of such acquisition, EAPC will, upon approval
by SWPL, which approval shall not be unreasonably withheld, contribute such
Searcy Gathering Assets to OGG L.L.C. and EAPC's capital account in NOARK shall
be credited with an amount equal to all amounts paid by EAPC for the purchase of
the Searcy Gathering Assets. Nothing in this Agreement shall be construed to
confer upon SWPL, SWN or NOARK, or their respective successors and assigns, any
right, benefit or obligation under such definitive agreement. Such definitive
agreement shall be in a form substantially similar to the Asset Purchase and
Sale Agreement attached hereto as Exhibit "C." Further, nothing in this
Agreement will be construed to obligate NOARK, SWPL or SWN to accept or agree to
the contribution of the Searcy Gathering Assets unless and until SWPL has
approved such contribution, which approval shall not be unreasonably withheld.
5. NGSC. There currently exists various disputes between SWN and its
Affiliates and SEMCO and its Affiliates regarding, among other matters, NGSC. On
or before the acquisition by EAPC of all of the SEMCO Interests, SWN, SWPL and
any of their appropriate Affiliates shall execute a Mutual Release and
Settlement Agreement between SWN, SWPL and any of their appropriate Affiliates
and SEMCO Energy, Inc. and any of its appropriate Affiliates, in the form
attached hereto as Exhibit "D."
6. Acquisition and Merger of AWP. SWN shall convey to SWPL all of the
capital stock of AWP, and SWPL shall cause AWP to be merged into AWP L.L.C. The
Parties recognize, however, that FERC authorization may be required prior to
consummating such merger. Upon the Closing, SWPL agrees to file with FERC for
such authorization and to use its best reasonable efforts to diligently pursue
and obtain such authorization. Such filing may be made in conjunction with the
filings contemplated under Section 10, and the fees and expenses of such filing
shall be borne by EAPC. Upon receipt of such authorization from FERC, SWPL
agrees to cause AWP to be merged into AWP L.L.C., and immediately thereafter to
contribute and assign all of the ownership interests in AWP L.L.C. to NOARK. In
the event such FERC authorization is not received by the closing of the Ozark
acquisition contemplated in Section 3 above, then SWPL shall convey to EAPC
seventy-
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five percent (75%) of all outstanding capital stock of AWP, free and
clear of all Liens. Following such contribution or sale of stock, as applicable,
all of the assets of AWP L.L.C., or AWP, as applicable, shall be those assets
described on Exhibit "E." In the event of such purchase of seventy-five percent
(75%) of AWP's stock, EAPC and SWPL shall contribute all of AWP's stock to
NOARK. In addition, within ten (10) days following such contribution of the
ownership interests of AWP L.L.C. into NOARK, or the contribution of all of
AWP's stock into NOARK, as applicable, EAPC shall pay to SWPL $1,575,000.00.
Upon such contribution and payment, SWPL's capital account in NOARK shall be
credited with $525,000.00 and EAPC's capital account in NOARK shall be credited
with $1,575,000.00, as a result of the contribution of AWP L.L.C. or AWP, as
applicable, into NOARK.
7. Closing. The Closing of the transaction contemplated by this
Agreement shall take place at the offices of Hall, Estill, Hardwick, Gable,
Golden & Nelson, 320 S. Boston Ave., Suite 400, Tulsa, Oklahoma or at such other
place as may be agreed to by the Parties. Subject to the terms and conditions
hereof, the following events will take place at the Closing:
(a) SWPL and EAPC shall execute the Amended and Restated
Partnership Agreement of NOARK in the form attached hereto as Exhibit
"F".
(b) SWPL shall contribute and assign to (i) OGG L.L.C. all of
the assets of NGSC, which assets are described on Exhibit "G," attached
hereto and made a part hereof and (ii) NOARK all technical information
and materials obtained or produced in conjunction with a project to
extend the pipeline system of NOARK into Oklahoma as more fully
described on Schedule 7(b).
(c) SWPL and EAPC shall cause NOARK to form NES L.L.C.
and OGG L.L.C. by filing articles of organization and executing the
operating agreements in the forms attached hereto as Exhibits "H" and
"I". NES L.L.C. shall engage in marketing activities and OGG L.L.C.
shall engage in gathering activities.
(d) EAPC shall pay to SWPL $1,172,000.00.
(e) Each of the Parties will execute and deliver such other
documents as may be required to accomplish the items set forth in (a)
through (c) above, to confirm the ownership under (b) above, and to
confirm the ownership in NOARK immediately prior to the execution of
the Amended and Restated Partnership Agreement referenced in (a) above.
8. Ownership in NOARK, and Status of Capital Accounts.
(a) Upon the Closing referenced in Section 7 above, EAPC will
elect to convert all of the Prudential Interest to general partnership
interests in NOARK except for a one percent (1%) limited partnership
interest in NOARK, and the ownership interests in NOARK shall then be
as set forth in the Amended and Restated Partnership Agreement of
NOARK, the form of which is attached as Exhibit "F." Such conversion
will be made by EAPC executing the Election to Convert in the form
attached hereto as Exhibit "K".
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(b) Upon the closing, and following the contribution to NOARK
of the assets described in Section 7(b) above, the balances of the
Capital Accounts of SWPL and EAPC in NOARK shall be as set forth in
Schedule 4.1 to the Amended and Restated Partnership Agreement of
NOARK, the form of which is attached hereto as Exhibit "F". Further,
these balances are also inclusive of the yield maintenance amounts paid
by NOARK and funded by SEMCO and SWPL discussed in Section 9(c) below.
(c) Allocations of NOARK partnership income or loss to SEMCO
will be based upon the actual closing of books on the day its interest
is sold to EAPC.
9. NOARK Debt.
(a) The Parties acknowledge that the execution of the Amended
and Restated Partnership Agreement of NOARK in the form attached as
Exhibit "F", and certain of the other actions contemplated under this
Agreement, require the consent of the lenders under the loan documents
pursuant to which the NOARK Debt described under item (a) of the
definition of NOARK Debt was incurred. Accordingly, the Parties agree
that the Closing shall not occur unless all such consents required to
be obtained from such lenders are in fact obtained.
(b) The Parties acknowledge that all loans from SEMCO and SWPL
to NOARK have been converted to capital contributions to NOARK. As
such, those loans are no longer in force or effect, and NOARK no longer
has any obligation to repay such loans. Further, the Parties also
acknowledge that the capital account balances set forth on Schedule 4.1
to the Amended and Restated Partnership Agreement of NOARK, the form of
which is attached hereto as Exhibit "F", reflect the inclusion of the
conversion of such loans to capital contributions.
(c) The Parties acknowledge that concurrent with the Closing,
Enogex is making a loan to NOARK in an amount necessary to pay off that
portion of the NOARK Debt described in item (b) of the definition of
NOARK Debt. The general terms of such loan from Enogex are described on
Exhibit "L." The Parties further acknowledge that (i) in connection
with the pay off of such portion of the NOARK Debt, NOARK is making the
yield maintenance payments to Prudential to enable the payment of such
portion of the NOARK Debt and SEMCO and SWPL shall have contributed to
NOARK amounts equal to such yield maintenance payments, and ii) SEMCO
and SWPL shall be entitled to any tax deductions or other benefits that
may arise from the respective amounts each contributed to NOARK for
such yield maintenance payments made by NOARK.
(d) Concurrent with the Closing, EAPC shall assume all
obligations of SEMCO under that portion of the NOARK Debt described
under item (a) of the definition of NOARK Debt.
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10. FERC and HSR Applications.
(a) The Parties recognize and agree that as soon as possible
following Closing, certain regulatory filings will be required in
connection with (i) EIT's contemplated acquisition of the pipeline
assets of Ozark, and (ii) the subsequent integration of those
facilities with NOARK's pipeline facilities into a single interstate
natural gas transmission system. Those filings include, but are not
limited to:
1. An Application with the FERC under Section 7(b) of
the Natural Gas Act for permission and approval to
abandon the pipeline assets of Ozark by sale to EIT
(to be made by Ozark);
2. An Application with the FERC under Section 7(c) of
the Natural Gas Act for a Certificate of Public
Convenience and Necessity authorizing EIT to acquire,
own and operate jurisdictional facilities and for
certain Blanket Authorizations (to be made by EIT);
and
3. An Application with the FERC under Section 7(c) of
the Natural Gas Act for a Certificate of Public
Convenience and Necessity authorizing EIT to
interconnect with and to acquire, own and integrate
into an existing jurisdictional pipeline system, the
intrastate pipeline facilities owned and operated by
NOARK (to be made by EIT possibly as part of its
application for certificate authorization to acquire
the Ozark system);
The Parties and their Affiliates shall provide such support and
assistance as EIT and NOARK may reasonably request with respect to the
above filings.
(b) The Parties recognize that certain filings under the HSR
Act and the rules of the Federal Trade Commission will be required in
connection with the acquisition by EIT of the pipeline assets of Ozark.
The Parties and their Affiliates shall provide such support and
assistance as EIT and NOARK may reasonably request in conjunction with
such filings and in responding to any requests for information from the
Federal Trade Commission or the United States Department of Justice.
(c) EAPC agrees to make capital contributions to NOARK equal
to all amounts paid or required to be paid by NOARK (including any
NOARK Related Entity) for the interconnection of the NOARK pipeline
system with the Ozark pipeline system, and the expansion of the NOARK
and Ozark pipeline systems as specified in Exhibit J attached hereto
which interconnection and expansion will not occur until after EAPC's
contribution of the ownership interests in EIT to NOARK contemplated by
Section 3 above. Such contributions shall be made by EAPC immediately
prior to the time the amounts under this subparagraph (c) are required
to be paid by NOARK, and shall be used by NOARK to make such payments.
EAPC's Capital Account under the Amended and Restated Partnership
Agreement of NOARK (the form of which is attached hereto) shall be
increased by the amount of such contributions at the time of such
contributions.
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11. Representations and Warranties of Enogex and EAPC. Enogex and EAPC,
jointly and severally, hereby represent and warrant as follows:
(a) Organization. Enogex is a corporation duly incorporated,
validly existing and in good standing under the laws of the State of
Oklahoma with full corporate power to carry on its business as now
being conducted. EAPC is a corporation duly incorporated, validly
existing and in good standing under the laws of the State of Oklahoma
with full corporate power to carry on its business as now being
conducted.
(b) Power and Authority; Enforceability. Each has all
requisite corporate power and authority to enter into this Agreement
and the other documents to be entered into by it at the Closing as
provided for under this Agreement and to perform its obligations
hereunder and thereunder. This Agreement has been and such other
documents will have been at the Closing duly authorized, executed and
delivered by Enogex and EAPC, and, assuming due authorization,
execution and delivery of the other Parties thereto, constitute legal,
valid and binding obligations enforceable in accordance with their
terms, except that (i) such enforcement may be limited by bankruptcy,
insolvency, reorganization, moratorium or similar laws relating to or
affecting creditors' rights generally and (ii) the remedy of specific
performance and injunction and other forms of equitable relief may be
subject to equitable defenses and to the discretion of the court before
which any proceeding therefor may be brought.
(c) No Conflict with Other Instruments or Consents. Neither
the execution and delivery of this Agreement or the other documents to
be entered into by Enogex or EAPC at the Closing as provided for in
this Agreement, nor the consummation of the transactions contemplated
hereby or thereby (i) will conflict with or result in (or with giving
of notice or passage of time or both would result in) a material
breach, default or violation of (A) any of the terms, provisions or
conditions of their charters, as amended, or bylaws, as amended or (B)
any material agreement, document, instrument, judgment, decree, order,
governmental permit, certificate or license to which either of them is
a party or to which either of them is subject or by which their
material property is bound, (ii) will result in the creation of any
lien, charge or other encumbrance on any of their material property or
assets or (iii) will require them to obtain the consent of any private
nongovernmental Third Person, except for the consent of The First
National Bank of Chicago required under the loan documents referred to
in item (a) of the definition of "NOARK Debt" in Section 1. No consent,
action, approval or authorization of, or registration, declaration or
filing with, any governmental department, commission, agency or other
instrumentality having jurisdiction over either of them is required by
them to authorize the execution and delivery by them of this Agreement
or the other documents to be entered into by them at the Closing as
provided for in this Agreement or, except for the authorizations
contemplated in Section 10 above, the consummation of the transactions
contemplated hereby and thereby.
(d) Accuracy of Representations and Warranties. All of their
representations and warranties contained in this Agreement shall be
true in all material respects at and as of the Closing, and such other
times as specifically set forth herein, as if such representations and
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warranties were made at and as of the Closing and such other times, and
they shall perform, at or prior to the relevant Closing and such other
times as specifically set forth herein, all agreements and covenants
required by this Agreement to be performed by them at or prior to the
relevant Closing and such other times.
(e) Litigation. There are no suits, actions, claims,
proceedings or investigations pending or to their knowledge,
threatened, seeking to prevent or challenge the transactions
contemplated by this Agreement.
(f) NOARK Interests. At the Closing, EAPC shall, subject to
having acquired same as contemplated by Sections 2(a) and (b), have
good title to the Prudential Interest and the SEMCO Interest, free and
clear of all Liens, except for Liens securing the NOARK Debt and the
Enogex loan referenced in Section 9(c) above.
(g) EIT Interests. At the time of the contribution of the
ownership interests in EIT to NOARK (the "Contribution Time"):
(i) The principal asset of EIT will be the Ozark
pipeline system which is more fully described in Exhibit A-1
and is referred to hereinafter sometimes as the "Ozark
Pipeline."
(ii) Except as set forth on the Ozark Disclosure
Schedule, no material claim, demand, filing, hearing, notice
of violation, proceeding, notice or demand letter,
investigation, administrative proceeding, civil, criminal or
other action, suit or other legal proceeding will be pending
or threatened, against EIT or EAPC relating to, resulting from
or affecting the ownership or operation of the Ozark Pipeline,
the consequences of which, individually or in the aggregate,
could have a material adverse effect on NOARK or any of the
NOARK Related Entities. Except as set forth on the Ozark
Disclosure Schedule, no notice from any governmental authority
or any other person (including employees) will have been
received by Enogex, EAPC or EIT or to their knowledge, the
prior owner of the Ozark Pipeline (or any affiliate thereof)
as to any material claim, demand, filing, hearing, notice of
violation, proceeding, notice or demand letter, administrative
proceeding, action, civil, criminal or other suit or other
legal proceeding relating to, resulting from or affecting the
ownership or operation of EIT or the Ozark Pipeline, claiming
any material violation of any law, statute, rule, regulation,
ordinance, order decision or decree of any governmental
authority (including, without limitation, any such law, rule,
regulation, ordinance, order, decision or decree concerning
the conservation of natural resources) or claiming any
material breach of any contract or agreement with any
third-party.
(iii) Except as set forth on the Ozark Disclosure
Schedule, the Ozark Pipeline will have been and shall at such
time continue to be operated in material compliance with the
provisions and requirements of all laws, rules, regulations,
ordinances, orders, decisions and decrees of all governmental
authorities having jurisdiction with respect to the Ozark
Pipeline or the ownership or operation thereof.
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All necessary material governmental permits, licenses and
other authorizations with regard to the ownership or operation
of the Ozark Pipeline by EIT will have been obtained and
maintained in effect; and no material violations or notices of
violations, written or otherwise, will exist in respect to
such permits, licenses or other authorizations.
(iv) Except as set forth on the Ozark Disclosure
Schedule, (i) all of the material contracts, agreements and
commitments relating to the ownership and operation of the
Ozark Pipeline shall be in full force and effect and
enforceable in accordance with their terms, and (ii) EIT shall
not be in material breach of, or with the lapse of time or the
giving of notice, or both, would be in material breach of, any
of its material obligations thereunder.
(v) All material ad valorem, property and other taxes
based on the ownership of the Ozark Pipeline that are then due
and payable will have been properly and timely paid. Except as
set forth on the Ozark Disclosure Schedule, all material
amounts payable by EIT under the terms of the contracts
described in (d) above will have been properly and timely paid
except for such amounts as are then being currently paid prior
to delinquency in the ordinary course of business. Except as
set forth on the Ozark Disclosure Schedule, all material
amounts then payable by third-parties under the terms of the
agreements described in (iv) above will be properly and timely
paid to EIT.
(vi) At the Contribution Time, EIT shall have good
title to all of the Ozark Pipeline and the other properties,
contracts and assets, real and personal of EIT, all of which
will then be free of all Liens, except for (i) liens for
current taxes and assessments that are not yet due and
payable; (ii) mechanics', warehousemen's, landlords' and other
similar statutory liens securing the payment of amounts that
are not yet due and payable and (iii) other EAPC Permitted
Liens.
(vii) To the best of EAPC's knowledge after due
inquiry, the equipment related to the Ozark Pipeline will have
been maintained in satisfactory operating condition and will
be capable of being used in the operation of the Ozark
Pipeline in the manner in which it has been historically
operated without present need for repair or replacement except
in the ordinary course of business.
(viii) Accurate and complete copies of all material
leases, instruments, contracts, agreements, permits, licenses,
rights-of-ways, certificates and other documents in connection
with the transactions contemplated by this Agreement will have
been delivered or otherwise made available to NOARK and SWPL.
(ix) Environmental Compliance. Except as set forth on
the Ozark Disclosure Schedule:
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(a) EIT will have obtained all material permits,
licenses and other authorizations ("Environmental Permits")
relating to the Ozark Pipeline, which are then required under
applicable laws relating to pollution or protection of the
environment, including laws relating to emissions, discharges,
releases or threatened releases of pollutants, contaminants,
or hazardous or toxic materials or wastes into ambient air,
surface water, ground water, or land, or otherwise relating to
the manufacture, processing, distribution, use, treatment,
storage, disposal, transport, or handling of pollutants,
contaminants, or hazardous or toxic materials or wastes into
ambient air, surface water, ground water or land, or otherwise
relating to the manufacture, processing, distribution, use,
treatment, storage, disposal, transport or handling of
pollutants, contaminants or hazardous or toxic materials or
wastes (collectively, the "Environmental Laws").
(b) EIT and the Ozark Pipeline will be in material
compliance with all terms and conditions of such Environmental
Permits and with all other limitations, restrictions,
conditions, standards, prohibitions, requirements,
obligations, schedules and timetables contained in such
Environmental Laws or contained in any regulation, code, plan,
order, decree, judgment or notice or demand letter from a
governmental entity issued, entered, promulgated or approved
thereunder as they will then apply to EIT or the Ozark
Pipeline.
(c) Enogex, EAPC or EIT will not have received any
notification from any governmental authority or any other
person that any of the current or former properties, assets or
operations of EIT or the Ozark Pipeline will then be in or
claimed to be in material violation of any applicable
Environmental Laws.
(d) There will be no material civil, criminal or
administrative action, suit, demand, claim, hearing, notice of
violation, investigation, proceeding, notice or demand letter
from a governmental entity pending or threatened against
Enogex, EAPC or EIT with respect to the Ozark Pipeline
claiming a violation of, or any probable or potential
violation of, any applicable Environmental Laws.
(e) To the best of their knowledge after due inquiry,
there will be no past or present events, conditions,
circumstances, activities, practices, incidents, actions or
plans, which will interfere with, or prevent material
compliance or continued material compliance with, the
Environmental Laws or with any regulation, code, plan, order,
decree, judgment, injunction, notice or demand letter from any
governmental entity issued, entered, promulgated or approved
thereunder, or which will give rise to any legal liability,
including, without limitation, liability under the
Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA") or similar state or local laws, or
otherwise form the basis of any claim, action, demand, suit,
proceeding, hearing, notice of violation, or investigation
which would be materially adverse, individually or in the
aggregate, to EITbased on or
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resulting from the conduct of the business of EIT, including
the ownership and operation of the Ozark Pipeline,
manufacture, processing, distribution, use, treatment,
storage, disposal, transport or handling, or the emission,
discharge, release or threatened release into the environment,
of any pollutant, contaminant, chemical, or industrial toxic
or hazardous material, substance or waste. To the best of
their knowledge after due inquiry, no release, emission or
discharge into the environment of any hazardous substance (as
that term is currently defined under CERCLA or any applicable
analogous state law) will have occurred or will then be
occurring in connection with the conduct of the business of
EIT, including the ownership and operation of the Ozark
Pipeline, as a result of which release, emission or discharge,
individually or in the aggregate, there would be a material
adverse affect on EIT. To the best of their knowledge after
due inquiry, the real property then owned or leased by EIT or
upon which EIT will then have a right-of-way will contain no
spill, deposit or discharge of any hazardous substance (as
that term is then defined under CERCLA or any applicable
analogous state law), as a result of which spill, deposit or
discharge, individually or in the aggregate, there would be a
material adverse effect on EIT or the Ozark Pipeline.
(x) All material taxes based upon, measured by or
imposed with respect to EIT or the prior owner of the Ozark
Pipeline (if EIT acquires the assets of the Ozark Pipeline
System) which are attributable to the period on or before the
Contribution Time will have been paid or deposited to the
extent required to be so paid or deposited.
(xi) To the best of their knowledge, except as set
forth on the Ozark Disclosure Schedule or in the Asset
Purchase and Sale Agreement attached as Exhibit "A," EIT will
not have any material liabilities or obligations of any
nature, whether absolute, accrued, contingent or otherwise,
and whether due or to become due (including without
limitation, any liability for taxes and interest, penalty or
other charges payable with respect to any such liability or
obligation).
(xii) At the Contribution Time, (i) EAPC shall have
good title to all of the ownership interests in EIT, free and
clear of all Liens, and all of those ownership interests shall
be owned by EAPC free and clear of any security interests,
voting trusts, agreements, proxies, options or other
restrictions; (ii) EIT will have no subsidiaries, no interest
in any partnership or joint venture and will not hold shares
of stock or other ownership interest in any corporation, trust
or other Person; and (iii) there will be: (a) no existing
subscriptions, options, warrants, calls, commitments or rights
of any character to purchase or otherwise acquire any shares
of capital stock or other securities or interests of EIT; and
(b) no contracts, subscriptions, options, warrants, calls,
commitments or rights to purchase or otherwise acquire, any
securities or other interests that are convertible into or
exchangeable for shares of capital stock or other securities
or interests of EIT.
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(xiii) With respect to the Asset Purchase and Sale
Agreement attached hereto as Exhibit A (the "Ozark
Agreement"):
(a) the employees of Ozark which are to
become employees of EIT under the terms of the Ozark
Agreement shall, prior to or at the time of the
contribution of EIT to NOARK, become employees of
EAPC (or one of its Affiliates) and EAPC (or one of
its Affiliates) shall bear, without reimbursement
from NOARK, all of the cost and expense of such
employees, including the obligation to make any
severance, termination or other such payments to any
of such employees; provided, however, if EAPC (or any
of its Affiliates) utilizes any of such employees in
providing services to NOARK (including any NOARK
Related Entity) under The Amended and Restated
Partnership Agreement of NOARK, then the costs of
such employees in providing such services shall be
reimbursed by NOARK in accordance with the Accounting
Procedures attached to such Amended and Restated
Partnership Agreement.
(b) EIT will not agree to any allocation of
the purchase price payable under the terms of the
Ozark Agreement without first obtaining SWPL's
agreement with or approval of the proposed
allocation, which agreement or approval will not be
unreasonably withheld;
(c) Enogex shall be responsible for ensuring
that Natural Gas Clearinghouse ("NGC") fulfills its
obligations under that certain Imbalance Makeup
Agreement, dated December 15, 1997;
(d) at the Contribution Time, Ozark will
have fully and completely complied with the
compressor overhaul schedule and planned maintenance
set forth on Exhibit D of the Ozark Agreement and
NOARK will not, from and after the Contribution Time,
bear or incur any cost or expense to perform any of
the actions with respect to the Ozark Pipeline
required to be performed by or at the expense of
Ozark on such schedule prior to the closing of the
transactions contemplated by the Ozark Agreement.
(h) Searcy Gathering Assets. At the time that the Searcy
Gathering Assets are contributed to NOARK (the "Searcy Contribution
Time"):
(i) Except as set forth on the Searcy Disclosure
Schedule, no material claim, demand, filing, hearing, notice
of violation, proceeding, notice or demand letter,
investigation, administrative proceeding, civil, criminal or
other action, suit or other legal proceeding will be pending
or threatened, against EAPC relating to, resulting from or
affecting the ownership or operation of the Searcy Gathering
Assets, the consequences of which, individually or in the
aggregate, could have a
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materially adverse effect on NOARK or any of the NOARK Related
Entities. No notice from any governmental authority or any
other person (including employees) will have been received by
Enogex, EAPC or to its knowledge, the prior owner of the
Searcy Gathering Assets (or any affiliate thereof) as to any
material claim, demand, filing, hearing, notice of violation,
proceeding, notice or demand letter, administrative
proceeding, action, civil, criminal or other suit or other
legal proceeding relating to, resulting from or affecting the
ownership or operation of EAPC pertaining to the Searcy
Gathering Assets, claiming any material violation of any law,
statute, rule, regulation, ordinance, order decision or decree
of any governmental authority (including, without limitation,
any such law, rule, regulation, ordinance, order, decision or
decree concerning the conservation of natural resources)
pertaining to the Searcy Gathering Assets or claiming any
material breach of any contract or agreement with any
third-party pertaining to the Searcy Gathering Assets.
(ii) Except as set forth on the Searcy Disclosure
Schedule, the Searcy Gathering Assets will have been and shall
be continuing to be operated, in material compliance with the
provisions and requirements of all laws, rules, regulations,
ordinances, orders, decisions and decrees of all governmental
authorities having jurisdiction with respect to the Searcy
Gathering Assets or the ownership or operation thereof. All
necessary material governmental permits, licenses and other
authorizations with regard to the ownership or operation of
the Searcy Gathering Assets by EAPC will have been obtained
and maintained in effect; and no material violations or
notices of violations, written or otherwise, will exist in
respect to such permits, licenses or other authorizations.
(iii) Except as set forth on the Searcy Disclosure
Schedule, (i) all of the material contracts, agreements and
commitments relating to the ownership and operation of the
Searcy Gathering Assets shall be in full force and effect and
enforceable in accordance with their terms, and (ii) EAPC
shall not be in material breach of, or with the lapse of time
or the giving of notice, or both, would be in material breach
of, any of its material obligations thereunder.
(iv) All material ad valorem, property and other
taxes based on the ownership of the Searcy Gathering Assets
that are then due and payable will have been properly and
timely paid. Except as set forth on the Searcy Disclosure
Schedule, all material amounts payable by EAPC under the terms
of the contracts described in (c) above will have been
properly and timely paid except for such amounts as are then
being currently paid prior to delinquency in the ordinary
course of business. Except as set forth on the Searcy
Disclosure Schedule, all material amounts then payable by
third parties under the terms of the agreements described in
(iii) above will be properly and timely paid to EAPC.
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<PAGE>
(v) At the Searcy Contribution Time, EAPC shall have
good title to all of the Searcy Gathering Assets free of all
Liens, except for (i) liens for current taxes and assessments
that are not yet due and payable; (ii) mechanics',
warehousemen's, landlords' and other similar statutory liens
securing the payment of amounts that are not yet due and
payable and (iii) other EAPC Permitted Liens.
(vi) To the best of EAPC's knowledge after due
inquiry, the equipment related to the Searcy Gathering Assets
will have been maintained in satisfactory operating condition
and will be capable of being used in the operation of the
Searcy Gathering Assets in the manner in which it has been
historically operated without present need for repair or
replacement except in the ordinary course of business.
(vii) Accurate and complete copies of all material
leases, instruments, contracts, agreements, permits, licenses,
rights-of-ways, certificates and other documents in connection
with the transactions contemplated by this Agreement will have
been delivered or otherwise made available to NOARK and SWPL.
(viii) Environmental Compliance. Except as set forth
on the Searcy Disclosure Schedule:
(a) EAPC will have obtained all Environmental Permits
relating to the Searcy Gathering Assets, which are then
required under any applicable Environmental Laws.
(b) EAPC and the Searcy Gathering Assets will be in
material compliance with all terms and conditions of such
Environmental Permits and with all other limitations,
restrictions, conditions, standards, prohibitions,
requirements, obligations, schedules and timetables contained
in such Environmental Laws or contained in any regulation,
code, plan, order, decree, judgment or notice or demand letter
from a governmental entity issued, entered, promulgated or
approved thereunder as they will then apply to EAPC and the
Searcy Gathering Assets.
(c) Enogex or EAPC will not have received any
notification from any governmental authority or any other
person that any of the current or former properties, assets or
operations of EAPC pertaining to the Searcy Gathering Assets
or the Searcy Gathering Assets will then be in or claimed to
be in material violation of any applicable Environmental Laws.
(d) There will be no material civil, criminal or
administrative action, suit, demand, claim, hearing, notice of
violation, investigation, proceeding, notice or demand letter
from a governmental entity pending or threatened against EAPC
with respect to the Searcy Gathering Assets claiming a
violation of, or any probable or potential violation of, any
applicable Environmental Laws.
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<PAGE>
(e) To the best of their knowledge after due inquiry,
there will be no past or present events, conditions,
circumstances, activities, practices, incidents, actions or
plans, which will interfere with, or prevent material
compliance or continued material compliance with, the
Environmental Laws or with any regulation, code, plan, order,
decree, judgment, injunction, notice or demand letter from any
governmental entity issued, entered, promulgated or approved
thereunder, or which will give rise to any legal liability,
including, without limitation, liability under CERCLA or
similar state or local laws, or otherwise form the basis of
any claim, action, demand, suit, proceeding, hearing, notice
of violation, or investigation which would be materially
adverse, individually or in the aggregate, to EAPC or the
Searcy Gathering Assets based on or resulting from the conduct
of the business of EAPC as it pertains to the ownership and
operation of the Searcy Gathering Assets or the manufacture,
processing, distribution, use, treatment, storage, disposal,
transport or handling, or the emission, discharge, release or
threatened release into the environment, of any pollutant,
contaminant, chemical, or industrial toxic or hazardous
material, substance or waste from the Searcy Gathering Assets.
To the best of their knowledge after due inquiry, no release,
emission or discharge into the environment of any hazardous
substance (as that term is currently defined under CERCLA or
any applicable analogous state law) will have occurred or will
then be occurring in connection with the conduct of the
business of EAPC as it pertains to the ownership and operation
of the Searcy Gathering Assets, as a result of which release,
emission or discharge, individually or in the aggregate, there
would be a material adverse affect on EAPC. To the best of
their knowledge after due inquiry, the real property then
owned or leased by EAPC pertaining to the Searcy Gathering
Assets or upon which EAPC will then have a right-of-way
pertaining to the Searcy Gathering Assets will contain no
spill, deposit or discharge of any hazardous substance (as
that term is then defined under CERCLA or any applicable
analogous state law), as a result of which spill, deposit or
discharge, individually or in the aggregate, there would be a
material adverse effect on EAPC or the Searcy Gathering
Assets.
(ix) All material taxes based upon, measured by or
imposed with respect to EAPC pertaining to the Searcy
Gathering Assets or the prior owner of the Searcy Gathering
Assets which are attributable to the period on or before the
Searcy Contribution Time will have been paid or deposited to
the extent required to be so paid or deposited.
(x) To the best of their knowledge, except as set
forth on the Searcy Disclosure Schedule, or in the Asset
Purchase and Sale Agreement attached as Exhibit "C," EAPC will
not have any material liabilities or obligations pertaining to
the Searcy Gathering Assets of any nature, whether absolute,
accrued, contingent or otherwise, and whether due or to become
due (including without limitation, any liability for taxes and
interest, penalty or other charges payable with respect to any
19
<PAGE>
such liability or obligation).
(i) Brokers. They have not employed, directly or indirectly
for their benefit, any broker or finder or incurred any liability for
any financial advisory fees, brokerage fees, commissions or finders'
fees, and no broker or finder has acted directly or indirectly for them
in connection with this Agreement or the transactions contemplated
hereby.
(j) Material Fact. To the best of their knowledge, no
representation or warranty in this Section 11, contains any untrue
statement of a material fact or omits to state any material fact which
is necessary to make any of the representations and warranties made
herein, in light of the circumstances in which they are made, not
misleading.
(k) No Reliance. Except as to the representations of SWN or
SWPL expressly set forth in Section 12 of this Agreement, Enogex and
EAPC have not relied upon any oral or written statements,
representations, or warranties which may have been made by or on behalf
of SWN or SWPL or upon any written reports, financial or production
data, business plans, projections, forecasts, projections of feedstock
availability or evaluations, or any environmental reports, audits,
studies or assessments, or any other written materials, copies of which
may have been furnished to Enogex or EAPC or as to which Enogex or EAPC
may have been provided access in connection with the transactions
contemplated by this Agreement. TO THE EXTENT THAT ENOGEX OR EAPC HAVE
BEEN FURNISHED COPIES OF OR BEEN PROVIDED ACCESS TO ANY OF THE
FOREGOING, ENOGEX AND EAPC ACKNOWLEDGE THAT NEITHER SWN, SWPL NOR ANY
OF THEIR AFFILIATES, OR ANY OF THEIR RESPECTIVE OFFICERS, DIRECTORS,
EMPLOYEES, REPRESENTATIVES AND AGENTS, HAS MADE, AND HEREBY EXPRESSLY
DISCLAIM, ANY REPRESENTATIONS OR WARRANTIES AS TO THE ACCURACY OR
COMPLETENESS OF SUCH INFORMATION, DATA OR MATERIALS (WHETHER WRITTEN OR
ORAL) WHICH MAY HAVE BEEN FURNISHED TO ENOGEX OR EAPC OR THEIR
REPRESENTATIVES OR AGENTS BY OR ON BEHALF OF SWN OR SWPL IN CONNECTION
WITH THE TRANSACTIONS CONTEMPLATED HEREBY.
12. Representations and Warranties of SWN and SWPL. SWN and SWPL,
jointly and severally, hereby represent and warrant as follows:
(a) Organization. SWN is a corporation duly incorporated,
validly existing and in good standing under the laws of the State of
Arkansas with full corporate power to carry on its business as now
being conducted. SWPL is a corporation duly incorporated, validly
existing and in good standing under the laws of the State of Arkansas
with full corporate power to carry on its business as now being
conducted.
(b) Power and Authority; Enforceability. Each has all
requisite corporate power and authority to enter into this Agreement
and the other documents to be entered into by it
20
<PAGE>
at the Closing as provided for under this Agreement and to perform its
obligations hereunder and thereunder. This Agreement has been and such
other documents will have been at the Closing duly authorized, executed
and delivered by SWN and SWPL, and, assuming due authorization,
execution and delivery of the other Parties thereto, constitute legal,
valid and binding obligations enforceable in accordance with their
terms, except that (i) such enforcement may be limited by bankruptcy,
insolvency, reorganization, moratorium or similar laws relating to or
affecting creditors' rights generally and (ii) the remedy of specific
performance and injunction and other forms of equitable relief may be
subject to equitable defenses and to the discretion of the court before
which any proceeding therefor may be brought.
(c) No Conflict with Other Instruments or Consents. Neither
the execution and delivery of this Agreement or the other documents to
be entered into by SWN or SWPL at the Closing as provided for in this
Agreement, nor the consummation of the transactions contemplated hereby
or thereby (i) will conflict with or result in (or with giving of
notice or passage of time or both would result in) a material breach,
default or violation of (A) any of the terms, provisions or conditions
of their charters, as amended, or bylaws, as amended or (B) any
material agreement, document, instrument, judgment, decree, order,
governmental permit, certificate or license to which either of them,
NOARK or AWP is a party or to which either of them, NOARK or AWP is
subject or by which their NOARK's or AWP's material property is bound,
(ii) will result in the creation of any lien, charge or other
encumbrance on any of their material property or assets or (iii) will
require them, NOARK or AWP to obtain the consent of any private
nongovernmental Third Person, except for the consent of The First
National Bank of Chicago required under the loan documents referred to
in item (a) of the definition of "NOARK Debt" in Section 1. No consent,
action, approval or authorization of, or registration, declaration or
filing with, any governmental department, commission, agency or other
instrumentality having jurisdiction over either of them, NOARK or AWP
is required by them, NOARK or AWP to authorize the execution and
delivery by them of this Agreement or the other documents to be entered
into by them at the Closing as provided for in this Agreement or,
except for the authorizations contemplated in Section 6 and 10 above,
the consummation of the transactions contemplated hereby and thereby.
(d) Accuracy of Representations and Warranties. All of their
representations and warranties contained in this Agreement shall be
true in all material respects at and as of the Closing and such other
times as specifically set forth herein as if such representations and
warranties were made at and as of the Closing and such other times, and
they shall perform, at or prior to the relevant Closing and such other
times as specifically set forth herein, all agreements and covenants
required by this Agreement to be performed by them at or prior to the
relevant Closing and such other times.
(e) Litigation. There are no suits, actions, claims,
proceedings or investigations pending or to their knowledge,
threatened, seeking to prevent or challenge the transactions
contemplated by this Agreement.
21
<PAGE>
(f) NOARK Interests. At the Closing, SWPL shall have good
title to the SWPL Interest, free and clear of all Liens, except for
Liens securing the NOARK Debt and the Enogex loan referenced in Section
9(c) above.
(g) NOARK and AWP Operations. With respect to the activities
and operations of NOARK and AWP:
(i) SWPL has been the managing partner and the
operator of NOARK since its in-service date and SWN was the
managing partner of NOARK Pipeline System, an Arkansas general
partnership, from its creation until its termination. AWG has
been the operator of AWP since its creation and was and will
be the operator of AWP, and its related assets, from its
creation until it is merged into AWP L.L.C.
(ii) There are not now, and never have been, any
employees of NOARK or AWP and there are no "employee benefit
plans" (as such term is defined in Section 3(3) of the
Employment Retirement Income Security Act of 1974) sponsored
by, maintained by or to which NOARK or AWP have contributed).
(iii) The principal asset of NOARK is the NOARK
Pipeline System which is more fully described on Schedule
12(g)(iii), and the principal asset of AWP is the AWP Pipeline
System which is more fully described on Schedule 12(g)(iii) as
well. The NOARK Pipeline System and the AWP Pipeline System
are herein referred to as the "Pipeline."
(iv) Schedule 12(g)(iv) attached hereto contains a
complete and accurate list of all material contracts,
agreements and commitments to which NOARK or AWP, or any of
their assets, are bound, including, but not limited to: (a)
any agreement with SWPL or any of its Affiliates; (b) any
material gas transportation agreements; (c) any material
agreement currently in effect with a general contractor for
the construction of any of the Pipeline; (d) any agreement
with any lender; (e) any material agreement to sell, lease or
otherwise dispose of any interest in any of NOARK's or AWP's
assets; (f) any material operating agreement or operating and
maintenance agreement of NOARK or AWP; and (g) any contract
that has a significant impact on the Pipeline, NOARK, AWP or
any of their assets.
(v) Except as described on Schedule 12(g)(v), no
material claim, demand, filing, hearing, notice of violation,
proceeding, notice or demand letter, investigation,
administrative proceeding, civil, criminal or other action,
suit or other legal proceeding is pending or threatened,
against NOARK, AWP or SWPL relating to, resulting from or
affecting the ownership or operation of the Pipeline, NOARK or
AWP, no notice from any governmental authority or any other
person (including
22
<PAGE>
employees) has been received by SWPL, NOARK or AWP as to any
material claim, demand, filing, hearing, notice of violation,
proceeding, notice or demand letter, administrative
proceeding, action, civil, criminal or other suit or other
legal proceeding relating to, resulting from or affecting the
ownership or operation of NOARK, AWP or the Pipeline, claiming
any material violation of any law, statute, rule, regulation,
ordinance, order decision or decree of any governmental
authority (including, without limitation, any such law, rule,
regulation, ordinance, order, decision or decree concerning
the conservation of natural resources) or claiming any
material breach of any contract or agreement with any third
party.
(vi) NOARK, AWP and the Pipeline have been and
currently are operated, and NOARK and AWP and the Pipeline
are, in material compliance with the provisions and
requirements of all laws, rules, regulations, ordinances,
orders, decisions and decrees of all governmental authorities
having jurisdiction with respect to the Pipeline, NOARK or AWP
or the ownership or operation thereof. All necessary material
governmental permits, licenses and other authorizations with
regard to the ownership or operation of the Pipeline by NOARK
or AWP have been obtained and maintained in effect; and no
material violations or notices of violations, written or
otherwise, exist in respect to such permits, licenses or other
authorizations.
(vii) All of the contracts described in Schedule
12(g)(iv) attached hereto are in full force and effect and
enforceable in accordance with their terms, and neither SWPL ,
NOARK nor AWP is in material breach of, or with the lapse of
time or the giving of notice, or both, would be in material
breach of, any of its obligations thereunder.
(viii) All material ad valorem, property and other
taxes based on the ownership of the assets of NOARK or AWP and
the Pipeline that are due and payable have been properly and
timely paid. All material amounts payable by either NOARK,
AWP, or SWPL under the terms of the contracts described in
Schedule 12(g)(iv) attached hereto have been properly and
timely paid except for such expenses as are being currently
paid prior to delinquency in the ordinary course of business.
All material amounts payable by third parties under the terms
of the agreements described on Schedule 12(g)(iv) of this
Agreement are being properly and timely paid to SWPL, NOARK or
AWP, as the case may be.
(ix) NOARK shall have good title to the NOARK
Pipeline System at the Closing and AWP L.L.C. or AWP, as
applicable, shall have good title to the AWP Pipeline System
at the AWP Contribution Time and their other respective
properties, contracts and assets, real and personal, all of
which are, or shall be, as applicable, free of all Liens,
except for (a) Liens listed on Schedule 12(g)(ix) attached
hereto; (b) liens for current taxes and assessments that are
not yet due and payable; and (c) mechanics', warehousemen's,
landlords' and other similar statutory liens securing
23
<PAGE>
the payment of amounts that are not yet due and payable and
(d) other Permitted Liens.
(x) To the best of SWPL's knowledge after due
inquiry, the equipment related to the Pipeline has been
maintained in satisfactory operating condition and is capable
of being used in the operation of the Pipeline in the manner
in which it has been historically operated without present
need for repair or replacement except in the ordinary course
of business.
(xi) Accurate and complete copies of all material
leases, instruments, contracts, agreements, permits, licenses,
rights-of-ways, certificates and other documents in connection
with the transactions contemplated by this Agreement have been
delivered or otherwise made available to Enogex and EAPC.
(xii) SWPL has delivered to Enogex and EAPC copies of
the following financial statements of NOARK and AWP
(collectively referred to herein as the "Financial
Statements");
(a) The audited (as to NOARK) and
unaudited (as to AWP) Balance Sheets
dated as of December 31, 1996.
(b) The audited (as to NOARK) and
unaudited (as to AWP) Income
Statements for the fiscal year ended
December 31, 1996.
(c) The unaudited Statements of cash
flow for the fiscal years ended
December 31, 1996, December 31, 1995
and December
31, 1994.
(d) The audited (as to NOARK) and
unaudited (as to AWP) Balance Sheets
as of December 31, 1995 and December
31, 1994, and the audited (as to
NOARK) and the unaudited (as to AWP)
Income Statements for the fiscal
years ended December 31, 1995 and
December 31, 1994.
The books and records of NOARK and AWP have been kept and
maintained in accordance with the FERC uniform system of
accounts. The Financial Statements have been prepared in
accordance with generally accepted accounting principles
consistently applied and the FERC uniform system of accounts,
as applicable, except as noted therein, and fairly present in
all material respects (i) the financial position of NOARK and
AWP, as applicable, as of the respective dates set forth
therein and (ii) the results of the operations and cash flows
of NOARK and AWP, as applicable, for the fiscal periods set
forth therein.
24
<PAGE>
(xiii) Except as described on Schedule 12(g)(xiii),
since December 31, 1996, in the aggregate, there have been no
material adverse changes in (a) the assets, liabilities or
financial condition of NOARK or AWP or (b) the business,
financial conditions or results of operations of NOARK or AWP.
(xiv) Environmental Compliance.
(a) NOARK and AWP have obtained all material permits,
licenses and other authorizations ("Environmental Permits")
relating to NOARK, AWP and the Pipeline, which are required
under applicable laws relating to pollution or protection of
the environment, including laws relating to emissions,
discharges, releases or threatened releases of pollutants,
contaminants, or hazardous or toxic materials or wastes into
ambient air, surface water, ground water, or land, or
otherwise relating to the manufacture, processing,
distribution, use, treatment, storage, disposal, transport, or
handling of pollutants, contaminants, or hazardous or toxic
materials or wastes into ambient air, surface water, ground
water or land, or otherwise relating to the manufacture,
processing, distribution, use, treatment, storage, disposal,
transport or handling of pollutants, contaminants or hazardous
or toxic materials or wastes (collectively, the "Environmental
Laws").
(b) NOARK, AWP and the Pipeline are in material
compliance with all terms and conditions of such Environmental
Permits and with all other limitations, restrictions,
conditions, standards, prohibitions, requirements,
obligations, schedules and timetables contained in such
Environmental Laws or contained in any regulation, code, plan,
order, decree, judgment or notice or demand letter from a
governmental entity issued, entered, promulgated or approved
thereunder as they apply to NOARK, AWP or the Pipeline.
(c) SWPL, NOARK or AWP has not received any
notification from any governmental authority or any other
person, nor does SWPL have knowledge that any of the current
or former properties, assets or operations of NOARK or AWP are
in or claimed to be in material violation of any applicable
Environmental Laws.
(d) There is no material civil, criminal or
administrative action, suit, demand, claim, hearing, notice of
violation, investigation, proceeding, notice or demand letter
from a governmental entity pending or, to SWPL's knowledge,
threatened against NOARK, AWP or SWPL, with respect to NOARK,
AWP or the Pipeline claiming a violation of, or any probable
or potential violation of, any applicable Environmental Laws.
(e) To the best of their knowledge, after due
inquiry, there are no past or present events, conditions,
circumstances, activities, practices, incidents, actions or
plans, which will interfere with, or prevent material
compliance or continued material
25
<PAGE>
compliance with, the Environmental Laws or with any
regulation, code, plan, order, decree, judgment, injunction,
notice or demand letter from any governmental entity issued,
entered, promulgated or approved thereunder, or which will
give rise to any legal liability, including, without
limitation, liability under the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA") or similar
state or local laws, or otherwise form the basis of any claim,
action, demand, suit, proceeding, hearing, notice of
violation, or investigation which would be materially adverse
to SWPL, NOARK, AWP or the Pipeline, based on or resulting
from the conduct of the business of NOARK or AWP, including
the ownership and operation of the Pipeline, manufacture,
processing, distribution, use, treatment, storage, disposal,
transport or handling, or the emission, discharge, release or
threatened release into the environment, of any pollutant,
contaminant, chemical, or industrial toxic or hazardous
material, substance or waste. To the best of their knowledge,
after due inquiry, no release, emission or discharge into the
environment of any hazardous substance (as that term is
currently defined under CERCLA or any applicable analogous
state law) has occurred or is currently occurring in
connection with the conduct of the business of NOARK or AWP,
including the ownership and operation of the Pipeline, as a
result of which release, emission, or discharge, there would
be a material adverse effect on SWPL, NOARK or AWP. To the
best of SWPL's knowledge, the real property currently owned or
leased by NOARK and AWP or upon which NOARK or AWP has a
right-of-way contains no spill, deposit or discharge of any
hazardous substance (as that term is currently defined under
CERCLA or any applicable analogous state law), as a result of
which spill, deposit or discharge, there would be a material
adverse effect on SWPL, NOARK, AWP or the Pipeline.
(xv) All material taxes based upon, measured by or
imposed with respect to NOARK or AWP which are attributable to
the period on or before the Closing Date, or with respect to
AWP or AWP L.L.C., as applicable, which are attributable to
the period on or before the date AWP is contributed to NOARK
or AWP is merged into AWP L.L.C. and contributed to NOARK, as
applicable, (in either case the "AWP Contribution Time"),
respectively, have been or will be paid or deposited, to the
extent required to be so paid or deposited, or accruals (for
taxes not yet due and owing based on a good faith estimate of
the taxes anticipated to be owed) will have been made on the
books of NOARK, AWP and/or AWP L.L.C., as applicable and all
returns, statements and reports with respect to such taxes
which are required to be filed on or before the Closing Date
or in the case of AWP or AWP L.L.C., as applicable, the AWP
Contribution Time have been (or will have been by the Closing
Date or in the case of AWP or AWP L.L.C., as applicable, by
the AWP Contribution Time) filed. All tax returns filed by
NOARK or AWP on or before the Closing, and also in the case of
AWP that will have been filed prior to the AWP Contribution
Time, constitute, or will constitute, complete and accurate
representations of their tax liabilities for such years and
accurately set forth or will set forth all material items
26
<PAGE>
(to the extent required to be included or reflected in such
returns) relevant to their future tax liabilities, including
the tax basis of their material properties and assets. Except
as set forth on Schedule 12(g)(xv), none of SWPL, NOARK, nor
AWP has waived or extended, or in the case of AWP will have
waived or extended at the AWP Contribution Time, any
applicable statute of limitations relating to the assessment
of federal, state, local or foreign taxes. Except as provided
in Schedule 12(g)(xv) no examinations of the federal, state,
local or foreign tax returns of NOARK or AWP are currently in
progress nor, in the case of AWP or AWP L.L.C. will be in
progress at the AWP Contribution Time nor, to the best of
SWPL's knowledge, is or will be any such examination noticed
or threatened. No material issue or issues have been raised in
connection with any prior or pending review or audit of said
federal, state, local or foreign tax returns which may be
expected to be raised in the future by such taxing authorities
in connection with the audit or review of the tax returns of
NOARK, AWP or AWP L.L.C. AWP or AWP L.L.C. is not a party to
any tax sharing or similar agreement, and it has no liability
for taxes of any other corporation.
(xvi) An election under Section 754 of the Internal
Revenue Code, as amended, has not been made by NOARK, AWP nor
AWP L.L.C.
(xvii) NOARK is an Arkansas limited partnership, duly
formed, validly existing and in good standing under the laws
of the State of Arkansas with full power to carry on its
business as now being conducted.
(xviii) NOARK is, and has been since its creation,
treated as a limited partnership for all purposes under state
and federal tax laws, rules and regulations.
(xix) Except as set forth in Schedule 12(g)(xix),
there are no patents, franchises, trademarks, service marks,
licenses, copyrights, trade secrets (as defined in 78 Okla.
Stat. ss. 86) or other assets of the same types as those
enumerated above which are used in the operation of the
businesses of NOARK or AWP. NOARK and AWP are in material
compliance with all such items set forth in Schedule
12(g)(xix). To the best of their knowledge, after due inquiry,
the conduct of the businesses of NOARK and AWP does not
conflict with, infringe upon or violate the patents,
franchises, trademarks, service marks, processes, process
technology or copyrights or other intangible assets of any
other person or entity.
(xx) To the best of their knowledge, after due
inquiry, all material receivables of NOARK, AWP and AWP L.L.C.
are fully collectible.
(xxi) To the best of their knowledge, neither NOARK
nor AWP has nor will AWP L.L.C. or AWP, as applicable, at the
AWP Contribution Time have, any material liabilities or
obligations of any nature, whether absolute, accrued,
contingent or otherwise, and whether due or to become due
(including without limitation, any
27
<PAGE>
liability for taxes and interest, penalty or other charges
payable with respect to any such liability or obligation)
which are not disclosed in the Financial Statements, or
elsewhere in this Agreement or the Schedules to this
Agreement.
For purposes of this Section 12(g), all representations regarding AWP
shall be deemed made at the Closing and all such representations shall
be deemed to be applicable to AWP L.L.C. and made with respect to AWP
L.L.C. at the AWP Contribution Time.
(h) At the Closing SWN shall have good title to all of the
stock of AWP free and clear of all Liens, and at the AWP Contribution
Time, SWPL shall have good title to all of the ownership interests in
AWP L.L.C., or twenty-five percent (25%) of the stock of AWP, as
applicable, free and clear of all Liens. At the Closing with respect to
AWP, and at the AWP Contribution Time with respect to AWP L.L.C. or
AWP, as applicable, all of these ownership interests shall be owned by
SWN or SWPL, as applicable, free and clear of any security interests,
voting trusts, agreements, proxies, options or other restrictions. At
the Closing AWP will have and at the AWP Contribution Time, AWP or AWP
L.L.C., as applicable, will have, no subsidiaries, no interest in any
partnership or joint venture and does not hold shares of stock or other
ownership interest in any corporation, trust or other Person. At the
Closing with respect to AWP, and at the AWP Contribution Time with
respect to AWP L.L.C. or AWP, as applicable, there will be: (a) no
existing subscriptions, options, warrants, calls, commitments or rights
of any character to purchase or otherwise acquire any shares of capital
stock or other securities or interests of AWP and/or AWP L.L.C., as
applicable; and (b) no contracts, subscriptions, options, warrants,
calls, commitments or rights to purchase or otherwise acquire, any
securities or other interests that are convertible into or exchangeable
for shares of capital stock or other securities or interests of AWP
and/or AWP L.L.C., as applicable.
(i) At the Closing, SWPL shall have good title to all of the
assets to be contributed to OGG L.L.C. under Section 7(b)(i) and to
NOARK under Section 7(b)(ii) above, free and clear of all Liens.
(j) NGMC. NGMC has been terminated and all of the assets of
NGMC are now owned by NGSC.
(k) Brokers. They have not employed, directly or indirectly
for their benefit, any broker or finder or incurred any liability for
any financial advisory fees, brokerage fees, commissions or finders'
fees, and no broker or finder has acted directly or indirectly for them
in connection with this Agreement or the transactions contemplated
hereby.
(l) Full Disclosure. To the best of their knowledge, no
representation or warranty in this Section 12 (including the
information in the Schedules attached to this Agreement), contains any
untrue statement of a material fact or omits to state any material fact
which is
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necessary to make any of the representations and warranties made
herein, in light of the circumstances in which they are made, not
misleading.
(m) No Reliance. Except as to the representations of Enogex
and EAPC expressly set forth in Section 11 of this Agreement, SWN and
SWPL have not relied upon any oral or written statements,
representations, warranties which may have been made by or on behalf of
ENOGEX or EAPC or upon any written reports, financial or production
data, business plans, projections, forecasts, projections of feedstock
availability or evaluations, or any environmental reports, audits,
studies or assessments, or any other written materials, copies of which
may have been furnished to SWN or SWPL or as to which SWN or SWPL may
have been provided access in connection with the transactions
contemplated by this Agreement. TO THE EXTENT THAT SWN OR SWPL HAVE
BEEN FURNISHED COPIES OF OR BEEN PROVIDED ACCESS TO ANY OF THE
FOREGOING, SWN AND SWPL ACKNOWLEDGE THAT NEITHER ENOGEX NOR EAPC NOR
ANY OF THEIR AFFILIATES, OR ANY OF THEIR RESPECTIVE OFFICERS,
DIRECTORS, EMPLOYEES, REPRESENTATIVES AND AGENTS, HAS MADE, AND SWN AND
SWPL HEREBY EXPRESSLY DISCLAIM ANY REPRESENTATIONS OR WARRANTIES AS TO
THE ACCURACY OR COMPLETENESS OF SUCH INFORMATION, DATA OR MATERIALS
(WHETHER WRITTEN OR ORAL) WHICH MAY HAVE BEEN FURNISHED TO SWN AND SWPL
OR THEIR REPRESENTATIVES OR AGENTS BY OR ON BEHALF OF ENOGEX OR EAPC IN
CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY.
13. Expenses.
(a) Expenses of the Transaction. Except as otherwise provided
herein, each of the Parties shall bear their respective expenses, costs
and fees (including attorneys' and accountants' fees) in connection
with the transactions contemplated hereby, including the preparation,
execution and delivery of this Agreement and compliance herewith,
whether or not the transactions contemplated hereby shall be
consummated.
(b) Partnership Expenses. After the Closing, all of the costs
and expenses of NOARK, and the entities owned by NOARK, shall be
handled in accordance with the Amended and Restated Partnership
Agreement of NOARK attached as Exhibit "F," or as otherwise provided in
this Agreement.
14. Conditions to Closing.
(a) Each Party. The obligations of the Parties to consummate
the transactions contemplated hereby at the Closing shall be subject to
the fulfillment on or prior to the Closing Date of the condition that
the consummation of such transactions shall not have been restrained,
enjoined or otherwise prohibited by any order of any governmental
authority whether judicial or administrative.
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(b) SWN and SWPL. The obligations of SWN and SWPL to
consummate the actions contemplated hereby at the Closing shall be
subject to the fulfillment on or prior to the Closing Date of the
following conditions:
(i) The representations and warranties of Enogex and
EAPC contained herein will be accurate in all material
respects at and as of the Closing as though such
representations and warranties had been made at and as of such
Closing; all terms, covenants and conditions of this Agreement
to be complied with and performed by Enogex and EAPC at or
before the relevant Closing will have been duly complied with
and performed; and Enogex and EAPC will have delivered to SWN
and SWPL certificates in the form attached as Exhibit "M"
dated as of the Closing and signed by the President or any
Vice President thereof to the foregoing effect.
(ii) EAPC shall have acquired all of the Prudential
Interest as contemplated by Section 2(a) above.
(iii) EAPC shall have acquired all of the SEMCO
Interest as contemplated by Section 2(b) above.
(iv) EIT shall have entered into a definitive
agreement to acquire the pipeline assets of Ozark as
contemplated by Section 3 above.
(v) SEMCO Energy, Inc. and any of its appropriate
Affiliates shall have executed the Mutual Release and
Settlement Agreement between SWN, SWPL any of their
appropriate Affiliates and SEMCO Energy, Inc. and any of its
appropriate Affiliates in the form attached hereto as Exhibit
"D."
(vi) EAPC shall have executed the Amended and
Restated Partnership Agreement of NOARK in the form attached
hereto as Exhibit "F."
(vii) NOARK shall have entered into a new loan
agreement with Enogex and shall have used the proceeds of such
loan to pay a portion of the NOARK Debt as contemplated by
Section 9(c).
(viii) The consents required to be obtained from the
lenders of the NOARK Debt as contemplated by Section 9 shall
have been obtained.
SWN and SWPL may waive any condition specified in this Section 14(b) if
they execute a writing so stating at or prior to the Closing.
(c) Enogex and EAPC. The obligations of Enogex and EAPC to
consummate the actions contemplated hereby at the Closing shall be
subject to the fulfillment on or prior to the Closing Date of the
following conditions:
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(i) The representations and warranties of SWN and
SWPL contained herein will be accurate in all material
respects at and as of the Closing as though such
representations and warranties had been made at and as of such
Closing; all terms, covenants and conditions of this Agreement
to be complied with and performed by SWN and SWPL at or before
the relevant Closing will have been duly complied with and
performed; and SWN and SWPL will have delivered to Enogex and
EAPC certificates in the form attached as Exhibit "N" dated as
of the Closing and signed by the President or any Vice
President thereof to the foregoing effect.
(ii) EAPC shall have acquired all of the Prudential
Interest as contemplated by Section 2(a) above.
(iii) EAPC shall have acquired all of the SEMCO
Interest as contemplated by Section 2(b) above.
(iv) EIT shall have entered into a definitive
agreement to acquire the pipeline assets of Ozark as
contemplated by Section 3 above.
(v) SWPL shall have contributed all of the assets of
NGSC specified on Exhibit "G", free and clear of all Liens,
except for SWPL Permitted Liens.
(vi) The Mutual Release and Settlement Agreement
between SWN, SWPL, and any of their appropriate Affiliates and
SEMCO Energy, Inc. and any of its appropriate Affiliates in
the form attached as Exhibit "D" shall have been fully
executed.
(vii) SWPL shall have contributed to NOARK all of the
items described in Section 7(b)(ii) above free and clear of
all Liens.
(viii) SWPL shall have executed the Amended and
Restated Partnership Agreement of NOARK in the form attached
hereto as Exhibit "F."
(ix) NOARK shall have entered into a new loan
agreement with Enogex and shall have used the proceeds of such
loan to pay a portion of the NOARK Debt as contemplated by
Section 9(c).
(x) The consents required to be obtained from the
lenders of the NOARK Debt as contemplated by Section 9 shall
have been obtained.
(xi) SWPL shall continue to own all of the SWPL
Interest as contemplated by Section 2(c) above.
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Enogex and EAPC may waive any condition specified in this Section 14(c)
if it executes a writing so stating at or prior to the Closing.
15. Indemnification.
15.1 SWN and SWPL Indemnity.
(a) SWN and SWPL, from and after the Closing Date, shall
jointly and severally indemnify and hold Enogex and EAPC and their
Affiliates (other than NOARK and any NOARK Related Entity), and their
respective officers, directors, shareholders, employees, agents,
representatives, successors and assigns (collectively the "Enogex
Indemnified Parties") harmless from and against and in respect of, and
will reimburse the Enogex Indemnified Persons for any and all damage,
loss, cost, claims, demands, assessments, judgments, deficiencies or
liability (whether based on contract, tort, product liability, strict
liability or otherwise), including without limitation all reasonable
expenses (including interest, penalties, attorneys' and accountants'
fees and costs of investigation) net of any insurance proceeds received
by reason of such damage, loss, cost, claims, demands, assessments,
judgments, deficiencies as provided in Section 15.3 (collectively,
"Damages") incurred by any of the Enogex Indemnified Parties, directly
or indirectly, resulting from or in connection with any
misrepresentation, breach of warranty or nonfulfillment of any covenant
or agreement by or on the part of SWN and/or SWPL hereunder whether
prior to or subsequent to the Closing. Notwithstanding anything herein
to the contrary, for purposes of Section 15.1, the representations and
warranties in Section 12(g) shall be read, construed and enforced as if
there were no qualifications or exceptions therein as to knowledge or
matters disclosed in the schedules to the Agreement referenced therein.
(b) SWN and SWPL, from and after the Closing Date shall
jointly and severally indemnify and hold NOARK and any NOARK Related
Entity harmless from and against and in respect of and will reimburse
NOARK and any NOARK Related Entity for (i) 60% of any and all Damages
incurred by NOARK and/or any of the NOARK Related Entities resulting
from claims of Third Persons incurred by NOARK and/or any of the NOARK
Related Entities directly or indirectly resulting from or in connection
with the ownership, the assets or operations of NOARK which are
attributable to the period prior to the Closing, regardless of the date
actually incurred and (ii) any and all Damages resulting from claims of
Third Persons, SWN, SWPL, or their Affiliates (other than NOARK or any
NOARK Related Entity) incurred by NOARK and/or any of the NOARK Related
Entities directly or indirectly resulting from or in connection with
(x) AWP, AWP L.L.C. and/or their respective assets and operations which
are attributable to the period prior to the AWP Contribution Time
regardless of the date actually incurred and (y) the assets of NGSC
which are contributed to NOARK pursuant to Section 7(b), and the
operation thereof, which are attributable to the period prior to the
Closing, regardless of the date actually incurred.
(c) The Parties acknowledge and agree that the Enogex
Indemnified Parties shall
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not receive any double recovery of Damages under Section 15.1(a)and(b).
15.2 Enogex and EAPC Indemnity.
(a) Enogex and EAPC, from and after the Closing Date, shall
jointly and severally indemnify and hold SWN and SWPL and their
Affiliates (other than NOARK and any NOARK Related Entity), and their
respective officers, directors, shareholders, employees, agents,
representatives, successors and assigns (collectively the "SWN
Indemnified Parties") harmless from and against and in respect of, and
will reimburse the SWN Indemnified Parties for (a) any and all Damages
incurred by any of the SWN Indemnified Parties, directly or indirectly,
resulting from or in connection with any misrepresentation, breach of
warranty or nonfulfillment of any covenant or agreement by or on the
part of Enogex and/or EAPC hereunder whether prior to or subsequent to
the Closing. Notwithstanding anything herein to the contrary, for
purposes of Section 15.2, the representations and warranties in Section
11(g) and (h) shall be read, construed and enforced as if there were no
qualifications or exceptions therein as to knowledge or matters
disclosed in the Ozark Disclosure Schedule or Searcy Disclosure
Schedule.
(b) Enogex and EAPC, from and after the Closing Date shall
jointly and severally indemnify and hold NOARK and any NOARK Related
Entity harmless from and against and in respect of, and will reimburse
NOARK and any NOARK Related Entity for (i) 40% of any and all Damages
resulting from claims of Third Persons incurred by NOARK and/or any of
the NOARK Related Entities directly or indirectly resulting from or in
connection with the ownership, the assets or operations of NOARK which
are attributable to the period prior to the Closing, regardless of the
date actually incurred and (ii) any and all Damages resulting from
claims of Third Persons, Enogex, EAPC or their Affiliates (other than
NOARK or any NOARK Related Entity) incurred by NOARK and/or any of the
NOARK Related Entities directly or indirectly resulting from or in
connection with (y) the Searcy Gathering Assets which are to be
contributed to NOARK pursuant to Section 4 above, and the operation
thereof, which are attributable to the period prior to the Searcy
Contribution Time regardless of the date actually incurred and (z) the
pipeline assets of Ozark which are contributed to NOARK (as a result of
the contribution of EIT to NOARK as contemplated in Section 3), and the
operation thereof, which are attributable to the period prior to the
Contribution Time, regardless of the date actually incurred.
(c) The Parties acknowledge and agree that the SWN Indemnified
Parties shall not receive any double recovery of Damages under Section
15.2(a) and (b).
15.3 Reimbursement for Recoveries by Indemnified Party.
(a) In any case where an indemnified party recovers from third
parties all or any part of any amount paid to it by an indemnifying
party pursuant to this Section 15, such indemnified party shall
promptly pay over to the indemnifying party the amount so recovered
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(after deducting therefrom the full amount of the expenses incurred by
it in procuring such recovery and any additional amounts owed to the
indemnified party by the indemnifying party under this Agreement), but
not in excess of any amount previously so paid by the indemnifying
party.
(b) The indemnified party shall be obligated to file
diligently and in good faith any claim for Damages with any applicable
insurer prior to collecting an indemnification payment under this
Section 15. However, an indemnified party shall be entitled to collect
an indemnification payment under this Section 15 if such indemnified
party has not received reimbursement from an applicable insurer within
six months after it has given such insurer written notice of its claim.
In such event, the indemnified party shall assign to the indemnifying
party any and all rights against its insurers.
15.4 Third Person Claim. If a claim by a Person other than the
Parties is made against one or more of the Enogex Indemnified Parties
or the SWN Indemnified Parties (the "Indemnified Party"), and if the
Indemnified Party intends to seek indemnity with respect thereto under
this Section 15, the Indemnified Party shall promptly notify the Party
or Parties having an indemnification obligation with respect to such
claim (the "Indemnifying Party") of such claim. The Indemnifying Party
shall have 15 days after receipt of such notice to notify the
Indemnified Party of its agreement to undertake, conduct and control,
through counsel of its own choosing and at its own expense, the
settlement or defense thereof, and the Indemnified Party shall
cooperate with the Indemnifying Party in connection therewith;
provided, however, that (a) the Indemnifying Party shall permit the
Indemnified Party to participate in such settlement or defense through
counsel chosen by the Indemnified Party, provided that the fees and
expenses of such counsel shall be borne by the Indemnified Party, and
(b) the Indemnifying Party shall promptly assume and hold the
Indemnified Party harmless from and against the full amount of any
loss, damage or expense resulting therefrom. So long as the
Indemnifying Party is reasonably contesting any such claim in good
faith, the Indemnified Party shall not pay or settle any such claim, to
the extent such claim is subject to the indemnity provisions of this
Section 15. If the Indemnifying Party does not notify the Indemnified
Party within 15 days after the receipt of the Indemnified Party's
notice of a claim of indemnity hereunder that it elects to undertake
the defense thereof, the Indemnified Party shall have the right to take
over the defense of such claim and to contest, settle or compromise the
claim but shall not thereby waive any right to indemnity therefor
pursuant to this Agreement, including without limitation the right to
reimbursement for all fees, costs and expenses incurred by the
Indemnified Party (including attorneys' fees and costs of
investigation) in such defense and in contesting, settling or
compromising such claim. The Indemnifying Party shall not, except with
the consent of the Indemnified Party, enter into any settlement that
does not include as an unconditional term thereof the giving by the
Person or Persons asserting such claim an unconditional release to all
Indemnified Parties from all liability with respect to such claim or
consent to entry of any judgment.
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15.5 Survival. All representations, covenants, agreements and
warranties of the Parties or any authorized representative thereof
contained in this Agreement or in any certificate delivered in
connection herewith shall be and remain in full force and effect
notwithstanding any investigation made by or disclosure made to any
party hereto, whether before or after the date hereof and shall survive
the execution and delivery of this Agreement and the Closing; provided,
however, the representations and warranties contained in Sections 11
and 12 shall only survive for a period of three (3) years from the
Closing Date and any claim for breach of such representations and
warranties contained in Sections 11 and 12 must be asserted in writing
during such three (3) year survival period or shall be deemed waived,
except that the representations and warranties contained in Section
12(g)(xv) shall survive for the applicable statute of limitations for
the assessment or collection of any taxes.
15.6 Limitation on Liability for Breach of Representations and
Warranties Contained in Sections 11 and 12. Enogex and EAPC's maximum
aggregate liability to SWN and SWPL for breaches of representations and
warranties contained in Section 11 shall not exceed five million
dollars ($5,000,000). Similarly, SWN and SWPL's maximum aggregate
liability to Enogex and EAPC for breaches of representations and
warranties contained in Section 12 shall not exceed five million
dollars ($5,000,000).
16. Brokers. Regardless of whether any Closing shall occur, each Party
shall indemnify and hold harmless the other Parties from and against any and all
liability for any brokers' or finders' fees arising with respect to brokers or
finders retained or engaged by such Party in respect of the transactions
contemplated by this Agreement.
17. Notices. Any notice, request, instruction, correspondence or other
document to be given hereunder by any Party to the others (herein collectively
called "Notice") shall be in writing and delivered in person or by courier
service requiring acknowledgment of receipt of delivery or mailed by certified
mail, postage prepaid and return receipt requested, or by telecopier, as
follows:
If to SWN, addressed to:
Southwestern Energy Company
1083 Sain Street
P.O. Box 1408
Fayetteville, Arkansas 72702-1408
Attention: Executive Vice President - Finance & Corporate
Development
Facsimile No.: (501) 521-1147
If to SWPL, addressed to:
Southwestern Energy Pipeline Company
c/o Southwestern Energy Services Company
2200 MidContinent Tower
401 S. Boston Ave.
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Tulsa, Oklahoma 74103
Attention: Senior Vice President
Facsimile No.: (918) 584-4222
with a copy to SWN if notice is to SWPL only
If to Enogex, addressed to:
Enogex Inc.
600 Central Park Two
515 Central Park Drive
Oklahoma City, OK 73105
Attention: Roger Farrell
Facsimile No.: (405) 557-5205
with a copy to:
Enogex Inc.
600 Central Park Two
515 Central Park Drive
Oklahoma City, OK 73105
Attention: General Counsel
Facsimile No.: (405) 557-5205
If to EAPC, addressed to:
Enogex Arkansas Pipeline Corporation
600 Central Park Two
515 Central Park Drive
Oklahoma City, OK 73105
Attention: President
Facsimile No.: (405) 557-5205
with a copy to Enogex if notice is to EAPC only
Notice given by personal delivery or courier service shall be effective upon
actual receipt. Notice given by mail shall be effective five days after deposit
with the United States postal service when sent by first class mail, postage
prepaid. Notice given by telecopier shall be confirmed by appropriate answer
back and shall be effective upon actual receipt if received during the
recipient's normal business hours, or at the beginning of the recipient's next
business day after receipt if not received during the recipient's normal
business hours. All Notices by telecopier shall be confirmed promptly after
transmission in writing by certified mail or personal delivery. Any Party may
change any address to which Notice is to be given to it by giving Notice as
provided above of such change of address.
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18. Public Announcements. The parties agree that prior to making any
public announcement or statement with respect to the transaction contemplated by
this Agreement, the party desiring to make such public announcement or statement
shall consult with the other parties hereto and obtain prior written approval of
the other parties hereto of the text of a public announcement or statement to be
made solely by the party proposing to make such announcement. Nothing contained
in this Section shall be construed to require any party to obtain approval of
the other parties hereto to disclose information with respect to the transaction
contemplated by this Agreement to any state or federal governmental authority or
agency to the extent required by applicable law or by any applicable rules,
regulations or orders of any governmental authority or agency having
jurisdiction or necessary to comply with disclosure requirements of the New York
Stock Exchange, NASDAQ or any applicable securities laws.
19. Dispute Resolution
19.1 Invoking Procedure. In the event of a dispute between the Parties
arising out of or related to this Agreement , any Party may invoke the
procedures specified in this Section by giving written notice to the other
Parties. Such written notice will describe briefly the nature of the dispute and
shall identify an individual with authority to settle the dispute on behalf of
that Party. The Party receiving such notice shall have ten (10) days within
which to designate an individual with authority to settle the dispute on its
behalf and to give written notice to the other Parties of its designation (the
individuals so designated shall be referred to as the "Authorized Individuals").
In this regard, there shall be only one Authorized Individual for SWN and SWPL,
and only one Authorized Individual for Enogex and EAPC. Unless otherwise
notified, i) the Authorized Individual of SWN and SWPL shall be the President of
SWN, and ii) the Authorized Individual of Enogex and EAPC shall be the President
of Enogex.
19.2 Investigation. The Authorized Individuals shall make whatever
investigation each deems appropriate and promptly thereafter, but no later than
thirty (30) days from the date of the original notice invoking these procedures,
shall commence discussions concerning resolution of the dispute. If the dispute
has not been resolved within sixty (60) days from the date of the original
notice invoking these procedures, the Parties shall submit the matter to
Alternate Dispute Resolution (ADR) in accordance with the following procedure.
19.3 Neutral. The Parties shall have ten (10) days from the expiration
of the sixty (60) day period referred to in Section 19.2, or the agreement of
the Parties, to submit the matter to ADR, whichever occurs first, within which
to agree upon a mutually acceptable person not affiliated with any Party
("Neutral"). If no Neutral has been selected within that time period, the
Parties agree jointly to request the American Arbitration Association, or other
mutually agreed-upon organization, to supply within ten (10) days a list of at
least three (3) potential Neutrals with qualifications as specified by the
Parties in the joint request. Within seven (7) days of receipt of the list, the
Parties shall rank the proposed candidates independently, exchange rankings and
select as the Neutral the individual who received the highest combined ranking
who is available to serve.
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19.4 Schedule. In consultation with the Neutral, the Parties shall
designate a mutually convenient time and place for the ADR, and unless
circumstances require otherwise, such time shall be not later than forty-five
(45) days after the selection of the Neutral.
19.5 Discovery. In the event any of the Parties have substantial need
for information in the possession of any other Party or a need to take certain
limited depositions and/or production of principal documents in order to prepare
for the ADR, the Parties shall attempt in good faith to agree on a plan for the
expeditious exchange of such information. Should they fail to reach agreement,
any Party may request a meeting with the Neutral who shall assist them in
reaching an accommodation.
19.6 Written Submission. One week prior to the first scheduled session
of the ADR, each Party shall deliver to the Neutral and to the other Parties a
written summary of its views on the matter in dispute. The summary shall be no
longer than twenty (20) double-spaced pages unless the Parties agree otherwise.
19.7 Representatives. In the ADR, each Party shall be represented by
the Authorized Individual and by counsel. In addition, each Party may bring
additional persons as necessary to respond to questions or contribute
information as needed. The number of such additional persons to be allowed shall
be mutually agreed by the Parties with the assistance of the Neutral, if
necessary.
19.8 Structure. The Neutral is authorized to conduct joint and separate
meetings with the Parties and to help the Parties structure whatever form of
presentation of the matter in dispute is most likely to facilitate resolution.
Notwithstanding the form of the presentation, it is the intent of the Parties to
provide an opportunity for their Authorized Individuals, with or without the
assistance of counsel, and with the assistance of the Neutral, to negotiate a
resolution of the matters in dispute. In the event the Neutral holds separate
private caucuses with a Party, he or she shall keep confidential all information
learned in such private caucuses unless specifically authorized to make
disclosure of the information to the other Parties. There shall be no
stenographic, visual, or audio record made of the ADR.
19.9 Mandatory. The Parties agree to participate in the ADR to its
conclusion as designated by the Neutral and not to terminate negotiations
concerning resolution of the matters in dispute until at least two (2) weeks
thereafter. Each Party agrees not to commence arbitration or seek other remedies
prior to the conclusion of the two-week post-ADR negotiation period, provided
that any Party may commence arbitration on any date after which the commencement
of litigation could be barred by an applicable statute of limitations or in
order to request an injunction to prevent irreparable harm. In such event, the
Parties agree (except as prohibited by court order) to continue to participate
in the ADR to its conclusion.
19.10 Fees. The fees of, and authorized costs incurred by, the Neutral
shall be shared equally by the Parties. The Neutral shall be disqualified as a
witness, consultant, expert, or counsel for any Party with respect to the
matters in dispute and any related matters.
19.11 Later Proceedings. The ADR is a compromise negotiation for
purposes of the Federal Rules of Evidence and the Rules of Evidence of the State
of Oklahoma. The entire procedure is
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confidential. All conduct, statements, promises, offers, views, and opinions,
whether oral or written, made in the course of the ADR by any of the Parties,
their agents, employees, representatives, or other invitees to the ADR and by
the Neutral, who is the parties' joint agent for the purposes of these
compromise negotiations, are confidential and shall, in addition and where
appropriate, be deemed to be work product and privileged. Such conduct,
statements, promises, offers, views, and opinions shall not be discoverable or
admissible for any purposes, including impeachment, in any litigation or other
proceeding involving the Parties and shall not be disclosed to anyone not an
agent, employee, expert, witness, or representative for any of the Parties.
Evidence otherwise discoverable or admissible is not excluded from discovery or
admission as a result of its use in the ADR.
19.12 Arbitration.
(a) In the event the Parties are unable to resolve their
dispute in accordance with the foregoing provisions of this Section 19,
the dispute shall be submitted to final and binding arbitration. The
arbitration shall be administered by the American Arbitration
Association ("AAA") in accordance with, and in the following order of
priority: (i) the terms of these arbitration provisions; (ii) the
Commercial Arbitration Rules of the AAA; (iii) the Federal Arbitration
Act (Title 9 of the United States Code); (iv) the Oklahoma Uniform
Arbitration Act (15 O.S. ss. 801, et seq.); and (v) to the extent the
foregoing are inapplicable, unenforceable or invalid, the laws of the
State of Oklahoma. The validity and enforceability of these arbitration
provisions shall be determined in accordance with the same order of
priority. In the event of any inconsistency between these arbitration
provisions and such rules and statutes, these arbitration provisions
shall control. Judgment upon any award rendered hereunder shall be
entered in any court having jurisdiction thereof, and the parties
consent to the jurisdiction of any state or federal court in Oklahoma.
Commencement of and demand for arbitration shall be made by written
notice by the initiating party (claimant) to the other party
(respondent) which contains a statement of the nature of the dispute,
the amount involved and the relief or remedy sought ("Notice").
(b) The arbitration shall be conducted by a panel of three (3)
arbitrators (the "Arbitration Panel"). Enogex and EAPC on the one hand
and SWN and SWPL on the other, will each nominate one (1) arbitrator,
who is experienced and knowledgeable in the areas involved in the
dispute, within ten (10) working days of their receipt of the Notice
that arbitration has been demanded and commenced, and each will notify
the other party of the name of its selected arbitrator within that same
time period. If either side refuses to name an arbitrator, application
will be made to the Chief Judge of the United States District Court for
the Northern District of Oklahoma requesting that the Chief Judge
appoint an arbitrator. If the Chief Judge declines to name an
arbitrator, application will be made to the AAA. The two arbitrators
thus selected will confer within ten (10) working days of their final
selection and agree upon a third arbitrator. If the two arbitrators are
unable to agree on a third arbitrator within sixty (60) working days of
their first contact, the nomination of the third arbitrator will follow
the same procedure as the nomination of a party arbitrator for a party
refusing to make a selection. AAA Rules regarding the selection,
qualification, and challenge of arbitrator shall only apply to the
second or third arbitrators if those arbitrators
39
<PAGE>
are selected by the AAA. No member of the Arbitration Panel may be
involved in the controversy, be or have been an officer, director,
representative, employee or agent of or for either party. The third
arbitrator shall act as Chairman of the Arbitration Panel.
(c) The costs and fees of the arbitrators selected by the
parties shall be borne by the party selecting such arbitrator, unless
otherwise awarded by the Arbitration Panel. The costs and fees
attributable to the third arbitrator shall be shared equally by the
parties, unless otherwise awarded by the Arbitration Panel.
(d) The Arbitration Panel may engage engineers, accountants or
other consultants that the Arbitration Panel deems necessary to render
a decision in the Arbitration Proceeding. All fees of any such
consultants shall be borne equally by the parties, unless otherwise
awarded by the Arbitration Panel.
(e) The arbitration will be governed by the Federal
Arbitration Act, 9 U.S.C. ss.ss. 9 et seq. and the Oklahoma Uniform
Arbitration Act, 15 Okla. Stat. ss.ss. 801 et seq. The arbitrators will
establish a schedule that will result in a final arbitration award to
be rendered in written form not later than 180 days following the
appointment of the third arbitrator. The place of the arbitration shall
be Tulsa, Oklahoma.
(f) The parties agree that pre-arbitration hearing discovery
is necessary. Within twenty (20) working days after the appointment of
the third arbitrator, the parties agree to exchange lists of the
witnesses and exhibits each then plans to call and use in the
Arbitration Hearing. Within twenty (20) working days after the exchange
of the witness and exhibit lists, the parties may request additional
discovery, if any is necessary, from the other party. The parties agree
to respond to any such additional request for documents from the other
party within thirty (30) days after receiving such request, and each
agrees to attempt in good faith to schedule the depositions of
witnesses requested by the other side by agreement. If the parties are
unable to agree on any aspect of discovery requested, such discovery
issue shall be presented to and resolved by the Arbitration Panel.
(g) Any dispute relating to or arising under this arbitration
provision, including interpretation thereof, shall be solely and
finally resolved by submission to the Arbitration Panel.
(h) A written decision by two (2) of the arbitrators will be
final and binding on the parties. An arbitration award entered herein
can be confirmed by any party in the United States District Courts for
the Northern or Western Districts of Oklahoma or the Western District
of Arkansas or any state district courts for the States of Oklahoma and
Arkansas, and a judgment may be entered on the arbitration award by the
same court.
(i) Punitive damages may not be awarded by the Arbitration
Panel. The Arbitration Panel shall have the power to award recovery to
the prevailing party of all or part of its costs, expenses and
attorneys' fees incurred in conjunction with such Arbitration
40
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Proceeding.
(j) The parties, their Affiliates, employees, contractors,
attorneys and auditors shall keep the substance of these final and
binding arbitration proceedings confidential to the extent the same is
permissible, consistent with the responsibilities of the attorneys
under the pertinent Codes of Professional Responsibility or obligations
which may reasonably require disclosure to financial institutions,
consultants for evaluation purposes or as may be ordered by the federal
or state government or a court of competent jurisdiction. Under no
circumstances shall any documents memorializing the substance of any
aspect of these proceedings be disclosed or released to the newspaper
or other media absent the mutual agreement of the parties. The parties
will use all reasonable efforts to obtain protective orders before
disclosing any terms of these proceedings to any federal or state
government or a court of competent jurisdiction.
(k) Except for the internal costs of each party, all costs,
fees and expenses of any portion of this dispute resolution process
shall be shared equally by the parties, unless otherwise specified
herein.
20. Governing Law. The provisions of this Agreement and, unless
specifically otherwise provided in the document delivered pursuant hereto, the
documents delivered pursuant hereto shall be governed by and construed and
enforced in accordance with the laws of the State of Oklahoma, excluding any
conflicts-of-law rule or principle that might refer same to the laws of another
jurisdiction.
21. Amendments and Waivers. No supplement, modification or waiver of
this Agreement shall be binding unless executed in writing by the Party to be
bound thereby. The failure of a Party to exercise any right or remedy shall not
be deemed or constitute a waiver of such right or remedy in the future. No
waiver of any of the provisions of this Agreement shall be deemed or shall
constitute a waiver of any other provision hereof, nor shall any such waiver
constitute a continuing waiver unless otherwise expressly provided.
22. Binding Effect; Non-Assignability and Alienation of Benefits. This
Agreement shall be binding upon and inure to the benefit of the Parties and
their respective permitted successors and assigns; but neither this Agreement
nor any of the rights, benefits or obligations hereunder shall be assigned, by
operation of law or otherwise, by any Party without the prior written consent of
the others. Nothing in this Agreement, express or implied, is intended to confer
upon any Person other than the Parties and their respective permitted successors
and assigns, any rights, benefits or obligations hereunder.
23. Severability. If one or more of the provisions contained in this
Agreement or in any other document delivered pursuant hereto shall, for any
reason, be held to be invalid, illegal or unenforceable in any respect, such
invalidity, illegality or unenforceability shall not affect any other provisions
of this Agreement or any other such document.
41
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24. Headings and Exhibits. The headings of the several Sections herein
are inserted for convenience of reference only and are not intended to be a part
or to affect the meaning or interpretation of this Agreement. The Exhibits and
Schedules referred to herein are attached hereto and incorporated herein by this
reference.
25. Construction. This Agreement was drafted jointly by the Parties,
and no presumption shall operate in favor of or against any Party as a result of
any responsibility that any Party may have had for drafting this Agreement or
any part thereof.
26. Multiple Counterparts. This Agreement may be executed in one or
more counterparts, each of which shall be deemed an original, but all of which
together shall constitute one and the same instrument.
IN WITNESS WHEREOF, SWPL, SWN, EAPC and Enogex have caused this
Agreement to be signed by their respective officers thereunto duly authorized,
all as of the date first above written.
Southwestern Energy Pipeline Company
By: /s/ DEBBIE J. BRANCH
------------------------------
Name: Debbie J. Branch
Title: Senior Vice President
Southwestern Energy Company
By: /s/ STANLEY D. GREEN
------------------------------
Name: Stanley D. Green
Title: Executive Vice President -
Finance & Corporate Development
Enogex Arkansas Pipeline Corporation
By: /s/ ROGER A FARRELL
------------------------------
Name: Roger A. Farrell
Title: Vice President
42
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Enogex Inc.
By: /s/ ROGER A. FARRELL
-----------------------------
Name: Roger A. Farrell
Title: Executive Vice President
43
AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
NOARK PIPELINE SYSTEM, LIMITED PARTNERSHIP
JANUARY 12, 1998
<PAGE>
<TABLE>
<CAPTION>
Table of Contents
<S> <C>
AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP
OF NOARK PIPELINE SYSTEM, LIMITED PARTNERSHIP............................................................1
ARTICLE I DEFINITIONS.............................................................................................2
1.1 Definitions.....................................................................................2
1.2 Other Terms.....................................................................................8
ARTICLE II FORMATION OF LIMITED PARTNERSHIP.......................................................................9
2.1 Formation.......................................................................................9
2.2 Name............................................................................................9
2.3 Offices and Registered Agent....................................................................9
2.4 Term of Partnership.............................................................................9
2.5 Purpose.........................................................................................9
2.6 Representations and Warranties Concerning Partnership..........................................10
ARTICLE III MANAGEMENT OF THE PARTNERSHIP........................................................................10
3.1 Management Committee...........................................................................10
3.2 Composition of Management Committee............................................................10
3.3 Meetings of Management Committee...............................................................10
3.4 Partners Meetings..............................................................................11
3.5 Restrictions on Authority of the Management Committee..........................................12
3.6 Project Leader.................................................................................15
3.7 Delegation.....................................................................................18
3.8 Officers.......................................................................................19
3.9 Claims.........................................................................................19
3.10 Disputed Charges...............................................................................19
ARTICLE IV FINANCING OF THE PARTNERSHIP..........................................................................20
4.1 Existing Capital Accounts Balances.............................................................20
4.2 Capital Contributions..........................................................................20
4.3 Failure to Contribute..........................................................................21
4.4 Capital Accounts...............................................................................22
4.5 Loans by Partners..............................................................................22
4.6 Interest.......................................................................................22
4.7 Time for Return of Contributions...............................................................22
4.8 Limited Liability of the Limited Partners......................................................22
4.9 Benefits of Agreement..........................................................................22
ARTICLE V CAPITAL AND INCOME ALLOCATIONS AND DISTRIBUTIONS.......................................................22
5.1 Allocations Controlling for Capital Account Purpose............................................22
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5.2 General Allocation of Profits and Losses.......................................................23
5.3 Special Interest Expense.......................................................................23
5.4 Preferential Allocations.......................................................................23
5.5 Special Profits Allocations....................................................................25
5.6 Other Allocation Rules.........................................................................26
5.7 Cash Distributions.............................................................................26
5.8 Amounts Withheld...............................................................................27
5.9 Reimbursements.................................................................................27
ARTICLE VI RELATIONS OF THE PARTNERS.............................................................................27
6.1 Restricted Transactions........................................................................27
6.2 Exculpation from Liability.....................................................................28
6.3 Indemnification................................................................................29
6.4 Title to Partnership Assets....................................................................30
ARTICLE VII ASSIGNABILITY OF PARTNERS' INTERESTS.................................................................31
7.1 Restrictions on Transfer of Partner's Interest.................................................31
7.2 Right of First Refusal.........................................................................31
7.3 Opinion of Counsel.............................................................................31
7.4 Substituted Partner............................................................................32
7.5 Recognition of Transferee as Partner...........................................................32
7.6 Binding Effect.................................................................................33
7.7 Permitted Transfers of Partnership Interests...................................................33
7.8 Succession to Capital Account..................................................................33
ARTICLE VIII WITHDRAWAL AND REMOVAL; ADMISSION OF SUCCESSOR AND
ADDITIONAL GENERAL PARTNERS.............................................................................33
8.1 Voluntary Withdrawal...........................................................................33
8.2 Other Withdrawal Events........................................................................33
8.3 Removal of a Partner...........................................................................34
8.4 Liability of a Withdrawn General Partner.......................................................34
8.5 Additional or Successor Partners...............................................................34
8.6 Continuation of Partnership....................................................................34
8.7 Automatic Suspension of the Vote and Right to Participate
in Management of Partnership Affairs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34
ARTICLE IX DISSOLUTION AND LIQUIDATION...........................................................................35
9.1 Dissolution....................................................................................35
9.2 Liquidation....................................................................................35
ARTICLE X ALLOCATIONS AND DISTRIBUTIONS ON LIQUIDATION...........................................................35
10.1 Liquidation and Termination....................................................................35
10.2 Capital Account Deficits.......................................................................36
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10.3 Special Distributions..........................................................................36
10.4 Deemed Distribution and Recontribution.........................................................37
ARTICLE XI CERTIFICATES AND OTHER DOCUMENTS......................................................................37
11.1 Project Leader as Attorney for Partners........................................................37
11.2 Making and Filing of Certificate...............................................................38
11.3 Cancellation of Certificates Evidencing Partnership Interests..................................39
ARTICLE XII BOOKS OF ACCOUNT, FINANCIAL
STATEMENTS AND FISCAL MATTERS...........................................................................39
12.1 Books of Account...............................................................................39
12.2 Reports and Financial Statements...............................................................39
12.3 Tax Returns and Other Reports..................................................................40
12.4 Fiscal Year....................................................................................40
12.5 Bank Accounts, Funds and Assets................................................................40
12.6 Tax Elections..................................................................................40
12.7 Other Partnership Records......................................................................41
12.8 Survival of Tax Provision......................................................................42
12.9 Deposit of Funds . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
ARTICLE XIII DISPUTE RESOLUTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .42
13.1 Invoking Procedure.............................................................................42
13.2 Stalemate Defined..............................................................................43
13.3 Investigation..................................................................................43
13.4 Neutral........................................................................................43
13.5 Schedule.......................................................................................44
13.6 Discovery......................................................................................44
13.7 Written Submission.............................................................................44
13.8 Representatives................................................................................44
13.9 Structure......................................................................................44
13.10 Mandatory......................................................................................44
13.11 Fees...........................................................................................45
13.12 Later Proceedings..............................................................................45
13.13 Dispute Resolution.............................................................................45
ARTICLE XIV LIMITATION OF AUTHORITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .47
ARTICLE XV LIMITATION OF LIABILITIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .47
ARTICLE XVI MISCELLANEOUS........................................................................................48
16.1 Notices........................................................................................48
16.2 Captions and Pronouns..........................................................................49
16.3 Binding Effect.................................................................................49
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16.4 Amendment of the Agreement.....................................................................49
16.5 Governing Law..................................................................................49
16.6 Counterparts and Execution.....................................................................50
16.7 Severability...................................................................................50
16.8 Waiver.........................................................................................50
16.9 Attorneys' Fees................................................................................50
16.10 Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50
I. Exhibits: Ex. No.
- Description of Interconnection, Integration and Expansion of Pipeline
Facilities of NOARK and Ozark A
- Accounting Procedures B
II. Schedules: Sch. No.
- Initial Capital Account Balances 4.1
- Special Revenue Allocation Base Amounts 5.4(a)
- Supply Receipt Points on NOARK Pipeline System 5.4(b)
- Special Revenue Allocation Examples (5) 5.4(d)
- Insurance 6.3(d)
</TABLE>
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THE SECURITIES REPRESENTED BY THIS AGREEMENT OF LIMITED PARTNERSHIP HAVE BEEN
ACQUIRED FOR INVESTMENT AND HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF
1933, AS AMENDED, OR THE SECURITIES LAWS OF ANY STATE. SUCH SECURITIES MAY NOT
BE SOLD, PLEDGED, HYPOTHECATED OR OTHERWISE TRANSFERRED AT ANY TIME WHATSOEVER,
EXCEPT UPON REGISTRATION OR UPON DELIVERY TO THE PARTNERSHIP OF AN OPINION OF
COUNSEL SATISFACTORY TO THE GENERAL PARTNERS THAT REGISTRATION IS NOT REQUIRED
FOR SUCH TRANSFER OR THE SUBMISSION TO THE GENERAL PARTNERS OF THE PARTNERSHIP
OF SUCH OTHER EVIDENCE AS MAY BE SATISFACTORY TO THE GENERAL PARTNERS TO THE
EFFECT THAT ANY SUCH TRANSFER SHALL NOT BE IN VIOLATION OF THE SECURITIES ACT OF
1933, AS AMENDED, APPLICABLE STATE SECURITIES LAWS OR ANY RULE OR REGULATION
PROMULGATED UNDER SUCH ACT OR LAWS.
AMENDED AND RESTATED
AGREEMENT OF LIMITED PARTNERSHIP
OF
NOARK PIPELINE SYSTEM, LIMITED PARTNERSHIP
This Amended and Restated Agreement of Limited Partnership
("Agreement") is made as of January 12, 1998, by and among the Partners (as
defined below).
RECITALS
A. NOARK Pipeline System, Limited Partnership, an Arkansas limited
partnership (the "Partnership") was formed and organized under the terms of that
certain Limited Partnership Agreement dated as of October 10, 1991 (the
"Original Agreement").
B. The Original Agreement was amended by that certain Amendment No. 1
to the Original Agreement, dated February 24, 1993.
C. SWPL and EAPC and their Affiliates have entered into an Omnibus
Project Agreement dated January 12, 1998 which contemplates, among other things,
this amendment and restatement of the Original Agreement, as amended, in its
entirety.
D. The Parties intend that this Agreement replaces and supersedes the
Original Agreement, as amended, in its entirety.
In consideration of the mutual promises made herein, and for other good
and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the Partners hereby agree as follows:
1
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ARTICLE I
DEFINITIONS
1.1 Definitions. The following terms used in this Agreement shall
(unless otherwise expressly provided herein or unless the context otherwise
requires) have the following respective meanings:
"Act" means the Arkansas Revised Limited Partnership Act of 1991, Ark.
Code Ann. ss. 4-43-101 et seq., as it may be amended from time to time, and any
successor act.
"Affiliate" or "Affiliates" means with respect to any Person, except as
otherwise provided herein: (i) any person or entity directly or indirectly
controlling, controlled or under common control with such Person; (ii) any
person or entity directly or indirectly owning or controlling ten percent (10%)
or more of the outstanding voting securities or ownership interests of such
Person; (iii) any person or entity ten percent (10%) or more of whose
outstanding voting securities or ownership interests are directly or indirectly
owned or controlled by such Person; (iv) any officer, director, partner, manager
or member of a Person; and (v) any company for which a Person acts as an
officer, director, partner, manager or member.
"Budget" means the annual budget of anticipated capital and operating
costs of the Partnership described in Section 3.6(g) hereof.
"Capital Account" means, with respect to a Partner, the Capital Account
determined and maintained for such Partner in accordance with the following
provisions:
(a) The initial balances of each Capital Account shall be the amounts
set forth in Schedule 4.1.
(b) To each Partner's Capital Account there shall be credited such
Partner's future Capital Contributions when made, such Partner's distributive
share of Profits, allocated pursuant to Section 5.2 hereof, any items in the
nature of income or gain that are specially or curatively allocated pursuant to
Sections 5.3 through 5.5 hereof, and the amount of any Partnership liabilities
assumed by such Partner or which are secured by any asset of the Partnership
distributed to such Partner.
(c) To each Partner's Capital Account there shall be debited the amount
of cash and the Gross Asset Value of any Partnership asset distributed to such
Partner pursuant to any provision of this Agreement, such Partner's distributive
share of Losses allocated pursuant to Section 5.2 hereof, any items in the
nature of deductions or losses that are specially or curatively allocated
pursuant to Sections 5.3 through 5.5 hereof, and the amount of any liabilities
of such Partner assumed by the Partnership or which are secured by any property
contributed by such Partner to the Partnership.
2
<PAGE>
(d) In the event all or a portion of a Partnership Interest is
transferred in accordance with the terms of this Agreement, the transferee shall
succeed to the Capital Account of the transferor to the extent it relates to the
transferred Partnership Interest.
(e) In determining the amount of any liability for purposes of this
definition of Capital Accounts, there shall be taken into account Code ss.
752(c) and any other applicable provisions of the Code and Regulations.
The foregoing provisions and the other provisions of this Agreement
relating to the maintenance of Capital Accounts are intended to have a
"substantial economic effect" and to reflect the Partners' economic interests in
the Partnership for tax purposes. However, in the event that changes in the
allocations are required by the Service or any other taxing authority or other
curative allocations and adjustments to the Capital Accounts may be required for
income tax purposes to comply with Treas. Reg. ss. 1.704-1(b) or otherwise, the
Partners agree that such allocations and adjustments will not be made to the
Capital Accounts and the Capital Accounts as herein calculated will control upon
liquidation.
"Capital Contributions" means, with respect to any Partner, the amount
of money and the initial Gross Asset Value of any property (other than money)
contributed in the future to the Partnership with respect to the Partnership
Interest held by such Partner. Loans to the Partnership shall not be included in
the Capital Account of any Partner. The principal amount of a promissory note
which is not readily traded on an established securities market and which is
contributed to the Partnership by the maker of the note shall not be included in
the Capital Account of any Partner until the Partnership makes a taxable
disposition of the note or until (and to the extent) principal payments are made
on the note, all in accordance with Treas. Reg. ss. 1.704-1 (b)(2)(iv)(d)(2)
(relating to the contributions to a partnership of promissory notes).
"Certificate of Limited Partnership" means the Certificate of Limited
Partnership of the Partnership filed with the Secretary of the State of
Arkansas, as it may be amended and/or restated from time to time.
"Code" means the Internal Revenue Code of 1986, as amended from time to
time (or any corresponding provisions of succeeding law).
"Depreciation" means, for each fiscal year or other period, an amount
equal to the depreciation, amortization, or other cost recovery deduction
allowable with respect to an asset for such year or other period, except that if
the Gross Asset Value of an asset differs from its adjusted basis for Federal
income tax purposes at the beginning of such year or other period, Depreciation
shall be an amount which bears the same ratio to such beginning Gross Asset
Value as the Federal income tax depreciation, amortization, or other cost
recovery deduction for such year or other period bears to such beginning
adjusted tax basis; provided, however, that if the Federal income tax
depreciation, amortization, or other cost recovery deduction for such year is
zero, Depreciation shall
3
<PAGE>
be determined with reference to such beginning Gross Asset Value using any
reasonable method selected by the Management Committee.
"EAPC" means Enogex Arkansas Pipeline Corporation, an Oklahoma
corporation.
"Existing Loans" means the NOARK Debt, and any subsequent loans to the
Partnership replacing the then existing principal balance of the NOARK Debt, or
the then existing principal balance of such subsequent loans, as applicable.
"Expansion" means an expansion of the pipeline facilities included
within the System by looping, adding compression, extending the mainline, or by
constructing or purchasing laterals or gathering facilities linking such
pipeline facilities to a Partner's or a third party's facilities.
"General Partner" or "General Partners" means EAPC and SWPL, and any
additional Person admitted as a general partner of the Partnership, but does not
include any Person who has ceased to be a general partner of the Partnership.
"Gross Asset Value" means, with respect to any asset, the asset's
adjusted basis for Federal income tax purposes, except as follows:
(a) The Gross Asset Value of the Partnership's assets as of the date of
this Agreement shall be consistent with the initial balances of the Capital
Accounts as set forth in Schedule 4.1.
(b) The initial Gross Asset Value of any asset contributed by a Partner
to the Partnership shall be the gross fair market value of such asset, as
determined by agreement between the contributing Partner and the other Partners;
(c) The Gross Asset Values of all Partnership assets shall be adjusted
to equal their respective gross fair market values, as determined by a
SuperMajority in Interest of the Partners as of the following times: (i) the
acquisition of an additional interest in the Partnership by a new or existing
Partner in exchange for more than a de minimis Capital Contribution; (ii) the
distribution by the Partnership to a Partner of more than a de minimis amount of
Property as consideration for an interest in the Partnership; and (iii) the
liquidation of the Partnership within the meaning of Treas. Reg. ss.
1.704-1(b)(2)(ii)(g) (relating to when a liquidation of a partnership occurs);
provided, however, that adjustments pursuant to clauses (i) and (ii) above shall
be made only if a SuperMajority in Interest of the Partners determines that such
adjustments are necessary or appropriate to reflect the relative economic
interests of the Partners in the Partnership;
(d) The Gross Asset Value of any Partnership asset distributed to any
Partner shall be the gross fair market value of such asset on the date of
distribution as determined by the Partners (or by an independent appraiser if
the Partners are unable to agree upon a value); and
4
<PAGE>
(e) The Gross Asset Values of Partnership assets shall be increased or
decreased to reflect any adjustments to the adjusted basis of such assets
pursuant to Code ss. 734(b) or Code ss. 743(b), but only to the extent that such
adjustments are taken into account in determining Capital Accounts pursuant to
Treas. Reg. ss. 1.704-1(b)(2)(iv)(m) (relating to Code ss. 754 elections) and
the definition of Capital Account hereof.
"Indemnitee" shall mean (i) any Partner or any former Partner, (ii) any
Project Leader or former Project Leader, (iii) the Management Committee or any
member or former member of the Management Committee, (iv) any Person who is or
was a NOARK Related Entity, (v) any Person who is or was an Affiliate of a
Partner or a former Partner who is or was performing or providing services on
behalf of the Partnership (including any NOARK Related Entity), (vi) any Person
who is or was an officer, director, employee, partner, agent or trustee of the
Partner, the Partnership (including any NOARK Related Entity), any former
Partner, or any such Affiliate, or (vii) any Person who is or was serving at the
request of a Partner, any former Partner, or any such Affiliate, as a director,
officer, employee, partner, agent, attorney or trustee of such Partner, former
Partner or Affiliate.
"Inservice Expansion Date" means the date on which the interconnection,
integration and expansion of the pipeline facilities of the Partnership and
Ozark (as more fully described on Exhibit A) are completed and commence full
time operations.
"Limited Partner" or "Limited Partners" means EAPC with respect to its
Partnership Interest as a Limited Partner and its successor, and any other
person or entity admitted as a Limited Partner of the Partnership pursuant to
this Agreement, but does not include any Person who has ceased to be a Limited
Partner.
"Liquidator" means the Person in charge of the liquidation of the
Partnership's assets which shall be the Management Committee unless a
SuperMajority in Interest of Partners designates another Person as Liquidator.
"Major Decision" shall have the meaning set forth in Section 3.5 of
this Agreement.
"Management Committee" means the Management Committee described in
Article III of this Agreement.
"Management Committee Approval" shall have the meaning set forth in
Section 3.3 of this Agreement.
"NOARK Debt" means (a) the debt incurred by NOARK pursuant to the terms
of that certain Credit Agreement and related documents dated as of February 26,
1993 among NOARK, the lenders and The First National Bank of Chicago, as Agent,
as amended by the First Amendment to NOARK Pipeline System, Limited Partnership
Credit Agreement dated February 1, 1994 and (b) the debt incurred by NOARK
pursuant to the terms of that certain Construction Loan and Note Purchase
5
<PAGE>
Agreement and related documents dated as of October 10, 1991 and as amended by
Amendment No. 1 and Amendment No. 2 to the Construction Loan and Note Purchase
Agreement dated as of January 29, 1993 and February 24, 1993, respectively,
between NOARK and The Prudential Insurance Company of America.
"NOARK Related Entity" means any Person which is wholly owned by the
Partnership.
"Omnibus Agreement" means that certain Omnibus Project Agreement dated
as of January 12, 1998, by and among EAPC, SWPL, Southwestern Energy Company and
Enogex Inc.
"Ozark" means Ozark Pipeline, Inc., a Delaware corporation.
"Ozark Acquisition" means the transaction in which Enogex Interstate
Transmission, L.L.C. will acquire all of the pipeline assets of Ozark or all of
the issued and outstanding capital stock of Ozark.
"Partners" or "Partner" means the General Partners and the Limited
Partner, or any of them individually.
"Partnership" means NOARK Pipeline System, Limited Partnership, an
Arkansas limited partnership.
"Partnership Agreement" or "Agreement" means this Amended and Restated
Agreement of Limited Partnership.
"Partnership Interest" means that interest of a Partner in the
Partnership, as described in this Agreement.
"Partnership Percentage" means the percentage of each Partner in the
Partnership as the same may change from time to time in accordance with the
terms of this Agreement. As of the date of this Agreement, the Partnership
Percentage of each Partner is as set forth below:
SWPL 60% (entirely as a General Partner)
EAPC 40% (39% as a General Partner and 1% as a Limited Partner)
At such time as the Ozark Acquisition is consummated and all of the ownership
interests of Enogex Interstate Transmission, L.L.C. are contributed to the
Partnership as provided for in Section 3 of the Omnibus Agreement, the
Partnership Percentage of each Partner shall be changed to the following:
SWPL 32% (entirely as a General Partner)
EAPC 68% (67% as a General Partner and 1% as a Limited Partner)
6
<PAGE>
On the Inservice Expansion Date, the Partnership Percentage of each
Partner shall be changed to the following:
SWPL 25% (entirely as a General Partner)
EAPC 75% (74% as a General Partner and 1% as Limited Partner)
"Person" means any individual, corporation, limited liability company,
limited or general partnership, joint venture, association, joint stock company,
trust, unincorporated organization or other entity.
"Profits" and "Losses" means, for each fiscal year or other period, an
amount equal to the Partnership's taxable income or loss for such year or period
determined in accordance with Code ss. 703(a) (for this purpose, all items of
income, gain, loss, or deduction required to be stated separately pursuant to
Code ss. 703(a)(1) shall be included in taxable income or loss), with the
following adjustments:
(a) Any income of the Partnership that is exempt from Federal income
tax and not otherwise taken into account in computing Profits or Losses pursuant
to this definition of Profits and Losses shall be added to such taxable income
or loss;
(b) Any expenditures of the Partnership described in Code ss.
705(a)(2)(B) or treated as Code ss. 705(a)(2)(B) expenditures pursuant to Treas.
Reg. ss. 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing
Profits or Losses pursuant to this definition of Profits and Losses, shall be
subtracted from such taxable income or loss;
(c) In the event the Gross Asset Value of any Partnership asset is
adjusted as required by the terms of subsections (c), (d) or (e) of the
definition of Gross Asset Value hereof, the amount of such adjustment shall be
taken into account as gain or loss from the disposition of such asset for
purposes of computing Profits or Losses;
(d) Gain or loss resulting from any disposition of Partnership assets
with respect to which gain or loss is recognized for Federal income tax purposes
shall be computed by reference to the Gross Asset Value of the property disposed
of, notwithstanding that the adjusted tax basis of such property differs from
its Gross Asset Value; and
(e) In lieu of the depreciation, amortization, and other cost recovery
deductions taken into account in computing such taxable income or loss, there
shall be taken into account Depreciation for such fiscal year or other period in
accordance with the definition of Depreciation herein.
(f) Any items of gross income specially allocated pursuant to Section
5.4 or interest expense allocated pursuant to Section 5.3 shall not be
considered when calculating "Profits" or "Losses" because such items are
specially allocated.
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"Project Leader" means the person designated as Project Leader in
accordance with Section 3.6 hereof.
"Proposing Partner" shall have the meaning set forth in Section 4.2(b)
of this Agreement.
"SWPL" means Southwestern Energy Pipeline Company, an Arkansas
corporation and its permitted successors and assigns.
"Service" means the Internal Revenue Service of the United States of
America.
"Substituted Partner" shall refer to a Transferee of a Partner's
Partnership Interest who is admitted to the Partnership as a Partner in
accordance with the provisions of Section 7.4 of this Agreement.
"SuperMajority in Interest" means such of the Partners as have, at the
time of determination, eighty percent (80%) or more of the Partnership
Percentages of all Partners.
"System" shall mean the pipeline system and related equipment and
property owned, directly or indirectly, by the Partnership (including any NOARK
Related Entity) on the date hereof together with the pipeline assets and related
equipment and property to be contributed to the Partnership under the terms of
the Omnibus Agreement (whether directly or indirectly through contributions of
ownership interests), and all pipeline facilities and related equipment and
property hereafter acquired directly or indirectly, by the Partnership
(including any NOARK Related Entity), all as same may be modified or expanded
pursuant to the provisions of this Agreement.
"Transfer" means, as a noun, any voluntary or involuntary transfer,
assignment, sale, pledge, gift, hypothecation or other disposition and, as a
verb, voluntarily or involuntarily to transfer, assign, sell, pledge, gift,
hypothecate or otherwise dispose of.
"Transferee" shall have the meaning set forth in Section 7.1 hereof.
"Transferor" shall have the meaning set forth in Section 7.1 hereof.
"Treasury Regulations" or "Treas. Reg." means the income tax
regulations, including proposed and temporary regulations, promulgated under the
Code, as such regulations may be amended from time to time (including
corresponding provisions of succeeding regulations).
1.2 Other Terms. Other terms may be defined elsewhere in the text
of this Agreement and shall have the meaning indicated therein.
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ARTICLE II
FORMATION OF LIMITED PARTNERSHIP
2.1 Formation. The Partnership has been formed pursuant to the Act, and
shall be governed by the Act and the terms and conditions set forth herein.
2.2 Name. The name of the Partnership shall be, and the business of the
Partnership shall be conducted under the name of, NOARK Pipeline System, Limited
Partnership. The Partnership's business may be conducted under any other name or
names deemed advisable by the Management Committee.
2.3 Offices and Registered Agent. The principal offices of the
Partnership shall be at such place or places as the Management Committee may
determine; provided, that, such place or places shall as soon as reasonably
practicable after the date of this Agreement be established in Oklahoma City,
Oklahoma, in an office which is separate from that of any Partner. The
Partnership shall maintain a registered agent and a registered office in
Arkansas as the Management Committee shall designate from time to time on the
Partnership's Certificate of Limited Partnership. As of the date of this
Agreement, the principal office shall be located at 600 Central Park Two, 515
Central Park Drive, Oklahoma City, Oklahoma 74124-0300 and the registered agent
and registered office shall be The Corporation Company, 417 Spring Street,
Little Rock, AR 72201. The Partnership may maintain offices at such other place
or places as the Management Committee deems advisable.
2.4 Term of Partnership. The Partnership commenced as of the date of
the filing of the Certificate of Limited Partnership as required under the Act
and shall continue for a period ending the earlier of:
(a) September 30, 2047;
(b) The date on which all of the assets acquired by the Partnership
have been sold and converted to cash (or to cash equivalents, or securities
tradeable on a national securities exchange) or otherwise disposed of and all
installment obligation receivables have been collected;
(c) The date on which the Partnership is voluntarily dissolved upon
approval by a SuperMajority in Interest of the Partners;
(d) The date on which the Partnership is dissolved by operation of
law or judicial decree; or
(e) The date on which the Partnership no longer has any General
Partners.
2.5 Purpose. The purpose and business of the Partnership shall be any
business which may lawfully be conducted by a limited partnership organized
pursuant to the Act. In particular, and not by way of limitation, the
Partnership (including any NOARK Related Entity) shall engage in the
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gathering, processing, compression, transmission and marketing of natural gas
and natural gas liquids.
2.6 Representations and Warranties Concerning Partnership. Each Partner
represents and warrants that (i) the execution and delivery of this Agreement by
such Partner and the performance thereof by such Partner of its obligations will
not contravene any provision of, or constitute a default under, any indenture,
mortgage or other agreement of such Partner, any applicable law or regulation or
any order of any court, commission or governmental agency having jurisdiction,
(ii) this Agreement is a legal, valid and binding obligation of such Partner
enforceable against such Partner in accordance with its terms, except insofar as
enforcement may be limited by bankruptcy, insolvency, reorganization or other
similar laws relating to or affecting the enforcement of creditors' rights
generally and by general equitable principles (regardless of whether enforcement
is considered in equity or at law), and (iii) it is acquiring its interest in
the Partnership for its own account for investment, and not with a view to the
sale or distribution thereof.
ARTICLE III
MANAGEMENT OF THE PARTNERSHIP
3.1 Management Committee. The Partnership (including all NOARK Related
Entities) shall be managed by the Management Committee, which, except as
otherwise provided in this Agreement (including without limitation, those
matters which under Section 3.5 require the approval of a SuperMajority in
Interest of Partners) shall have exclusive authority with respect to all affairs
of the Partnership (including any NOARK Related Entities).
3.2 Composition of Management Committee. The Management Committee shall
be composed of five (5) members. One member shall be the Project Leader as
determined in Section 3.6 below. EAPC (together with any Substituted Partner(s)
succeeding to EAPC's Partnership Interest) shall designate two of the four
remaining members of the Management Committee, and SWPL, (together with any
Substituted Partner(s) succeeding to SWPL's Partnership Interest) , shall
designate the two remaining members of the Management Committee. Each Partner
shall notify all other Partners in writing of their designations to the
Management Committee, including any alternate members they may choose to
designate. Such alternate members shall have full authority to act in the
absence of a primary member. The Partners shall have authority to remove their
respective designees to the Management Committee at any time and to replace them
with new designees at any time upon giving written notice to the other Partners.
3.3 Meetings of Management Committee. The Project Leader shall preside
at all meetings of the Management Committee, which shall meet at least
quarterly. Special meetings of the Management Committee may be called at such
times and places, and in such manner, as the Project Leader or any Partner deems
necessary and requests in writing, and at such times as requested in writing by
any member of the Management Committee. Unless notice is waived by
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all members of the Management Committee, notice of all meetings shall be given
by the Project Leader to all Management Committee members and to all Partners at
least five (5) days in advance of the time set for the meeting. The notice will
be accompanied by an agenda of the matters the proponent of the meeting intends
to present at the meeting; provided, that, the scope of the issues to be
discussed at the Management Committee meeting need not be limited to the matters
stated in the notice. Any member of the Management Committee may require that
items be added to the agenda by notice to all other Management Committee members
and Partners given at least forty-eight (48) hours prior to the meeting. Items
may be added to the agenda at a Management Committee meeting only if all members
of the Management Committee are present at such meeting and agree to the
addition of such items. Although discussions of other matters may take place,
only agenda items may be formally decided at any Management Committee meeting.
All meetings of the Management Committee shall be held in person or by means of
conference telephone or similar communications equipment by means of which all
persons participating in the meeting can hear each other. The members of the
Management Committee may act through written proxies, and the Management
Committee may take action in lieu of a meeting through a written consent signed
by all of the members of the Management Committee. The presence in person, by
proxy or through alternates of not less than fifty percent (50%) of the members
of the Management Committee shall be necessary to constitute a quorum at any
meeting for the transaction of business. Unless otherwise provided herein, the
affirmative vote of a majority of the members in attendance at a meeting of the
Management Committee at which a quorum is present ("Management Committee
Approval") shall be necessary and sufficient to take any action on behalf of the
Management Committee. Each member on the Management Committee shall have one
vote. In the absence of a quorum, a majority of the members present at the
meeting may adjourn such meeting from time to time until a quorum is present.
Written minutes of all Management Committee meetings shall be maintained and
distributed promptly to all members of the Management Committee.
3.4 Partners Meetings.
(a) Immediately upon execution of this Agreement, each Partner
shall designate, by notice given to each other Partner and to the
Partnership, an individual to serve as its primary representative to
vote at meetings of the Partners. By like notice, each Partner may
designate not more than one alternative representative who shall have
authority to act in lieu of its primary representative. In the absence
of a primary representative, the designated alternate may serve in the
place of the primary representative. Any Partner may at any time, by
written notice to all other Partners and to the Partnership, remove its
primary representative or alternate representative and designate a new
primary representative or alternate representative.
(b) The Project Leader shall preside at all meetings of the
Partners. Meetings of the Partners may be called at such times and
places, and in such manner, as requested in writing by a representative
of any Partner. Such request shall identify the items the Partner
proposes to be placed on the agenda for such meeting. Unless notice is
waived by the representatives of all Partners, notice of all meetings
shall be given by the Project Leader to
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all representatives and alternates at least five days in advance of the
time set for the meeting. The notice will be accompanied by an agenda
of matters to be presented by the Project Leader. Any representative
may require that items be added to the agenda by notice to the
representatives of all other Partners given at least two days prior to
the date of the meeting. Although discussion of other matters may take
place, only agenda items may be formally decided; provided, that by
unanimous vote of the representatives at a meeting in which at least a
SuperMajority in Interest of the Partners are represented, items may be
added to the agenda. All meetings of the Partners shall be held in
person or by means of conference telephone or similar communications
equipment by means of which all persons participating in the meeting
can hear each other. All expenses of the meeting and notification shall
be borne by the Partnership. Representatives of Partners (or their
respective designated alternates) holding at least 80% of the
Partnership Percentages shall be necessary to constitute a quorum at
any meeting for the transaction of business. In the absence of a
quorum, a majority of the representatives present at the meeting may
adjourn such meeting from time to time until a quorum is present.
Written minutes of all meetings shall be maintained and distributed
promptly to all representatives.
(c) Each representative at a meeting of Partners shall have a
vote equal to the Partnership Percentages of the Partner he represents.
(d) Personal presence of Partners' representatives shall not
be required, provided that at or prior to the meeting time either (i)
an effective written consent to or rejection of such proposed action is
submitted to the Project Leader or (ii) a proxy is submitted to the
Project Leader. Attendance by the representatives of the Partner (or
its respective designated alternate) and voting in person at any
meeting shall revoke any written consents or rejections of such Partner
or any proxies previously submitted with respect to the action proposed
to be taken at such meeting.
(e) Any matter on which the Partners are authorized to take
action under this Agreement or under law may be taken by the Partners
without a meeting and shall be as valid and effective as action taken
by the Partners at a meeting assembled, if written consents to such
action by the Partners are signed by the Partners entitled to vote upon
such action at a meeting who hold the Partnership Percentages required
to authorize such action, and are delivered to the Project Leader.
3.5 Restrictions on Authority of the Management Committee.
Notwithstanding anything to the contrary in this Agreement (other than Section
3.6(j)), including the provisions set forth in Section 3.1, the following
actions of the Management Committee (a "Major Decision") shall require the
consent of a SuperMajority in Interest of Partners and without such consent, may
not be taken by the Partnership (nor any Partner or other Person on behalf of
the Partnership), unless such actions are approved as a result of arbitration
pursuant to Section 13.13 below):
(a) Admitting any General Partner or Limited Partner.
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(b) Any incurrence of indebtedness for borrowed money other than the
NOARK Debt, the loan entered into with Enogex Inc. as contemplated by Section 9
of the Omnibus Agreement, or in the ordinary course of business. A borrowing, or
series of borrowings for purposes that are operationally related and that take
place in a consecutive 24 month period, shall be considered other than in the
ordinary course of business only if such borrowing or series of borrowings
involves more than $150,000.
(c) Entering into any gas transportation, gas purchase or gas sales
contract or any other contract or transaction between i) any Partner or any of
its Affiliates and ii) the Partnership (including any NOARK Related Entity),
other than contracts or transactions satisfying the parameters of the applicable
policy established by the Partners under Section 3.5(p).
(d) Amending this Agreement.
(e) Changing the nature of the Partnership's business.
(f) Establishing the nature and scope of the business of any NOARK
Related Entity including NOARK Energy Services L.L.C. and Ozark Gas Gathering,
L.L.C., including, without limitation, their operating parameters, functions and
activities.
(g) Selling, exchanging, leasing, mortgaging, pledging or otherwise
transferring Partnership (including any NOARK Related Entity) assets other than
in the ordinary course of business. For purposes of this Section 3.5(g), a sale,
exchange, lease, mortgage, pledge or other transfer of assets or a series of
such transactions that are operationally related and that take place in a
consecutive 24 month period, shall be considered other than in the ordinary
course of business only if such transaction or series of transactions involves
more than $250,000.
(h) Dissolving or winding up the Partnership.
(i) Amending the Certificate of Limited Partnership of the Partnership
except as otherwise permitted under this Agreement.
(j) Forming or dissolving any Partnership committee or changing the
authority or responsibilities of any committee.
(k) Except for expenditures, commitments, or contracts involving
Expansions or matters for which EAPC has agreed to make contributions to the
Partnership pursuant to Section 10(c) of the Omnibus Agreement:
(i) Entering into any contract which involves expenditures or
commitments by the Partnership in excess of $100,000 for projects not
included in any approved Budget or accepting performance under such
contract.
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(ii) Entering into any contract which involves expenditures or
commitments by the Partnership in excess of $500,000 for projects
included in any approved Budget or accepting performance under such
contract.
(iii) Entering into any contract (x) for the transportation,
purchase, sale, exchange or balancing of natural gas or (y) which
creates any material restrictions, conditions or impediments to the
Partnership, and which in the case of either (x) or (y) has a term in
excess of one year.
(l) Approving or amending the Budget.
(m) Acquiring assets for the Partnership involving an amount more than
$100,000 (for matters not included in any approved Budget) or $500,000 (for
matters included in any approved Budget), other than i) for purposes of an
Expansion, which shall be governed by Section 4.2(b), or ii) for matters for
which EAPC has agreed to make contributions to the Partnership pursuant to
Section 10(c) of the Omnibus Agreement, provided, however, that any such
acquisition involves terms that are standard and customary in the industry and
would not have a material adverse effect on the Partnership.
(n) Determining any matter which any contract to which the Partnership
is a party expressly provides shall be approved, decided, determined, or
otherwise resolved or acted upon by the Management Committee.
(o) Determining any material Partnership tax policy, other than that
fixed by this Agreement and approving the annual federal and state income tax
returns of the Partnership. For purposes of the foregoing material Partnership
tax policy shall include without limitation the making of any material tax
election and the adoption of a method of accounting with respect to any material
item.
(p) Approving any material policy decisions of the Partnership and
changes thereof, which approvals shall not be unreasonably withheld. For
purposes of the foregoing, material policy decisions shall include without
limitation i) the making of any decision regarding actions to be taken with any
governmental agency which would have a material effect on the Partnership or the
System, ii) the establishment of parameters for the Partnership (including any
NOARK Related Entity) to enter into gathering or transportation agreements on
the System and iii) the establishment of parameters for the Partnership
(including any NOARK Related Entity) to engage in gas marketing activities. The
Partners hereby acknowledge and agree that it is not their intent to use this
provision to micro-manage the operations of the Partnership.
(q) Determining the gross fair market value of the Partnership assets
as provided for in subsection (c) of the definition of Gross Asset value.
(r) Determining the form of a nominee agreement as contemplated by
Section 6.4.
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(s) Approving appointment of directors, managers or officers of NOARK
(except for the Project Leader whose approval shall be subject to Section
3.6(e)) or any NOARK Related Entity who are employees of any Partner or their
Affiliates; and the Project Leader shall consult with the Partners regarding the
appointment of any director, manager or officer of NOARK or any NOARK Related
Entity who is not an employee of any Partner or their Affiliates, but no
approval of such appointment shall be required.
(t) Approving the final design of the interconnection, integration and
expansion of the pipeline facilities of NOARK and Ozark described on Exhibit "A"
and any contracts for the supply of fuel or electricity to power the compressor
operations of the System. For purposes of the foregoing, the "final" design
shall mean those aspects of the design which would significantly impact future
operating expenses, or future operations, of the System.
(u) The decision to settle or to litigate and defend a claim against
the Partnership as provided in Section 3.9.
3.6 Project Leader.
(a) The Project Leader shall be the chief executive officer of the
Partnership (including the NOARK Related Entities) and, subject to directives of
the Management Committee and the other provisions of this Agreement, shall have
general supervision of the affairs of the Partnership (including the NOARK
Related Entities) and shall have all power and authority reasonably necessary to
perform or cause to be performed the general operation and conduct of the
Partnership. The Project Leader shall preside when present at meetings of the
Partners and the Management Committee. He shall have general authority to
execute bonds, deeds and contracts in the name of the Partnership (including the
NOARK Related Entities) and in general to exercise all the powers usually
appertaining to the office of president of a company, except as otherwise
provided by statute or this Agreement.
(b) The Project Leader shall manage the day-to-day operations of the
Partnership (including the NOARK Related Entities); provided, that, the Project
Leader shall undertake no Major Decision without the approval of a SuperMajority
in Interest of the Partners. Subject at all times to the control and direction
of the Management Committee, the Project Leader shall oversee the executive,
administrative and operating level services of the Partnership (including the
NOARK Related Entities). The Project Leader's executive level management
responsibilities shall include, without limitation: (1) implementation of
decisions of the Management Committee; (2) supervision and oversight of the
System's operations and financial affairs; and (3) such other duties and
services reasonably incidental to the foregoing which the Management Committee
may request the Project Leader to provide. The Project Leader's oversight of
administrative and operating level responsibilities shall include, without
limitation, oversight of: (i) contract and gas management services; (ii) finance
and accounting services; (iii) marketing services; (iv) engineering services;
(v)
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data systems and operations oversight; (vi) gathering activities and (vii)
day-to-day operating services necessary for the System.
(c) By way of illustration and not by way of limitation, the powers of
the Project Leader shall include: (i) executing, acknowledging and delivering
any and all agreements and instruments on behalf of the Partnership (including
any NOARK Related Entity); (ii) preparing and submitting annual Budgets to the
Partners for approval; (iii) employing or contracting with Persons in the
operations and management of the business of the Partnership (including any
NOARK Related Entity) on such terms and for such compensation as the Project
Leader shall determine, subject to the constraints and restrictions established
by the Budget, and, in the case of Persons employed by or affiliated with any
Partner or an Affiliate of any Partner, the provisions of the Accounting
Procedures attached hereto as Exhibit B; (iv) preparing or causing to be
prepared reports, statements and other relevant information for distribution to
the Partners; (v) opening accounts and deposits and maintaining funds in the
name of the Partnership (including any NOARK Related Entity) in banks or other
financial institutions or investing such funds; and (vi) making all reports and
filings required by governmental authorities.
(d) The Project Leader shall initially be E. Keith Mitchell who shall
serve in such capacity until the earlier of his death, resignation or removal.
In order for the Project Leader to receive the benefits he has heretofore
received, the Project Leader shall be employed by EAPC, but shall be dedicated
full time to the Partnership. The Project Leader shall maintain his office at
the principal business office of the Partnership.
(e) The Project Leader shall be subject to removal with or without
cause at any time by EAPC (or any Substituted Partner succeeding to all of
EAPC's Partnership Interest); provided such removal shall not be arbitrary or
capricious. If a vacancy occurs in the office of Project Leader, whether through
death, resignation, removal or otherwise, the Partners shall consult regarding
the appointment of a new Project Leader. After such consultation, EAPC (or any
Subsequent Partner succeeding to all of EAPC's Partnership Interest) shall have
the authority to propose the new Project Leader who shall become the Project
Leader upon the consent of SWPL (or any Subsequent Partner(s) succeeding to
SWPL's Partnership Interest), which consent shall not be unreasonably withheld.
It shall be deemed unreasonable for SWPL (or any Subsequent Partner(s)
succeeding to SWPL's Partnership Interest) to withhold its consent by reason of
the fact that the proposed Project Leader is or was an employee of EAPC (or any
Subsequent Partner succeeding to all of EAPC's Partnership Interest) or of an
Affiliate of EAPC.
(f) The Project Leader shall have power to contract with third parties
on behalf of and in the name of the Partnership (including any NOARK Related
Entity) when the contract is approved by the Management Committee (or is within
the approval levels delegated to him by the Management Committee), and to make
expenditures on behalf of the Partnership (including any NOARK Related Entity)
when such expenditures have been approved by the Management Committee (subject,
where applicable, to the provisions of Section 3.5) or when such expenditures do
not exceed that permitted under the approved annual Budget by more than ten
percent (10%) for
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the line item or items in question (based on a Budget format similar to that
historically used by the Partnership) or $50,000. Upon execution of this
Agreement, the Project Leader shall have authority to make expenditures in
fiscal year 1998 in accordance with the existing Budget of the Partnership for
fiscal year 1997 until a new Budget is approved.
(g) The Project Leader shall submit to the Partners for approval an
annual Budget setting forth on a monthly basis the anticipated costs to be
incurred in connection with the Partnership (including the NOARK Related
Entities), including without limitation the cost of operating and field
personnel providing day-to-day operations of the System, and the anticipated
capital costs to be incurred in connection with the System based on a Budget
format similar to that historically used by the Partnership. A proposed Budget
shall be provided to the Partners as soon as practicable following execution of
this Agreement for the period covering calendar year 1998 and by December 1st
for each year thereafter during the term of this Agreement. Such Budgets shall
be subject to the approval requirements of Section 3.5. In the event Partner
approval of any Budget as required by Section 3.5 is not obtained by the
commencement of the year to which such Budget applies, the most recently
approved Budget shall be utilized until such new Budget is approved.
(h) The Project Leader may rely and shall be protected in acting or
refraining from acting upon any resolution, certificate, statement, instrument,
opinion, report, notice, request, consent, order, bond, debenture, or other
paper or document believed by it to be genuine and to have been signed or
presented by the proper party or parties. The Project Leader may consult with
legal counsel, accountants, appraisers, management consultants, investment
bankers and other consultants and advisers selected by it and any act taken or
omitted in reliance upon an opinion including, without limitation, a written
opinion of counsel (who shall be regular or special counsel to the Partnership)
acceptable to the Project Leader of such persons as to matters that the Project
Leader reasonably believes to be within such person's professional or expert
competence shall be conclusively presumed to have been done or omitted in good
faith and in accordance with such opinion.
(i) The Project Leader shall have the right, in respect of any of his
powers or duties hereunder, to delegate same to any employee of the Partnership
or, to any Partner. Each such Person shall have full power and authority to do
and perform each and every act and duty that is so delegated to such Person.
(j) In the event the Project Leader incurs expenditures in emergency
situations to safeguard life or property or to maintain the operational
integrity of the System at design capacity, the Project Leader shall notify the
Management Committee and the Partners of the emergency situation as soon as
reasonably possible after any such emergency situation. Such costs so incurred
by the Project Leader shall not require the prior approval of the Management
Committee or the Partners; provided, however, that any expenditures or
transactions undertaken shall involve terms that are standard and customary in
the industry and do not expose or subject the Partnership to any inordinate,
unusual or unreasonable risks, liabilities or obligations given the facts and
circumstances which exist at the time of the Project Leader committing to any
such expenditures or transactions.
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The Partners acknowledge that the facts and circumstances of an emergency
situation may require terms, expenditures or transactions which under normal
situations would be different.
3.7 Delegation
(a) The Management Committee shall have the authority to delegate any
of its duties and authority to any Partner, the Project Leader, or, subject to
Section 3.5, a committee. Any such delegation shall be in writing and shall be
revocable at any time by the Management Committee.
(b) The Partners shall make available to the Partnership (including any
NOARK Related Entity) executive, administrative and operating personnel with the
appropriate backgrounds and experience to provide such services as the
Management Committee may reasonably delegate for them to provide and to make
available to the Management Committee sufficient time of such executives,
administrative and operating personnel to promptly, faithfully and
professionally provide such services. A Partner may utilize the personnel and
resources of not only itself, but also of its Affiliates and other Persons in
the performance of such services.
(c) The Partners shall be reimbursed by the Partnership in accordance
with the Accounting Procedures attached hereto as Exhibit B, for all direct and
indirect costs and expenses incurred in providing services delegated by the
Management Committee to be provided by them.
(d) Subject to the provisions of this Section 3.7, the Management
Committee shall be deemed to have delegated i) to SWPL the continued performance
of the accounting services for the Partnership and the performance of field
operations and field operations support services SWPL has historically provided
to the Partnership in Arkansas as well as the performance of field operations
and field operations support services in those areas where the facilities of
NOARK and Ozark are in close proximity for which the Partners agree SWPL should
provide such services and ii) to EAPC the performance of operations and
operations support services to provide support, direction and assistance to the
Project Leader in the operation of the Partnership (including the NOARK Related
Entities) and the System.
(e) Subject to Section 3.5, the Management Committee may designate one
or more committees (including, specifically, an executive committee), each of
which shall be comprised of one or more of its members, and may designate one or
more of its members as alternate members of any committee, who may, subject to
any limitations imposed by the Management Committee, replace absent or
disqualified members at any meeting of that committee. Any such committee, to
the extent provided in such resolution, shall have and may exercise the
authority delegated to it by the Management Committee in the management of the
business and affairs of the Partnership, subject to the limitations set forth in
the Act and this Agreement.
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3.8 Officers.
(a) Except for the chief executive officer, who shall be the Project
Leader, the Management Committee may appoint such officers and agents as it
deems necessary or appropriate, who shall be appointed for such terms and shall
exercise such powers and perform such duties as shall be determined from time to
time by the Management Committee. Any two or more offices may be held by the
same person.
(b) Any officer, agent or member of a committee elected or appointed by
the Management Committee may be removed by the Management Committee at any time
with or without cause.
3.9 Claims. The Project Leader shall be responsible for overseeing the
settlement or litigation and defending of any and all claims, damages, or causes
of action in favor of any one other than the Partners arising out of the
Operation of the System (as defined in the Accounting Procedures) which are not
covered by insurance; provided, that Project Leader shall report to the
Management Committee from time to time with respect to such claims, damages or
causes of action and the disposition thereof. The decision to settle or to
litigate and defend against any such claim, demand or cause of action may be
made by Project Leader in accordance with its best judgment and discretion when
the amount involved is $50,000 or less, provided, however, that if the aggregate
of the amounts payable by the Partnership in connection with any final judgment
against the Partnership and/or the settlement of any claim or claims against the
Partnership during any fiscal year exceeds $250,000, any subsequent settlements
shall be effected during such fiscal year only with the approval of a
SuperMajority in Interest of the Partners. Decisions to settle or to defend and
litigate (i) any single claim which involves any amount in excess of $50,000,
(ii) any claim which is commenced against the Partnership during any fiscal year
when the aggregate of all claims commenced against the Partnership during the
same fiscal year have involved amounts in excess of $250,000, and (iii) any
claim in which the Project Leader is named as a defendant or respondent or has
an interest in the claim or the proceedings which is adverse to the Partnership,
shall be made only with the approval of a SuperMajority in Interest of the
Partners.
3.10 Disputed Charges. Within the time provided in the Accounting
Procedures and regardless of whether the applicable Budget has been exceeded,
the Management Committee or any Partner may take written exception to all or any
portion of any bill or statement rendered by a Partner to the Partnership on the
ground that the same was not a reasonable expense or expenditure incurred in
good faith in connection with the Operation of the System (as such term is
defined in the Accounting Procedures). NOARK shall nevertheless pay in full when
due the amount of all statements submitted by a Partner. Thereafter, at its
discretion on the vote of Partners representing at least 70% of the Partnership
Interests remaining after excluding the Partner's Partnership Interest whose
bill or statement is in dispute, the Management Committee may submit the dispute
to the dispute resolution procedures set forth in Article XIII, and, in such
event the Partners agree to utilize such procedures in resolving such dispute.
If the amount as to which such written exception is taken or any part thereof is
ultimately determined in arbitration not to be a reasonable expense or
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expenditure incurred in good faith in connection with the Operation of the
System, such amount or portion thereof (as the case may be) shall be refunded to
NOARK together with interest thereon at one hundred basis points over the prime
rate from time to time charged by Citibank, N.A., New York, N.Y. to responsible
commercial and industrial borrowers, not in excess of the maximum lawful rate,
for the period from the date of payment by NOARK to the date of refund.
ARTICLE IV
FINANCING OF THE PARTNERSHIP
4.1 Existing Capital Accounts Balances. Schedule 4.1 hereto sets forth
the Capital Accounts of the Partners as of the date of this Agreement which have
been agreed to by the Partners.
4.2 Capital Contributions.
(a) In order to meet the funding requirements of the Partnership
(including any NOARK Related Entity), the Management Committee shall have
authority to make mandatory capital calls on the Partners for cash contributions
in amounts that the Management Committee deems necessary or advisable to fund
capital and operational needs of the Partnership (including any NOARK Related
Entity). With respect to each mandatory capital call, each Partner shall within
thirty (30) days of receiving such written notice contribute to the Partnership
in cash that portion of the total call equal to its Partnership Percentage.
(b) Notwithstanding the language of Section 4.2(a) above, the
Management Committee shall not have authority to issue mandatory capital calls
to fund a proposed Expansion of the System, other than Expansions included
within an approved Budget. Any such Expansion shall be subject to the consent of
a SuperMajority in Interest of the Partners; provided, that, if such consent is
not obtained within thirty (30) days of the submittal to the Partners of a
proposal for such an Expansion (which consent of any Partner may be conditioned
upon approval of such Partner's board of directors to be obtained (i.e. approved
or rejected) within sixty (60) days of the submittal to the Partners of the
proposed Expansion), but one of the Partners (the "Proposing Partner") desires
to pursue such Expansion, the Proposing Partner shall contribute to the capital
of the Partnership all of the funds necessary to finance such Expansion (such
contribution a "Special Capital Contribution") and shall following such
contribution receive, in addition to any other distributions provided for in
this Agreement, an additional cash distribution equal to all of the additional
net operating income attributable to the Expansion (which shall not include any
revenues realized from the replacement of volumes being transported on the
System prior to the Expansion) until the Proposing Partner has received an
amount equal to 200% of the Special Capital Contribution made by the Proposing
Partner.
(c) The Partners agree that the Existing Loans, including applicable
interest, shall be repaid as follows: (i) sixty percent (60%) of the Existing
Loans, including applicable interest, shall
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be repaid out of any amounts otherwise distributable to SWPL, before taking into
account debt service on the Existing Loans, under this Agreement and (ii) forty
percent (40%) of the Existing Loans, including applicable interest, shall be
repaid out of any amounts otherwise distributable to EAPC, before taking into
account debt service on the Existing Loans, under this Agreement. If such
amounts are insufficient to pay a Partner's percentage share (i.e. 60% or 40% as
set forth above) of the debt service on the Existing Loans, including applicable
interest, in accordance with their terms, then such Partner shall be responsible
to contribute to the capital of the Partnership amounts sufficient to pay its
percentage share (i.e. 60% or 40% as set forth above) of the debt service on the
Existing Loans, including applicable interest, and shall do so upon notice from
the Project Leader. Such Capital Contributions by the Partners shall not alter
the Partnership Percentages of the Partners. Default by a Partner in the making
of such Capital Contributions shall cause it to be deemed a Delinquent Partner
subject to the provisions of Section 4.3 hereof.
(d) Notwithstanding anything to the contrary in Section 4.2(c) above or
elsewhere in this Agreement, it is understood and agreed that the terms of any
Existing Loans may in the future (but do not currently) provide that the
amortization of the principal amount thereof shall be borne or allocated in a
manner different from the percentages set forth in Section 4.2(c) or any Partner
may direct the Project Leader to apply amounts of Partnership cash otherwise
distributable to such Partner (except amounts to be paid to other Partners
pursuant to the other provisions of this Agreement) to the repayment or
prepayment of the principal amount of the Existing Loans in excess of the
amounts required to be repaid under the terms of the Existing Loans, provided
such Partner bears all costs and penalties of doing so. Consequently, a Partner
may thereby pay or bear more than its attributable percentage (i.e. 60% or 40%)
of the principal amount of the Existing Loans to be repaid. In such event, the
percentages of the then outstanding principal amount of the Existing Loans
payable out of the distributable amounts attributable to the Partners set forth
in Section 4.2(c) shall be adjusted as appropriate to reflect the resulting
percentage of the aggregate outstanding principal amount of the Existing Loans
then attributable to each Partner.
4.3 Failure to Contribute. If any Partner fails to make a Capital
Contribution as required under Section 4.2(a) or (c) above, the Partnership may,
in addition to the other rights and remedies the Partnership may have under the
Act or applicable law, take such enforcement action (including, the commencement
and prosecution of court proceedings) against such Partner as the Management
Committee considers appropriate and such Partner shall be deemed to be
delinquent ("Delinquent Partner"). Moreover, each remaining Partner who is not
delinquent shall have the right, but not the obligation, to contribute that
portion of the amount defaulted by the Delinquent Partner equal to such
remaining Partner's Partnership Percentage expressed as a percentage of the
Partnership Percentage of all such remaining Partners who elect to contribute
their applicable portion of the defaulted Capital Contribution. In such an
event, the Partner(s) who contributes on behalf of the Delinquent Partner
("Contributing Partner") will be entitled to a priority distribution out of the
first cash distributions which would otherwise be distributable to the
Delinquent Partner equal to three hundred percent (300%) of the amount which the
Contributing Partner contributed on behalf of the Delinquent Partner. Following
satisfaction of this priority distribution, and any other priority distributions
provided for in this Agreement, distributions would be made in accordance with
Section
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5.7 hereof. The amount contributed on behalf of a Delinquent Partner shall be
secured by such Delinquent Partner's interest in the Partnership. Each Partner
who may hereafter be deemed delinquent hereby grants to each Contributing
Partner, a security interest in such Delinquent Partner's Partnership Interest.
4.4 Capital Accounts. A separate Capital Account shall be established
and maintained by the Partnership for each Partner in the manner described in
the definition of the term "Capital Account" in Article I hereof.
4.5 Loans by Partners. No Partner shall be required to make loans to
the Partnership. Loans may be made, however, with the approval of the Management
Committee, by any Partner to the Partnership and such loans shall not be
considered contributions to the capital of the Partnership. To the extent loans
are made by any Partner to the Partnership, they shall be made on terms, as to
interest rates and other finance charges, as are comparable to amounts that are
charged by unrelated banks and other financial institutions on comparable loans
for the same purpose.
4.6 Interest. No interest shall be paid to any Partner on the initial
or any subsequent Capital Contribution to the Partnership.
4.7 Time for Return of Contributions. No Partner shall be entitled to
compel the return of its Capital Contribution. Upon the full and complete
winding up and liquidation of the business and affairs of the Partnership, the
Partners shall be entitled to distributions as set forth in Article X.
4.8 Limited Liability of the Limited Partners. Notwithstanding anything
to the contrary contained herein, the liability of a Limited Partner for any of
the debts, losses or obligations of the Partnership shall be limited to the
Limited Partner's Capital Contributions. No Limited Partner shall have any
personal liability whatsoever, whether to the Partnership or any third party,
for the debts of the Partnership or any of its losses.
4.9 Benefits of Agreement. Nothing in this Agreement, and, without
limiting the generality of the foregoing, in this Article IV, expressed or
implied, is intended or shall be construed to give to any creditor of the
Partnership or any creditor of any Partner or of any other Person, other than
the Partners and the Partnership, any legal or equitable right, remedy or claim
under or in respect to this Agreement or any covenant, condition or provisions
herein contained, and such provisions are and shall be held to be for the sole
and exclusive benefit of the Partners and the Partnership.
ARTICLE V
CAPITAL AND INCOME ALLOCATIONS AND DISTRIBUTIONS
5.1 Allocations Controlling for Capital Account Purpose. The Partners
agree that all items of Partnership income, gain, loss and deduction realized by
the Partnership from its operation or upon the sale or other disposition of its
assets shall be credited or charged to the Capital Accounts
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of the Partners and further, to the extent allowed by the law, among the
Partners for Federal income tax purposes in accordance with Sections 5.2 through
5.6. The allocation of Partnership income, gain, loss and deduction to a Partner
whose interest in the Partnership terminates or to a newly admitted Partner
shall be based upon an actual closing of the books of the Partnership for the
period ending on the date of such termination or admission except as otherwise
determined by the Management Committee. In addition, upon the closing of the
Ozark Acquisition, there shall be an actual closing of the books of the
Partnership for the period ending on the date of the closing of the Ozark
Acquisition, when the Partnership Percentages will change as specified in the
definition of Partnership Percentage. Further, upon the Inservice Expansion
Date, there shall be an actual closing of the books of the Partnership for the
period ending on the date of the Inservice Expansion Date, when the Partnership
Percentages will change as specified in the definition of Partnership
Percentages. For purposes of making the allocations under this Agreement for the
periods ending on the Ozark Acquisition and the Inservice Expansion Date, the
allocation of Partnership income, gain, loss and deduction to a Partner shall be
based upon such dates.
5.2 General Allocation of Profits and Losses. After giving effect to
the special allocations set forth in Sections 5.3 through 5.6 hereof, the
Profits and Losses for any fiscal year, or portion thereof, as applicable, shall
be allocated to the Partners in accordance with the Partnership Percentages of
the respective Partners.
5.3 Special Interest Expense. The Partnership interest expense
deductions incurred with regard to the Existing Loans as referenced in Section
4.2(c) shall be allocated to Partners as follows:
SWPL 60%
EAPC 40%
In the event the percentages of the outstanding principal amounts of the
Existing Loans payable out of the distributable amounts attributable to each
Partner are adjusted pursuant to Section 4.2(d), the foregoing percentages shall
be subject to adjustment to reflect the same percentages as the percentages
established pursuant to Section 4.2(d).
5.4 Preferential Allocations.
(a) During each fiscal year of the period commencing on the Inservice
Expansion Date and ending on December 31, 2009 (the "Special Allocation Period")
SWPL shall receive a special allocation of Partnership gross revenues (items of
gross income and gain) in accordance with the formula set forth below. For
purposes of this Section 5.4(a), a fiscal year shall be a calendar year except
that the first fiscal year of the above described period shall commence on the
Inservice Expansion Date and end on December 31 of the calendar year in which
the Inservice Expansion Date occurs.
Special Revenue Allocation = Base Amount - Increased Volume
Amount, where:
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(1) Base Amount = for each fiscal year during the Special
Allocation Period, the amount specified on Schedule
5.4(a) for such fiscal year
(2) Increased Volume Amount =
(a) the product of (i)the average daily quantity
of gas(in MMBtu's)moved on the System during
the fiscal year less the Firm Quantities (as
defined below) for such year (but not less
than 244,000 MMBtu's per day less the Firm
Quantities), multiplied by (ii) 25% of the
average margin (per MMBtu) realized by (x)
EIT (which, upon the Inservice Expansion
Date, will be a NOARK Related Entity and
will own the integrated interstate
transmission facilities of Ozark and the
Partnership), (y) NES L.L.C. (as defined in
the Omnibus Agreement) the average margin of
which may be negative, and (z) OGG L.L.C.
(as defined in the Omnibus Agreement) but
only to the extent of the Searcy Gathering
Assets (as defined in the Omnibus Agreement)
and the average margin realized from such
assets as they will exist on the date of
their contribution to the System (the
entities and assets specified in items (x),
(y) and (z) herein collectively referred to
as the "Preferential Allocation Group") from
the movement of such average daily quantity
of gas on the System as the System exists on
the Inservice Expansion Date, and as it may
be modified by only the contribution of the
Searcy Gathering Assets (as defined in the
Omnibus Agreement) as they exist on the date
of their contribution to the Partnership,
whether from transportation revenues or
sales revenues (which average margin shall
not be less than $.16 per MMBtu), multiplied
by (iii) the number of days in such fiscal
year minus
(b) the product of (i) 244,000 MMBtu's per day
less the Firm Quantities for such fiscal
year multiplied by (ii) $.04 per MMBtu,
multiplied by (iii) the number of days in
such fiscal year.
(b) For purposes of Section 5.4(a) above, the following shall apply:
(1) The calculation of the Increased Volume Amount shall
not include quantities of gas (in MMBtu's) received
from supply sources in existence on January 1, 1998
located behind those supply points identified on
Schedule 5.4(b), or average margins attributable to
those quantities.
(2) Firm Quantities shall mean the average daily quantity
of gas (in MMBtu's) moved on the System under Firm
Business Agreements (as hereinafter defined) in any
fiscal year.
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(3) For purposes of the foregoing, Firm Business
Agreements shall mean firm gas transportation or
sales agreements having a primary term of one (1)
year or more between any member of the Preferential
Allocation Group and customers (such customers being
other than Affiliates which are NOARK Related
Entities).
(4) For purposes of this Section 5.4, the "average
margin" realized by the Preferential Allocation Group
shall mean (i) in the case of transportation or
gathering revenues, the average gross revenues
received (per MMBtu) from shippers for the movement
of gas on the System (including any demand charges
received under firm transportation agreements which
are not Firm Business Agreements), and (ii) in the
case of sales revenues, the average gross revenues
received (per MMBtu) from the sale of gas after
subtracting therefrom the average costs (per MMBtu)
directly incurred in making such sales, including
without limitation gas costs, gathering costs,
transportation costs and any related imbalance
penalties. In addition, for purposes of calculating
the Special Revenue Allocation, in the event the
Preferential Allocation Group engages in multiple
transactions involving the same gas, such
transactions shall be considered a single transaction
in determining the "average daily quantities" from
such transaction and the "average margin" realized
from such transaction.
(c) The Special Revenue Allocation for any fiscal year shall be
determined within sixty (60) days following the end of the fiscal year to which
such Special Revenue Allocation is applicable, but shall be effective for the
fiscal year in which the revenues were received. In no event will the Special
Revenue Allocation be less than zero.
(d) Schedule 5.4(d) attached hereto, sets forth several examples of the
calculation of the Special Revenue Allocation.
5.5 Special Profits Allocations.
(a) After making the special allocation of Partnership gross revenues
(items of gross income and gain) pursuant to Section 5.4 hereof and the special
allocation of Partnership deductions pursuant to Section 5.3 hereof, the
Partnership Profits shall be specially allocated to the Partners which have
received additional cash distributions in the current or prior years related to
contributions by Contributing Partners pursuant to Section 4.3 above in the
following manner and amount: Partnership Profits otherwise allocable to the
Delinquent Partner (i.e. Profits which would have been allocated to the
Delinquent Partner if this Section 5.5(a) did not exist) shall be allocated to
the Contributing Partners until the cumulative amount of Partnership Profits
allocated pursuant to this Section 5.5(a) equals the cumulative amount of the
cash distributions otherwise distributable to the Delinquent Partner, but which
are made to the Contributing Partners as provided in Section 4.3.
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(b) After making the special allocation of Partnership gross revenues
(items of gross income and gain) pursuant to Section 5.4 hereof, the special
allocation of Partnership deductions pursuant to Section 5.3 hereof and the
special allocation of Partnership Profits pursuant to Section 5.5(a) hereof, the
Partnership Profits shall be specially allocated to the Partners which have
received additional cash distributions in the current or prior years related to
an Expansion pursuant to Section 4.2(b) above until the cumulative amount of
Partnership Profits allocated pursuant to this Section 5.5(b) equals the
cumulative amount of such additional cash distributions received by the
respective Partners.
5.6 Other Allocation Rules.
(a) Section 754 Adjustments. To the extent an adjustment to the
adjusted tax basis of any Partnership asset pursuant to Code ss. 734(b) or Code
ss. 743(b) is required, pursuant to Treas. Reg. ss. 1.704-1(b)(2)(iv)(m), to be
taken into account in determining Capital Accounts, the amount of such
adjustment shall increase the basis of the asset or loss (if the adjustment
decreases such basis) and such gain or loss shall be specially allocated to the
Partners in a manner consistent with the manner in which their Capital Accounts
are required to be adjusted pursuant to such section.
(b) Code Section 704(c) Tax Allocations. In accordance with Code ss.
704(c) and the Regulations thereunder, income, gain, loss and deduction with
respect to any property contributed to the capital of the Partnership shall,
solely for tax purposes, be allocated among the General Partners and Limited
Partners so as to take account of any variation between the adjusted basis of
such property to the Partnership for Federal tax purposes and its initial Gross
Asset Value using the "traditional method with curative allocations" as set
forth in Treas. Reg. ss. 1.704-3(c). In the event the Gross Asset Value of any
Partnership asset is adjusted as required by the definition of "Gross Asset
Value" as contained in this Agreement, subsequent allocations of income, gain,
loss and deduction with respect to such asset shall take account of any
variation between the adjusted basis of such asset for Federal income tax
purposes and its Gross Asset Value in the same manner as under Code ss. 704(c)
and the Regulations thereunder. Any elections or other decisions relating to
such allocations shall be made by the General Partners in any manner that
reasonably reflects the purpose and intention of this Agreement. Allocations
pursuant to this Section 5.6(b) are solely for purposes of federal, state, and
local income taxes and shall not affect, or in any way be taken into account in
computing, any Partner's Capital Account or share of Profits, Losses, other
items, or distributions pursuant to any provision of this Agreement.
5.7 Cash Distributions. Except as otherwise provided in this Agreement,
the Management Committee in its sole discretion shall have the authority to
cause the Partnership to allocate and distribute cash or other property to the
Partners monthly on a basis in accordance with this Agreement. All distributions
shall be made in accordance with the Partnership Percentages of the respective
Partners, net of each Partner's required share of payments on the Existing
Loans, including interest thereon, as provided in Section 4.2(c), except for i)
distributions related to the funding of Expansions under Section 4.2(b), ii)
distributions under Section 4.3 and iii) distributions in liquidation pursuant
to Article X. It shall be a policy of the Partnership to distribute the maximum
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amount of cash available after taking into account anticipated future sources of
cash and the working capital and cash requirements to meet the current and
anticipated future obligations of the Partnership.
5.8 Amounts Withheld. All amounts withheld pursuant to the Code or any
provision of any state or local tax law with respect to any payment or
distribution to the Partnership or the Partners shall be treated as distributed
to the Partners pursuant to Section 5.7 for all purposes under this Agreement.
The Management Committee shall allocate such amounts among the Partners in a
manner that is consistent with Article V hereof and applicable law.
5.9 Reimbursements. The Project Leader and any Partner performing
services or providing goods to the partnership, in accordance with the
provisions of this Agreement, shall be reimbursed by the Partnership for all
reasonable direct and indirect costs and expenses incurred on behalf of the
Partnership in the performance of their duties hereunder in accordance with the
Accounting Procedures attached hereto as Exhibit B.
ARTICLE VI
RELATIONS OF THE PARTNERS
6.1 Restricted Transactions.
(a) Except as set forth in Section 6.1(a)(i) below, during the period
of time that a person is a Partner, no Partner shall, nor shall it to the extent
possible permit its Affiliates to, engage in any transactions involving,
directly or indirectly any business activity which is within the scope of the
business activities of any NOARK Related Entity as established by the Partners
pursuant to Section 3.5(f) (a "Restricted Transaction") without first giving the
Partnership a right of first refusal in accordance with the terms set forth in
Section 6.1(b) below with respect to such Restricted Transaction. Any such
business activities of any NOARK Related Entity so established by the Partners
shall be restricted to business activities on the System.
(i) A person who is a Partner, or who is an Affiliate of a
Partner, shall be permitted to (u) conduct gas marketing activities without
restriction, (v) continue to own and/or operate facilities for the gathering,
transportation, processing, compression or storage of natural gas or liquid
hydrocarbons which they owned and/or operated on December 31, 1997 (the
"Existing Facilities"), (w) continue to conduct transactions involving such
Existing Facilities, (x) expand and extend such facilities (by construction,
purchase or otherwise) and transactions involving such facilities (y) expand
and/or extend those businesses or operations and (z) conduct any other business
activities which are not conducted on the System. It is the intent of this
Section (6)(a)(i) to permit Partners and their Affiliates to continue to engage
in those businesses and operations (in which they were engaged on December 31,
1997) and to expand and/or extend those businesses and operations. Any projects
or businesses, however, which do not involve such businesses or operations as
they
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may be so expanded or extended and which would otherwise meet the requirements
of Section 6.1(a), are to be offered to the Partnership under Section 6.1(b).
(b) Should any Partner or its Affiliate desire to engage in a
Restricted Transaction, such Partner (the "Submitting Partner") shall submit to
the Partnership and to each Partner written notice (a "Submission") of the
Restricted Transaction, including a copy of any contract or agreement setting
forth the terms of the Restricted Transaction. The Partnership (whether itself
or through a NOARK Related Entity) acting upon the unanimous approval of all the
Partners except the Submitting Partner (who shall have no right to vote on the
Restricted Transaction) shall then have sixty (60) days from the delivery to it
of the Submission in which to elect to pursue the Restricted Transaction on the
terms set forth in the Submission. The Partnership shall evidence its election
to pursue the Restricted Transaction by giving written notice of such election
to the Submitting Partner within such sixty (60) day period, and the Submitting
Partner shall no longer have any separate interest in the Restricted Transaction
but shall fully cooperate in assisting the Partnership to pursue the Restricted
Transaction. If the Partnership does not elect in a timely manner to pursue the
Restricted Transaction, then the Partnership shall be deemed to have rejected
the Restricted Transaction and the Submitting Partner shall be free to pursue
the Restricted Transaction for its own separate account; provided, that, the
terms upon which the Submitting Partner shall pursue the Restricted Transaction
shall be the same as those set forth in the Submission to the Partnership. If
the terms of the Restricted Transaction shall vary from those set forth in the
Submission, then the Submitting Partner shall be required to commence again the
right of first refusal process by submitting a new Submission setting forth the
revised terms to the Partnership and the Partners and the Partnership shall have
the right to accept or reject the Restricted Transaction in accordance with the
procedure set forth in this Section 6.1 (b).
(c) Subject to the restrictions contained in Section 6.1(a), (i) the
Partners recognize that each of the Partners, directly or through its respective
Affiliates, may be currently engaged in numerous businesses in the gas industry
including, without limitation, buying, selling, gathering, transporting,
processing, compressing or storing natural gas or liquid hydrocarbons for
profit; and (ii) each Partner agrees that each other Partner may continue such
activities, may form new Affiliates to engage in such activities, and may expand
the present scope of such activities, in each case irrespective of whether such
be deemed in competition with the business and activities of the Partnership,
without in any manner being obligated to disclose such activities to the
Partnership or the other Partners, or to permit the Partnership or the Partners
to participate therein, and without any liability to the Partnership or the
Partners for breach of any duty arising out of such other Partner's position as
a Partner in the Partnership.
6.2 Exculpation from Liability.
(a) The Project Leader, shall have no liability whatsoever to the
Partnership (including any NOARK Related Entity) or to any Partner for loss
caused by any act or by failure to do any act if the loss suffered by the
Partnership (including any NOARK Related Entity) or any Partner arises out of an
action taken, or not taken, by the Project Leader in the course of the
Partnership's
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(including any NOARK Related Entity) business in good faith and not contrary to
the terms of this Agreement even if such action or failure to act constitutes
negligence.
(b) Neither the Management Committee, nor any member thereof (other
than the Project Leader to whom Section 6.2(a) applies), shall have any
liability whatsoever to the Partnership (including any NOARK Related Entity) or
to any Partner for loss caused by any act or by failure to do any act if the
loss suffered by the Partnership (including any NOARK Related Entity) or any
Partner arises out of an action taken, or not taken by the Management Committee,
or a member thereof in the course of the Partnership's (including any NOARK
Related Entity) business in good faith and not contrary to the terms of this
Agreement even if such action or failure to act constitute negligence; provided,
that, this shall not apply where the Person's action or failure to act
constitute willful misconduct or gross negligence.
6.3 Indemnification.
(a) To the fullest extent permitted by law but subject to the
limitations expressly provided in this Agreement, each Indemnitee shall be
indemnified and held harmless by the Partnership (including any NOARK Related
Entity) from and against any and all losses, claims, damages, liabilities (joint
or several), expenses (including without limitation, reasonable legal fees and
expenses), judgments, fines, settlements and other amounts arising from any and
all claims, demands, actions, suits or proceedings, whether civil, criminal,
administrative or investigative (other than claims by or on behalf of the
Partnership, including any NOARK Related Entity), in which any Indemnitee may be
involved, or is threatened to be involved, as a party or otherwise, by reason of
its status as an Indemnitee arising out of or relating to the performance of
this Agreement or its actions (or failures to act) with respect to the business
of the Partnership (including any NOARK Related Entity); provided, that in each
case the Indemnitee acted in good faith, in a manner which such Indemnitee
believed to be in, or not opposed to, the best interests of the Partnership
(including any NOARK Related Entity) and, with respect to any criminal
proceeding, had no reasonable cause to believe its conduct was unlawful. The
termination of any action, suit or proceeding by judgment, order, settlement,
conviction or upon a plea of nolo contendere, or its equivalent, shall not
create a presumption that the Indemnitee acted in a manner contrary to that
specified above.
(b) To the fullest extent permitted by law, expenses (including without
limitation, reasonable legal fees and expenses) incurred by an Indemnitee in
defending any claim, demand, action, suit or proceeding shall, from time to
time, be advanced by the Partnership (including any NOARK Related Entity) prior
to the final disposition of such claim, demand, action, suit or proceeding upon
receipt by the Partnership of an undertaking by or on behalf of the Indemnitee
to repay such amount if it shall be determined that the Indemnitee is not
entitled to be indemnified as authorized in this Section 6.3.
(c) The indemnification provided by this Section 6.3 shall be in
addition to any other rights to which an Indemnitee may be entitled under this
Agreement, as a matter of law or otherwise,
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as to actions in the Indemnitees' capacity as an Indemnitee and shall continue
as to an Indemnitee who has ceased to serve in such capacity as to actions
during its capacity as an Indemnitee.
(d) The Partnership shall purchase and maintain insurance on the
Partnership (including the NOARK Related Entities) and the assets of the
Partnership (including any NOARK Related Entities). Such insurance shall at a
minimum include the insurance specified on Schedule 6.3(d) attached hereto. The
Partnership may purchase and maintain insurance (in such amounts and for such
purposes as the Partnership shall determine), on behalf of the Partners, the
Project Leader and such other Persons as the Partnership shall determine,
against any liability that may be asserted against or expense that may be
incurred by any such Person in connection with the Partnership's activities,
whether or not the Partnership would have the power to indemnify such Person
against such liabilities under the provisions of this Agreement.
(e) In no event may an Indemnitee subject a Limited Partner to personal
liability by reason of the indemnification provisions set forth in this
Agreement.
(f) An Indemnitee shall not be denied indemnification in whole or in
part under this Section 6.3 because the Indemnitee had an interest in the
transaction with respect to which the indemnification applies if the transaction
was otherwise permitted by the terms of this Agreement.
(g) The provisions of this Section 6.3 are for the benefit of the
Indemnitees, their heirs, successors, assigns and administrators and shall not
be deemed to create any rights for the benefit of any other Persons.
(h) No amendment, modification or repeal of this Section 6.3 or any
other provision hereof shall in any manner terminate, reduce or impair the right
of any Indemnitee, or former Indemnitee, to be indemnified by the Partnership,
nor the obligation of the Partnership to indemnify any such Indemnitee under and
in accordance with the provisions of this Section 6.3 as in effect immediately
prior to such amendment, modification or repeal with respect to claims arising
from or relating to matters occurring, in whole or in part, prior to such
amendment modification or repeal, regardless of when such claims may arise or be
asserted.
6.4 Title to Partnership Assets. Title to assets of the Partnership
(including any NOARK Related Entity), whether real, personal or mixed and
whether tangible or intangible, shall be deemed to be owned by the Partnership
as an entity, and no Partner, individually or collectively, shall have any
ownership interest in such assets of the Partnership or any portion thereof.
Title to any or all of the assets of the Partnership (including any NOARK
Related Entity) may be held in the name of the Partnership (including any NOARK
Related Entity), or one or more nominees as the Management Committee may
determine under the terms of a nominee agreement the form of which shall be
approved by a SuperMajority in Interest of the Partners. All assets of the
Partnership (including any NOARK Related Entity) shall be recorded as the
property of the Partnership in its books and records, irrespective of the name
in which record title to such assets are held.
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ARTICLE VII
ASSIGNABILITY OF PARTNERS' INTERESTS
7.1 Restrictions on Transfer of Partner's Interest. Except as set forth
in Section 7.7, no Partner may Transfer all or a portion of its Partnership
Interest (the "Transferor"), unless the Transferor and transferee (the
"Transferee"), comply with the provisions of Section 7.2. No portion of a
Partner's right to receive its allocable share of income and losses and
distributions of the Partnership may be Transferred without the Transfer of the
same portion of a Partner's Partnership Interest. Failure to comply with the
provisions of this Article VII shall render the purported Transfer null and void
and of no force or effect for any purpose.
7.2 Right of First Refusal. At any time, a Transferor may offer to sell
for cash all or a portion of its Partnership Interest (but any such portion may
not be less than ten percent (10 %) of the total Partnership Interests)to any or
all of the other Partner(s) by delivering to them a written offer (the "Sales
Offer") specifically referring to this Section 7.2, stating the Transferor's
desire to sell, specifying the portion of such Partnership Interest to which the
Sales Offer applies, stating that such portion is to be sold in its entirety and
setting forth the cash purchase price. Within thirty (30) days following the
receipt of the Sales Offer, each other Partner may elect to accept the Sales
Offer at the purchase price set forth therein. Such acceptance may be
conditioned upon approval by the board of directors of the accepting Partner to
be obtained within sixty (60) days following receipt of the Sales Offer by the
accepting Partner. If more than one of the other Partners elect to accept the
Sales Offer, the purchase shall be made pro rata in accordance with the
accepting Partners' respective Partnership Interests. Payment for such
Partnership Interest shall be made within thirty (30) days after the final date
on which a Partner elects to accept the Sales Offer; provided, however, if any
waiting periods are imposed by applicable law, payment shall, if necessary, be
deferred to the first business day occurring after the expiration of the last
day of such waiting period. In the event that the Partners do not elect to
acquire or do not acquire the entire portion of the Partnership Interest
specified in a Sales Offer within the time periods referred to above, the
Transferor shall be entitled to Transfer to a third party (including an
Affiliate of the Transferor) the Partnership Interest stated in the Sales Offer
for a consideration in cash or other property having equal or greater value than
the cash purchase price stated in the Sales Offer during the six (6) month
period commencing with the day following the expiration of the 60-day time
period referred to above. If the consideration is other than all cash, the
Transferor shall provide the other Partners with the report of a qualified
appraiser concluding that the total value of the consideration to be paid for
the Partnership Interest is equal to or exceeds the value of the cash purchase
price stated in the Sales Offer. Prior to any Transfer becoming effective, the
Transferor shall provide written notice to all of the Partners and shall settle
all unpaid accounts with the Partnership.
7.3 Opinion of Counsel. The Transferor shall deliver to the Project
Leader evidence satisfactory to the Project Leader (including, if requested by
the Project Leader an opinion of counsel in form and substance satisfactory to
counsel to the Partnership), that:
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(a) such Transfer and any offerings made in connection therewith are in
compliance with applicable federal and state securities laws; and
(b) the Transfer will comply with all applicable rules and regulations
of government authorities.
(c) such Transfer and offerings will not cause the Partnership to be a
publicly traded partnership within the meaning of Section 7704 of the Code.
7.4 Substituted Partner. A Transferee shall become a Substituted
Partner of the Partnership in the event a SuperMajority in Interest of the
Partners consent in writing to the Transferee becoming a Substituted Partner or
if the Transferor and Transferee have complied with all of the requirements of
this Article VII and:
(a) The Transferor states its intention in writing to have the
Transferee become a Substituted Partner as concerns the portion of its
Partnership Interest to be Transferred;
(b) The Transferee agrees to pay any filing fees, reasonable counsel
fees, and other reasonable expenses of the Partnership in connection with its
becoming a Substituted Partner;
(c) The Transferee agrees in writing to be bound by all of the terms
and provisions of the Agreement and any other document or instrument executed by
or otherwise binding upon the Partners as if an original party to the Agreement
or other such document or instrument and to assume all the duties, liabilities
and obligations of the Transferor in respect of such Partnership Interest,
provided, that, the Transferor shall not be released from any liabilities of or
to the Partnership arising prior to the date of the Transfer; and
(d) The Transferee executes a statement satisfactory to the Project
Leader that it is acquiring such Partnership Interest for its own account for
investment and not with a view to the distribution or resale thereof.
7.5 Recognition of Transferee as Partner. Upon the effective Transfer
of a Partnership Interest, compliance with the other provisions of this Article
VII, and admission of the Transferee as a Substituted Partner, the Project
Leader shall, to the extent required by law execute, file and record with the
appropriate governmental agencies such documents as are required to accomplish
the substitution of the Transferee as a Substituted Partner. If required by law,
the Certificate of Limited Partnership shall be amended and recorded not more
often than quarterly, to recognize the admission of Substituted Partners.
Nothing contained herein is meant to require the filing of a Certificate of
Limited Partnership (or amendment thereto) which includes the names of all
Partners and Substituted Partners, if under applicable state law the inclusion
of such names is discretionary. In all events the Project Leader shall amend
this Agreement to reflect the admittance to the Partnership of the Substituted
Partner. The Partnership shall treat a Transferee who becomes a Substituted
Partner pursuant to the provisions of this Article VII as a Substituted Partner
with respect
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to the Partnership Interest, or part thereof, assigned from the last business
day of the calendar quarter following the acceptance by the Project Leader of
the Transfer, notwithstanding the time consumed in preparing and filing the
necessary documents with governmental agencies necessary to effectuate the
substitution.
7.6 Binding Effect. Any Transferee admitted to the Partnership as a
Substituted Partner shall be subject to and bound by all the provisions of the
Agreement as if an original party to the Agreement.
7.7 Permitted Transfers of Partnership Interests. Notwithstanding any
provision of this Article VII or the Agreement to the contrary, a Partner may
transfer its Partnership Interest in accordance with the following, provided the
transfer does not cause a termination of the Partnership under Section 708 of
the Code:
(a) any Partner may transfer all or any part of its Partnership
Interest to its Affiliate, which is directly or indirectly wholly-owned by the
Partner; provided such wholly-owned Affiliate complies with the requirements of
Section 7.4 and that, any such transfer shall not relieve the assigning Partner
of any of its past or future obligations under this Agreement;
(b) the Partners may pledge or otherwise encumber their Partnership
Interests to secure indebtedness of the Partnership or of the Partners;
provided, that, any Person who acquires a Partnership Interest by reason of such
pledge or encumbrance shall not in any event be admitted as a Substituted
Partner unless approved in writing by a SuperMajority in Interest.
7.8 Succession to Capital Account. Any valid Transferee of a
Partnership Interest in accordance with the terms of this Agreement shall
succeed to the balance of its Transferor's Capital Account.
ARTICLE VIII
WITHDRAWAL AND REMOVAL;
ADMISSION OF SUCCESSOR AND ADDITIONAL GENERAL PARTNERS
8.1 Voluntary Withdrawal. Each Partner hereby agrees that it may
withdraw from the Partnership only in connection with a Transfer of the entirety
of its Partnership Interest in accordance with Article VII hereof or with the
prior written consent of all other Partners. Any withdrawal not permitted under
the preceding sentence shall constitute a breach of this Agreement by the
withdrawing Partner.
8.2 Other Withdrawal Events. The occurrence of any of the events
described in Subsection 4-43-402(4) and (5) of the Act shall not effect the
withdrawal of a General Partner.
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8.3 Removal of a Partner. A Partner may not be removed as a
Partner.
8.4 Liability of a Withdrawn General Partner. Any General Partner which
shall for any reason withdraw from the Partnership, whether voluntarily or
involuntarily, or shall Transfer all or a portion of its Partnership Interest,
shall be and remain liable for all obligations and liabilities incurred by such
General Partner (including liabilities of the Partnership or any NOARK Related
Entity) prior to the time such withdrawal or Transfer has become effective, but
shall be free of any obligation or liability incurred on account of the
activities of the Partnership (including any NOARK Related Entity) from and
after the time such withdrawal or Transfer becomes effective except for any
liabilities or damages attributable to its action in withdrawing from the
Partnership.
8.5 Additional or Successor Partners.
(a) The Management Committee may admit additional or successor General
Partners in connection with a Transfer of all or a part of a General Partner's
Partnership Interest subject to compliance with Article VII above.
(b) If a General Partner withdraws pursuant to this Agreement and if
such removal would leave the Partnership without a General Partner, then prior
to the effective date of such removal or withdrawal, the Limited Partners shall
meet to select and appoint one or more successor General Partners to continue
the business of the Partnership, which selection and appointment shall be
effected by the approval of a Majority in Interest of the Limited Partners and
become effective prior to the removal or withdrawal of a sole General Partner. A
one percent (1%) partnership interest shall be reallocated from the Limited
Partners, pro rata, to any successor General Partner(s) required pursuant to
this Section 8.5, unless the successor General Partner makes a capital
contribution to the Partnership equal to or greater than one percent (1%) of the
total of the Capital Contributions to the Partnership.
8.6 Continuation of Partnership. In the event of an event which causes
the dissolution of the Partnership by the provisions of this Agreement, the
Partnership may be reconstituted and its business continued without being wound
up by the agreement in writing of all Partners.
8.7 Automatic Suspension of the Vote and Right to Participate in
Management of Partnership Affairs: A Partner's right to participate in the
management of Partnership affairs shall be suspended in the event of such
Partner's failure to make a capital contribution required to be made under
Section 4.2 above, when such failure continues for a period of ten (10) days
following receipt of notice from the Project Leader of such failure to make such
capital contribution; provided, however, if the capital contribution required to
be made is being disputed by such Partner in good faith and the Partner
contributes that portion, if any, of the capital contribution not in dispute,
such Partner's right to participate in the management of Partnership affairs
shall not be suspended.
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ARTICLE IX
DISSOLUTION AND LIQUIDATION
9.1 Dissolution. The Partnership shall be dissolved:
(a) upon the expiration of its term as provided in Section 2.4;
(b) upon the approval of a SuperMajority in Interest of the
Partners pursuant to Section 3.5; and
(c) upon any other event that, under this Agreement or Section 4-43-801
of the Act, causes its dissolution, except that an event of withdrawal of a
General Partner shall not cause a dissolution of the Partnership unless there
are no remaining General Partners and the Limited Partners do not appoint a
successor General Partner in accordance with Section 8.5 hereof.
9.2 Liquidation. Upon dissolution of the Partnership, unless the
Partnership is continued pursuant to the provisions of this Agreement, the
Liquidator shall proceed with the winding up of the business and the liquidation
of the Partnership as set forth under Article X.
ARTICLE X
ALLOCATIONS AND DISTRIBUTIONS ON LIQUIDATION
10.1 Liquidation and Termination.
(a) In the event of the dissolution of the Partnership in accordance
with Section 9.1 above, unless the remaining Partners, if any, elect to continue
the business of the Partnership as provided by the terms of this Agreement, the
Liquidator of the Partnership shall proceed with the winding up of the affairs
of the Partnership. Upon the dissolution of the Partnership no further business
shall be conducted, except for such action as shall be necessary for the winding
up of the affairs of the Partnership and the distribution of its assets to the
Partners pursuant to the provisions of this section. The Liquidator may appoint
in writing one or more liquidating trustees who shall have full authority to
wind up the affairs of the Partnership and to make final distribution as
provided herein.
(b) Upon dissolution of the Partnership, the Liquidator may sell any or
all Partnership property at the best price available or it may distribute those
properties in kind at their Gross Asset Values. Any Partner or an Affiliate of a
Partner may purchase Partnership property upon liquidation following thirty (30)
days prior public notice of the proposed sale. The price paid by a Partner or
its Affiliates for any Partnership property shall in no event be less than the
greater of (i) the highest bid received from a third party or (ii) the fair
market value of such property as determined by an independent third party
appraiser.
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(c) The Liquidator shall apply and distribute the assets of the
Partnership as follows:
(i) First, to the payment and discharge of all of the
Partnership's debts and liabilities to creditors, including the Existing Loans
but excluding other debts to the Partners;
(ii) Second, to the payment and discharge of all of the
Partnership's other debts and liabilities to the Partners.
(iii) Third, after giving effect to all contributions,
distributions and allocations for taxable years including the taxable year in
which the liquidation occurs, to the Partners in accordance with the positive
balances in their respective Capital Accounts; and
(iv) The balance, if any, according to the Partners'
respective Partnership Percentages.
10.2 Capital Account Deficits. If any General Partner has a deficit
balance in its Capital Account (after giving effect to all contributions,
distributions and allocations for all taxable years, including the year during
which such liquidation occurs and Sections 10.1(c)(i) through (iii), but
excluding Section 10.1(c)(iv)) at the time of the dissolution and liquidation of
the Partnership, such General Partner shall contribute to the capital of the
Partnership the amount necessary to restore such deficit balance to zero in
compliance with Treas. Reg. ss. 1.704-1(b)(2)(ii)(b)(3). If any Limited Partner
has a deficit balance in its Capital Account (after giving effect to all
contributions, distributions and allocations for all taxable years, including
the year during which such liquidation occurs and Sections 10.1(c)(i) through
(iii), but excluding Section 10.1(c)(iv)) such Limited Partner shall have no
obligation to make any contribution to the capital of the Partnership with
respect to such deficit, and such deficit shall not be considered a debt owed to
the Partnership or to any other Person for any purpose whatsoever.
10.3 Special Distributions. In the discretion of the Liquidator, a
portion of the distributions that would otherwise be made pursuant to this
Article X may be:
(a) distributed to a trust established for the benefit of the Partners
for the purposes of liquidating Partnership assets, collecting amounts owed to
the Partnership, and paying any contingent or unforeseen liabilities or
obligations of the Partnership. The assets of any such trust shall be
distributed to the Partners from time to time, in the reasonable discretion of
the Liquidator, in the same proportions as the amount distributed to such trust
by the Partnership would otherwise have been distributed to the Partners
pursuant to this Agreement; or
(b) withheld to provide a reasonable reserve for Partnership
liabilities (contingent or otherwise) and to reflect the unrealized portion of
any installment obligations owed to the Partnership, provided that such withheld
amounts shall be distributed to the Partners as soon as practicable.
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10.4 Deemed Distribution and Recontribution. Notwithstanding any other
provision of this Article X, in the event the Partnership is liquidated within
the meaning of Treas. Reg. ss. 1. 704- 1(b)(2)(ii)(g) (regarding when a
liquidation occurs) but it has not dissolved pursuant to Section 9.1 hereof, the
Partnership shall not be liquidated, the Partnership's liabilities shall not be
paid or discharged, and the Partnership's affairs shall not be wound up.
Instead, pursuant to Treas. Reg. ss. 1.708-1(b)(1)(iv), the Partnership for
federal income tax purposes shall be deemed to have contributed all of its
property and liabilities to a new partnership in exchange for a partnership
interest in such new partnership pursuant to Treas. Reg. ss. 1.708-1(b)(1)(iv).
Immediately thereafter, the Partnership for federal income tax purposes shall be
deemed to have distributed the interests in the new partnership to the Partners
in proportion to their interests as if the Partnership were liquidated.
ARTICLE XI
CERTIFICATES AND OTHER DOCUMENTS
11.1 Project Leader as Attorney for Partners.
(a) Each Partner hereby constitutes and appoints the Project Leader and
any successor of the Project Leader, the true and lawful attorney of, and in the
name, place and stead of said Partner from time to time:
(i) To make all agreements amending this Agreement, as now or
hereafter amended, that may be appropriate to reflect solely:
(1) A change of the name or the location of the
principal place of business of the Partnership;
(2) The disposal by a Partner of his Partnership
Interest in any manner permitted by this Agreement and any return of the Capital
Contribution of a Partner (or any part thereof), if any, provided for by this
Agreement;
(3) A person becoming a Partner of the
Partnership, as permitted by this Agreement;
(4) A change in any provision of this Agreement
or the exercise by any person of any right or rights thereunder, not requiring
the consent of any Partners; and
(5) The exercise by any person of any right or rights
under this Agreement requiring the consent or approval of all or a portion of
the Partners when the required consent or approval has been given;
(ii) To make such certificates, instruments and documents,
including fictitious business name statements, as may be required by, or may be
appropriate under, the laws of the State
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of Arkansas in connection with the use of the name of the Partnership by the
Partnership and to make such applications and filings to transact business as a
foreign limited partnership in those jurisdictions where the nature of the
Partnership's properties or business makes such action advisable;
(iii) To make such certificates, instruments and documents,
including those referenced in Section 11.2 below, and also including amendments
to this Agreement, as said Partner may be required or as may be appropriate for
said Partner to make, by the laws of any state or other jurisdiction solely to
reflect:
(1) A change of address of such Partner;
(2) Any changes in or amendments to this Agreement or the
Certificate of Limited Partnership, or pertaining to the Partnership, of any
kind referred to in Section 11.1(a); and
(3) Any other changes in or amendments to this Agreement or
the Certificate of Limited Partnership, but only if and when such Partner has
agreed to such other changes or amendments by signing, either personally or by
duly appointed attorney (other than the power of attorney set forth herein), an
agreement amending this Agreement.
(b) Each of such agreements, certificates, instruments and documents
shall be in such form as such attorney and counsel for the Partnership shall
deem appropriate. The powers hereby conferred to make agreements, certificates,
instruments and documents shall be deemed to include the powers to sign,
execute, acknowledge, swear to, verify, deliver, file, record and publish the
same.
(c) Each Partner authorizes such attorney to take any further action
which such attorney shall consider necessary or convenient in connection with
any of the foregoing and hereby gives such attorney full power and authority to
do and perform each and every act and thing whatsoever requisite and necessary
to be done in and about the foregoing as fully as such Partner might or could do
if personally present, and hereby ratifies and confirms all that such attorney
shall lawfully do or cause to be done by virtue hereof.
(d) The powers hereby conferred shall continue from the date such
Partner becomes a Partner in the Partnership until such Partner shall cease to
be a Partner and, being coupled with an interest, shall be irrevocable.
11.2 Making and Filing of Certificate. The Project Leader agrees, when
authorized pursuant to Section 11.1 hereof, or otherwise, to make, file or
record with the Secretary of State of the State of Arkansas or any other
appropriate public authority and (if required) to publish the certificate, any
amendments thereof, and such other certificates, instruments and documents as
may be required or appropriate in connection with the business and affairs of
the Partnership.
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11.3 Cancellation of Certificates Evidencing Partnership Interests. On
the date hereof, the Partners shall surrender to the Project Leader all
outstanding certificates evidencing their Partnership Interests which shall be
canceled. The Partnership shall no longer issue such certificates.
ARTICLE XII
BOOKS OF ACCOUNT, FINANCIAL
STATEMENTS AND FISCAL MATTERS
12.1 Books of Account. The Partners intend that the Partnership shall
be a partnership for federal, state and local income tax purposes and to the
extent possible for federal, state and local income tax purposes each NOARK
Related Entity will be treated as set forth in Treas. Reg. ss.
301.7701-3(b)(1)(ii). Each Partner agrees not to make the election described in
Section 761 (a) of the Code to be excluded from the application of the
provisions of Subchapter K of Chapter I of Subtitle A of the Code. Moreover,
each Partner agrees not to make an election to be excluded from the partnership
provisions of any applicable state or local taxation statute. The Management
Committee shall, to the extent permissible under existing law, for income tax
purposes, keep or cause to be kept on an accrual basis, adequate books of
account of the Partnership wherein there shall be recorded and reflected all of
the Capital Contributions and all of the expenses and transactions of the
Partnership. Such books of account shall be kept at the principal place of
business of the Partnership (or at the place where accounting services for the
Partnership are performed), and each Partner and his authorized representatives
shall have at all times, during reasonable business hours, free access to and
the right to inspect and copy such books of account and all records of the
Partnership, including the right to obtain by mail or to inspect a list of the
names and addresses and Partnership Interests owned by the Partners. All books
and records of the Partnership shall be kept on the basis of an annual
accounting period ending December 31, except for the final accounting period
which shall end on the dissolution or termination of the Partnership without
reconstitution. Accelerated methods of depreciation may be elected by the
Partnership with respect to its assets for purposes of reporting federal or
state taxes.
12.2 Reports and Financial Statements. The Partner who is maintaining
the accounting records of the Partnership shall maintain a system of accounting
established and administered in accordance with Generally Accepted Accounting
Principles and FERC system of accounts, as applicable, shall maintain a
calculation of Capital Accounts according to the terms of this Agreement, and
shall provide the following reports and financial statements to the Partners:
(a) Annual Report. Within ninety (90) days after the end of each
calendar year, (i) a balance sheet as of the end of such calendar year, together
with a statement of income or loss and a statement of changes in cash flows for
the Partnership for such year, (ii) a report summarizing the fees and other
remuneration (including reimbursable expenses) paid by the Partnership to each
of the Partners during the preceding year; and (iii) a statement showing each
Partner's estimated allocation of income, gains, losses and credits for Federal
income tax purposes. The balance sheet
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and financial statements described in clause (i) of this Section 12.2(a) shall
be audited by a nationally recognized certified public accounting firm appointed
by the Management Committee;
(b) Monthly Reports. Within thirty (30) days after the end of each
month, the balance sheet of the Partnership as of the end of such month and the
statement of income of the Partnership for such month and for the period
commencing at the end of the previous fiscal year and ending with the end of
such month, all in reasonable detail; and
(c) Income Tax Information. Within one hundred sixty-five (165) days
after the end of each calendar year, the Partnership will also furnish each
Partner (and each transferee of a Partnership Interest who shall have not become
a Substituted Partner) with the required income tax information based upon the
Partnership's tax return which will be prepared and filed with the Service and
other applicable taxing authorities. Within ninety (90) days after the end of
each calendar year, the Partnership will furnish to each Partner (and each
transferee of a Partnership Interest who shall have not become a Substituted
Partner) an estimate of the required income tax information.
12.3 Tax Returns and Other Reports. The Project Leader, at the
Partnership's expense, shall cause income tax returns for the Partnership to be
prepared and timely filed with the appropriate authorities. The Project Leader,
at Partnership expense, shall cause to be prepared and timely filed, with
appropriate federal and state regulatory and administrative bodies, all reports
required to be filed with such entities under then current applicable laws,
rules and regulations. Such reports shall be prepared on the accounting or
reporting basis required by such regulatory bodies. Any Partner shall be
provided with a copy of any such report upon request without expense to it.
12.4 Fiscal Year. The fiscal year of the Partnership shall begin with
the first day of January and end on the last day of December in each year.
12.5 Bank Accounts, Funds and Assets. The funds of the Partnership
shall be invested in such accounts and investments as described herein and such
funds shall be withdrawn only by the Project Leader or his duly authorized
agents. The Project Leader shall have fiduciary responsibility for the
safekeeping and use of all funds of the Partnership, whether or not in his
immediate possession or control, and he shall not employ such funds or assets in
any manner except for the exclusive benefit of the Partnership.
12.6 Tax Elections. The Partnership shall make the following elections
under the Code and Treasury Regulations and any similar state or local statutes
subject to modification at the direction of the Management Committee (which
modification shall be subject to any applicable Partner approvals required to be
obtained under Section 3.5):
(a) To adopt the calendar year as the annual accounting period,
unless otherwise required by law;
(b) To adopt the accrual method of accounting;
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(c) To compute the allowance for depreciation utilizing the shortest
life and fastest method permissible under the Modified Accelerated Cost Recovery
System under Code ss. 168(j) or other applicable depreciation system;
(d) To amortize start-up expenditures, if any, over a sixty (60) month
period in accordance with Code ss. 195(b) and any similar state statute;
(e) To amortize organization expenses and syndication fees if any, over
a sixty (60) month period in accordance with Code ss. 709(b) and any similar
state statute;
(f) To make such other elections as it may deem advisable to reduce
Partnership (including the NOARK Related Entities) taxable income to the maximum
extent possible and to take deductions in the earliest taxable year possible;
and
(g) To make the election provided under Code ss. 754, upon the request
of any Partner, if there is a distribution of property as described in Code ss.
734 or if there is a transfer of an interest as described in Code ss. 743.
12.7 Other Partnership Records. The Partnership shall keep and maintain
in its principal office all records as required by Section 4-43-105 of the Act.
Such records shall include the following:
(a) A current list that states the name and mailing address of each
Partner, separately identifying in alphabetical order the General Partners and
the Limited Partners;
(b) Copies of the Partnership's federal, state and local information or
income tax returns and copies of the Partnership's financial statements for each
of the Partnership's three most recent years, if applicable;
(c) A copy of the Agreement and the Certificate of Limited Partnership,
all amendments or restatements, executed copies of any powers of attorney under
which the Agreement and the Certificate of Limited Partnership and all
amendments or restatements to the Agreement and the Certificate of Limited
Partnership have been executed; and
(d) A written statement of: (i) all Capital Contributions made to the
Partnership, including cash amounts and a description and statement of the
agreed value of any non-cash Capital Contributions, and similar information with
respect to all Capital Contributions which the Partners have agreed to make in
the future; and (ii) all capital calls issued to the Partners.
Any Partner shall have the right to inspect and, at its own expense, copy and
audit any of the books and records of the Partnership upon giving reasonable
advance notice to the other Partners.
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12.8 Survival of Tax Provision. The provisions of the Agreement
relating to tax matters shall survive the termination of the Agreement and the
termination of any Partner's Partnership Interest and shall remain binding on
that Partner for the period of time necessary to resolve any tax matters
regarding the Partnership with any federal, state and local tax authority.
12.9 Deposit of Funds. Funds of the Partnership shall be deposited in
such banks or other depositories as shall be designated by the Project Leader.
Pending the application of such funds to the cash needs of the Partnership, the
Partnership's funds shall, to the extent practicable, be continuously invested.
Funds of the Partnership may only be placed in the following types of
investments; provided, that such investments shall not preclude the timely
distribution of excess cash; and provided, further, that any investment of
working capital shall not preclude the timely payment of the Partnership's
obligations when and as due:
12.9.1 Cash in the form of U.S. currency.
12.9.2 Evidence of indebtedness, maturing not more than one
year after the date of issue, issued or guaranteed by the United States
of America, or agencies thereof.
12.9.3 Collateralized repurchase agreements in respect of the
obligations described in Section 12.9.2 with the banks in which the
Partnership maintains its operating accounts or with a related trust
company.
12.9.4 Such other investments as the members on the Management
Committee representing the General Partners shall determine by
unanimous decision.
ARTICLE XIII
DISPUTE RESOLUTION
13.1 Invoking Procedure. In the event of a dispute between the Partners
arising out of or related to this Agreement or related to the business or
affairs of the Partnership, or in the event a SuperMajority in Interest of the
Partners do not agree on a matter requiring such approval under Section 3.5 of
this Agreement and such lack of approval results in a Stalemate (as hereinafter
defined in Section 13.2), either Partner may invoke the procedures specified in
this Article by giving written notice to the other Partners. Such written notice
will describe briefly the nature of the dispute, or the matter for which
approval has not been obtained under Section 3.5, and shall identify an
individual with authority to settle such dispute or matter on behalf of that
Partner. The Partner receiving such notice shall have ten (10) days within which
to designate an individual with authority to settle such dispute or matter on
its behalf and to give written notice to the other Partner of its designation
(the individuals so designated shall be referred to as the "Authorized
Individuals"). Unless otherwise notified, the Authorized Individual of each
Partner shall be its President. For purposes of this Section 13.1, any matter
which would otherwise be a Stalemate if a meeting of the Partners had been held
and requisite SuperMajority in Interest approval not obtained, or a proposal
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submitted pursuant to Section 3.4(e) and the requisite SuperMajority in Interest
approval not given, shall be deemed ripe for resolution under this Article XIII
if the proponent has (i) called a meeting of the Partners and has included in
the Agenda included with the notice of the meeting a full and complete
description of the proposal along with all information reasonably required for a
determination or vote by the other Partners(s) and the other Partner(s) does not
attend the meeting and does not, prior to the time scheduled therefor, request a
postponement or adjournment thereof for up to ten days, or if the Partner(s)
requests such a postponement or adjournment but does not attend the postponed
meeting or a new Partner meeting within such ten (10) day period, or (ii)
submitted such proposal to the other Partner(s) for approval pursuant to Section
3.4(e) hereof and such other Partner(s) does not provide such consent within
fifteen (15) days from the later of its receipt of such request or the date that
it shall receive all additional information regarding such proposal that it may
have reasonably requested in a written notice submitted to the proponent not
more than ten (10) days after the receipt of the proponent's request for such
consent.
13.2 Stalemate Defined. For purposes of this Article XIII, a
"Stalemate" shall mean any situation in which one or more proposals have been
submitted to the Partners relating to action reasonably considered by the
proponent to be required to be taken by the Partnership, or the Project Leader
on behalf of the Partnership, in order to avoid or substantially mitigate (i) a
cessation of, or material disruption or impediment in, the conduct of its
ongoing operations and affairs to any material extent, or (ii) potential
material harm or damage to the Partnership, its business, operations, affairs,
properties or other assets, but which proposal or proposals are not able to be
implemented because there has not been an approval thereof by a SuperMajority in
Interest of the Partners as required by Section 3.5. In this regard, the failure
to approve a Budget by the end of the first quarter of a fiscal year to which it
relates and which has been presented to the Partners in material compliance with
Section 3.6(g) hereof shall be considered to be a Stalemate and approval of the
Budget, or specific items thereof which are then in dispute, as then proposed
may be presented for dispute resolution pursuant to this Article XIII.
13.3 Investigation. The Authorized Individuals shall make whatever
investigation each deems appropriate and promptly thereafter, but no later than
thirty (30) days from the date of the original notice invoking these procedures,
shall commence discussions concerning resolution of the dispute or matter. If
the dispute or matter has not been resolved within sixty (60) days from the date
of the original notice invoking these procedures, the Partners shall submit the
dispute or matter to ADR in accordance with the following procedure.
13.4 Neutral. The Partners shall have ten (10) days from the expiration
of the sixty (60) day period referred to in Section 13.2 above, or the agreement
of the Partners, to submit the dispute or matter to ADR, whichever occurs first,
within which to agree upon a mutually acceptable person not affiliated with
either party ("Neutral"). If no Neutral has been selected within that time
period, the Partners agree jointly to request the American Arbitration
Association or other mutually agreed-upon organization, to supply within ten
(10) days a list of at least three (3) potential Neutrals with qualifications as
specified by the Partners in the joint request. Within seven (7) days of receipt
of the
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list, the Partners shall rank the proposed candidates independently, exchange
rankings and select as the Neutral the individual who received the highest
combined ranking who is available to serve.
13.5 Schedule. In consultation with the Neutral, the Partners shall
designate a mutually convenient time and place for the ADR, and unless
circumstances require otherwise, such time shall be not later than forty-five
(45) days after the selection of the Neutral.
13.6 Discovery. In the event one or both Partners have substantial need
for information in the possession of the other Partner or a need to take certain
limited depositions and/or production of principal documents in order to prepare
for the ADR, the Partners shall attempt in good faith to agree on a plan for the
expeditious exchange of such information. Should they fail to reach agreement,
either Partner may request a meeting with the Neutral who shall assist them in
reaching an accommodation.
13.7 Written Submission. One week prior to the first scheduled session
of the ADR, each Partner shall deliver to the Neutral and to the other Partner a
written summary of its views on the dispute or matter in issue. The summary
shall be no longer than twenty (20) double-spaced pages unless the Partners
agree otherwise.
13.8 Representatives. In the ADR, each Partner shall be represented by
the Authorized Individual and by counsel. In addition, each Partner may bring
additional persons as necessary to respond to questions or contribute
information as needed. The number of such additional persons to be allowed shall
be mutually agreed by the Partners with the assistance of the Neutral, if
necessary.
13.9 Structure. The Neutral is authorized to conduct joint and separate
meetings with the Partners and to help the Partners structure whatever form of
presentation of the dispute or matter in issue is most likely to facilitate
resolution. Notwithstanding the form of the presentation, it is the intent of
the Partners to provide an opportunity for their Authorized Individuals, with or
without the assistance of counsel, and with the assistance of the Neutral, to
negotiate a resolution of the dispute or matter in issue. In the event the
Neutral holds separate private caucuses with either Partner, he or she shall
keep confidential all information learned in such private caucuses unless
specifically authorized to make disclosure of the information to the other
Partner. There shall be no stenographic, visual, or audio record made of the
ADR.
13.10 Mandatory. The Partners agree to participate in the ADR to its
conclusion as designated by the Neutral and not to terminate negotiations
concerning resolution of the dispute or matter in issue until at least two (2)
weeks thereafter. Each Partner agrees not to commence arbitration or seek other
remedies prior to the conclusion of the two-week post-ADR negotiation period,
provided that either Partner may commence arbitration on any date after which
the commencement of litigation could be barred by an applicable statute of
limitations or in order to request an injunction to prevent irreparable harm. In
such event, the Partners agree (except as prohibited by court order) to continue
to participate in the ADR to its conclusion.
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13.11 Fees. The fees of, and authorized costs incurred by, the Neutral
shall be advanced by the Partnership and shared equally by the Partners who
shall reimburse the Partnership. The Neutral shall be disqualified as a witness,
consultant, expert, or counsel for any Partner with respect to the dispute or
matter in issue and any related matters.
13.12 Later Proceedings. The ADR is a compromise negotiation for
purposes of the Federal Rules of Evidence and the Rules of Evidence of the State
of Oklahoma. The entire procedure is confidential. All conduct, statements,
promises, offers, views, and opinions, whether oral or written, made in the
course of the ADR by any of the Partners, their agents, employees,
representatives, or other invitees to the ADR and by the Neutral, who is the
parties' joint agent for the purposes of these compromise negotiations, are
confidential and shall, in addition and where appropriate, be deemed to be work
product and privileged. Such conduct, statements, promises, offers, views, and
opinions shall not be discoverable or admissible for any purposes, including
impeachment, in any litigation or other proceeding involving the Partners and
shall not be disclosed to anyone not an agent, employee, expert, witness, or
representative for any of the Partners. Evidence otherwise discoverable or
admissible is not excluded from discovery or admission as a result of its use in
the ADR.
13.13 Dispute Resolution
(a) In the event the Partners are unable to resolve the dispute or
matter in issue in accordance with the foregoing provision of this Article XIII,
the dispute or matter in issue shall be submitted to final and binding
arbitration. The arbitration shall be administered by the American Arbitration
Association ("AAA") in accordance with and in the following order of priority:
(i) the terms of these arbitration provisions; (ii) the Commercial Arbitration
Rules of the AAA; (iii) the Federal Arbitration Act (Title 9 of the United
States Code); (iv) the Oklahoma Uniform Arbitration Act (15 O.S. ss. 801, et
seq.); and (v) to the extent the foregoing are inapplicable, unenforceable or
invalid, the laws of the State of Oklahoma. The validity and enforceability of
these arbitration provisions shall be determined in accordance with the same
order or priority. In the event of any inconsistency between these arbitration
provisions and such rules and statutes, these arbitration provisions shall
control. Judgment upon any award rendered hereunder shall be entered in any
court having jurisdiction thereof, and the parties' consent to the jurisdiction
of any state or federal court in Oklahoma. Commencement of and demand for
arbitration shall be made by written notice by the initiating party (claimant)
to the other party (respondent) which contains a statement of the nature of the
dispute or matter in issue, the amount involved and the relief or remedy sought
("Notice").
(b) The arbitration shall be conducted by a panel of three (3)
arbitrators (the "Arbitration Panel"). Each Partner will nominate one (1)
arbitrator, who is experienced and knowledgeable in the areas involved in the
dispute or matter in issue, within ten (10) working days of their receipt of
Notice that arbitration has been demanded and commenced, and each will notify
the other party of the name of its selected arbitrator within that same time
period. In the case of a matter which is subject to Section 3.5 which results in
a Stalemate, the arbitrator nominated by each Partner shall not be an attorney.
If a Partner refuses to name an arbitrator, application will be made to the
Chief Judge of the United States District Court for the Northern District of
Oklahoma requesting that the
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Chief Judge appoint an arbitrator. If the Chief Judge declines to name an
arbitrator, application will be made to the AAA. The two arbitrators thus
selected will confer within ten (10) working days of their final selection and
agree upon a third arbitrator. If the two arbitrators are unable to agree on a
third arbitrator within sixty (60) working days of their first contact, the
nomination of the third arbitrator will follow the same procedure as the
nomination of a party arbitrator for a party refusing to make a selection. AAA
Rules regarding the selection, qualification, and challenge or arbitrator shall
only apply to the second or third arbitrators if those arbitrators are selected
by the AAA. No member of the Arbitration Panel may be involved in the
controversy, be or have been an officer, director, representative, employee or
agent of or for either party. The third arbitrator shall act as Chairman of the
Arbitration Panel.
(c) The costs and fees of the arbitrators selected by the Partners
shall be borne by the Partners selecting such arbitrator, unless otherwise
awarded by the Arbitration Panel. The costs and fees attributable to the third
arbitrator shall be shared equally by the Partners, unless otherwise awarded by
the Arbitration Panel.
(d) The Arbitration Panel may engage engineers, accountants or other
consultants that the Arbitration Panel deems necessary to render a decision in
the Arbitration Proceeding. All fees of any such consultants shall be borne
equally by the Partners, unless otherwise awarded by the Arbitration Panel.
(e) The arbitration will be governed by the Federal Arbitration Act, 9
U.S.C. ss.ss. et seq., and the Oklahoma Uniform Arbitration Act, 15 Okla. Stat.
ss.ss. 801 et seq. The arbitrators will establish a schedule that will result in
a final arbitration award to be rendered in written form not later than one
hundred eighty (180) days following the appointment of the third arbitrator. The
place of the arbitration shall be Tulsa, Oklahoma.
(f) The Partners agree that pre-arbitration hearing discovery is
necessary. Within twenty (20) working days after the appointment of the third
arbitrator, the Partners agree to exchange lists of the witnesses and exhibits
each then plans to call and use in the Arbitration Hearing. Within twenty (20)
working days after the exchange of witness and exhibit lists, each Partner may
request additional discovery, if any is necessary, from the other Partner. The
Partners agree to respond to any such additional request for documents from the
other Partner within thirty (30) days after receiving such request, and each
agrees to attempt in good faith to schedule the depositions of witnesses
requested by the other side by agreement. If the Partners are unable to agree on
any aspect of discovery requested, such discovery issue shall be presented to
and resolved by the Arbitration Panel.
(g) Any dispute relating to or arising under this arbitration
provision, including interpretation thereof, shall be solely and finally
resolved by submission to the Arbitration Panel.
(h) A written decision by two (2) of the arbitrators will be final and
binding on the Partners. An arbitration award will be in writing and signed by
the arbitrators. An arbitration award
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entered herein can be confirmed by either of the Partners in the United States
District Courts for the Northern or Western Districts of Oklahoma or the Western
District of Arkansas or any state district court for the States of Oklahoma or
Arkansas, and a judgment may be entered on the arbitration award by the same
court.
(i) Punitive damages may not be awarded by the Arbitration Panel. The
Arbitration Panel shall have the power to award recovery to the prevailing party
of all or part of its costs, expenses and attorneys' fees incurred in
conjunction with such Arbitration Proceeding.
(j) The Partners, their Affiliates, employees, contractors, attorneys,
and auditors shall keep the substance of these final and binding arbitration
proceedings confidential to the extent the same is permissible, consistent with
the responsibilities of the attorneys under the pertinent Codes of Professional
Responsibility or obligations which may reasonably require disclosure to
financial institutions, consultants for evaluation purposes or as may be ordered
by the federal or state government or a court of competent jurisdiction. Under
no circumstances shall any documents memorializing the substance of any aspect
of these proceedings be disclosed or released to the newspaper or other media
absent the mutual agreement of the Partners. The Partners will use all
reasonable efforts to obtain protective orders before disclosing any terms of
these proceedings to any federal or state government or a court of competent
jurisdiction.
(k) Except for the internal costs of each party, all costs, fees and
expenses of any portion of this dispute resolution process shall be shared
equally by the Partners, unless otherwise specified herein.
ARTICLE XIV
LIMITATION OF AUTHORITY
Neither the Management Committee, the committees established by the
Management Committee, the Project Leader, nor the Partners shall have any
authority to take any action i) inconsistent with the terms of this Agreement or
ii) which will permit the Securities and Exchange Commission or any other
governmental agency to have jurisdiction with respect to the Partnership or any
Partner under the Public Utility Holding Company Act of 1935, U.S.C. Title 15,
Sections-6.
ARTICLE XV
LIMITATION OF LIABILITIES
No Partner shall be liable to third Persons for Partnership losses,
deficits, liabilities or obligations except as otherwise expressly agreed to in
writing by such Partners, unless the assets of the Partnership shall first be
exhausted; provided, however, that the Limited Partner shall not be
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liable for any of the debts of the Partnership or any of its obligations except
to the extent provided under this Agreement or other applicable law. The
provisions of this Article XV shall not modify or alter the specific obligations
of a Partner under this Agreement or the Omnibus Agreement.
ARTICLE XVI
MISCELLANEOUS
16.1 Notices. Any notice, request, instruction, correspondence or other
document to be given hereunder by any party (herein collectively called
"Notice") shall be in writing and delivered in person or by courier service
requiring acknowledgment of receipt of delivery or mailed by certified mail,
postage prepaid and return receipt requested, or by telecopier, as follows:
if to EAPC,
Enogex Arkansas Pipeline Corporation
600 Central Park Two
515 Central Park Drive
Oklahoma City, OK 73105
Attention: President
Facsimile No.: (405) 557-5205
with copy to (which copy shall not constitute notice to):
Enogex Inc.
600 Central Park Two
515 Central Park Drive
Oklahoma City, OK 73105
Attention: General Counsel
Facsimile No.: (405) 557-5205
if to SWPL,
Southwestern Energy Pipeline Company
c/o Southwestern Energy Services Company
2200 MidContinent Tower
401 S. Boston Ave.
Tulsa, Oklahoma 74103
Attention: Senior Vice President
Facsimile No.: (918) 584-4222
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with copy to (which copy shall not constitute notice to):
Southwestern Energy Company
1083 Sain Street
P.O. Box 1408
Fayetteville, Arkansas 72702-1408
Attention: Executive Vice President -
Finance & Corporate Development
Facsimile No.: (501) 521-1147
if to any other Partner, addressed to the applicable address provided by such
Partner in writing to all other Partners.
Notice given by personal delivery, courier service or mail shall be effective
upon actual receipt. Notice given by telecopier shall be confirmed by
appropriate answer back and shall be effective upon actual receipt if received
during the recipient's normal business hours, or at the beginning of the
recipient's next business day after receipt if not received during the
recipient's normal business hours. All Notices by telecopier shall be confirmed
promptly after transmission in writing by certified mail or personal delivery.
All Notices by mail shall be deemed received on the fifth business day following
the date on which the same is mailed. Any party may change any address to which
Notice is to be given to it by giving Notice as provided above of such change of
address.
16.2 Captions and Pronouns. Any titles or captions or articles or
paragraphs contained in this Agreement are for convenience only and shall not be
deemed part of the context of this Agreement. All pronouns and any variations
thereof shall be deemed to refer to the masculine, feminine, neuter, singular or
plural, as the identification of the person or persons, firm or firms,
corporation or corporations may require.
16.3 Binding Effect. Except as otherwise herein provided, this
Agreement shall be binding upon and inure to the benefit of the parties hereto,
their heirs, executors, administrators, successors and all Persons hereafter
having or holding a Partnership Interest, whether as assignees, Substituted
Partners, or otherwise. Nothing in this Agreement, express or implied, is
intended to confer upon any person or entity other than the parties hereto and
their respective permitted successors and assigns, any rights, benefits or
obligations hereunder.
16.4 Amendment of the Agreement. Except as otherwise provided in this
Agreement, an amendment to this Agreement shall require the unanimous consent of
the Partners.
16.5 Governing Law. THE PROVISIONS OF THIS AGREEMENT SHALL BE GOVERNED
BY AND CONSTRUED AND ENFORCED IN ACCORDANCE WITH THE LAWS OF THE STATE OF
ARKANSAS (EXCLUDING ANY CONFLICTS-OF-LAW RULE OR PRINCIPLE THAT MIGHT REFER SAME
TO THE LAWS OF ANOTHER JURISDICTION), EXCEPT TO THE EXTENT THAT SAME ARE
MANDATORILY SUBJECT TO THE LAWS
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OF ANOTHER JURISDICTION PURSUANT TO THE LAWS OF SUCH OTHER
JURISDICTION.
16.6 Counterparts and Execution. This Agreement may be executed in
multiple counterparts, each of which shall be deemed an original Agreement, and
all of which shall constitute one Agreement, by each of the parties hereto on
the dates respectively indicated in the signatures of said parties,
notwithstanding that all of the parties are not signatories to the original or
to the same counterpart, to be effective as of the day and year hereinabove set
forth.
16.7 Severability. If any provision of this Agreement is held to be
illegal, invalid or unenforceable under present or future state or federal laws
or rules and regulations promulgated thereunder effective during the term
hereof, such provision shall be fully severable, and the Agreement shall be
construed and enforced as if such illegal, invalid or unenforceable provision
had never comprised a part hereof, and the remaining provisions hereof shall
remain in full force and effect and shall not be affected by the illegal,
invalid or unenforceable provision or by its severance herefrom. Furthermore, in
lieu of such illegal, invalid, or unenforceable provision, there shall be
automatically as a part of this Agreement a provision similar in terms to such
illegal, invalid, or unenforceable provision as may be possible and be legal,
valid and enforceable.
16.8 Waiver. None of the requirements of this Agreement may be waived
unless waived in writing by the named party or all parties to this Agreement.
Failure by any party to enforce its rights hereunder shall not subsequently act
as a waiver of those or any other rights. The waiver by any party of a breach of
any provision of this Agreement shall not operate or be construed as a waiver by
such party of any subsequent breach.
16.9 Attorneys' Fees. In any suit to enforce this Agreement, the
prevailing party shall have the right to recover its costs and reasonable
attorneys' fees and expenses, including costs, fees and expenses on appeal if
the finder of facts, including an arbitrator, determines that the non-prevailing
party's arguments were frivolous or substantially without merit.
16.10 Construction. This Agreement was drafted jointly by the Parties,
and no presumption shall operate in favor of or against any Party as a result of
any responsibility that any Party may have had in drafting this Agreement or any
part thereof.
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IN WITNESS WHEREOF, the Partners have executed this Agreement on the
date first set forth above.
GENERAL PARTNERS:
ENOGEX ARKANSAS PIPELINE CORPORATION
By: /s/ ROGER A. FARRELL
----------------------------
Name: Roger A. Farrell
Title: Vice President
SOUTHWESTERN ENERGY PIPELINE
COMPANY
By: /s/ STANLEY D. GREEN
----------------------------
Name: Stanley D. Green
Title: Executive Vice President - Finance & Corporate
Development
LIMITED PARTNER:
ENOGEX ARKANSAS PIPELINE
CORPORATION
By: /s/ ROGER A. FARRELL
----------------------------
Name: Roger A. Farrell
Title: Vice President
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Exhibit A
DESCRIPTION OF
INTERCONNECTION, INTEGRATION AND EXPANSION OF PIPELINE
FACILITIES OF NOARK AND OZARK
Following are capital improvements proposed to combine and expand the
existing Ozark and NOARK systems.
Pipeline
Tie NOARK and Ozark systems together at their farthest west crossing in
Sebastian County, Arkansas. This tie-in would include approximately 600 feet of
10-inch piping, relocation of existing pigging facilities to the terminus of the
10-inch addition and conversion of the existing 10 inch Ft. Chaffee suction line
to interconnect discharge service. This will give the existing NOARK compressor
station in Franklin County, Arkansas a common suction to both systems. The
improvements for this connection will also include appropriate crossover
valving, bypass valving, crossover risers and interconnection site as necessary.
Construct two, 20-inch diameter pipeline segments, approximately 4.75
miles each, to integrate the Ozark and NOARK systems through the existing NOARK
compression. One 20-inch pipeline, which will serve as a suction connection from
Ozark to the NOARK station, will span from the area of milepost 123 on the Ozark
system to the suction of the existing NOARK compression in Franklin County. The
other 20-inch pipeline will follow the same corridor and will serve as a
discharge pipeline back to the existing Ozark system near milepost 123. These
improvements will also include the appropriate block valve, crossover piping,
crossover risers and interconnect site as necessary.
Compression
Upgrade the existing Ozark Lequire compressor station to handle more volume.
Installation of between 7,000 and 11,000 horsepower of additional compression at
the Lequire station, dependent on final design and utilization of existing
turbine compression. Installation to include related station yard piping,
valving, electrical switchgear, and electric facilities as required.
Upgrade the existing NOARK compressor station to handle more volume.
Installation of approximately 13,000 horsepower of additional compression at the
NOARK station. Station manifold and yard piping will be adapted as necessary to
accept the new suction and discharge lines to the Ozark system including 20 inch
pig launcher and receiver facilities. Appropriate valving and piping will also
be added to provide flexibility to discharge into either or both systems.
A-1
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Measurement
Upgrade receipt metering stations to provide additional design receipt capacity
from the existing Enogex and Transok metering points into the Ozark pipeline
system. Facilities to include additional valving, meter tubes and telemetry to
meet AGA standards.
Scada
Upgrade existing Ozark and/or NOARK Scada system(s) to provide interconnect
communication between the Ozark and NOARK pipeline systems consistent with FERC
requirements and sound operating practices.
A-2
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Exhibit B
ACCOUNTING PROCEDURES
TO
AMENDED AND RESTATED AGREEMENT
OF LIMITED PARTNERSHIP OF
NOARK PIPELINE SYSTEM, LIMITED PARTNERSHIP
DATED JANUARY 12, 1998
These Accounting Procedures are a part of, and are to be interpreted
and applied in conjunction with the above referenced Amended and Restated
Agreement of Limited Partnership (the "Partnership Agreement"). To the extent of
any inconsistencies in or conflicts between the provisions of these Accounting
Procedures and the Partnership Agreement, the provisions of the Partnership
Agreement will control.
I.
GENERAL PROVISIONS
1. Statements and Billings
Each Partner shall render all bills and statements to the Partnership
on or before the last day of each month for the costs, expenses and expenditures
for the preceding months. Such bills will be accompanied by a statement of all
charges and credits to the Partnership, including discounts, if any, summarized
by appropriate classifications indicative of the nature thereof.
2. Payment by Partnership
The Partnership shall pay all bills within fifteen (15) days after
receipt thereof. If payment is not made or cash funds are not made available to
the Partnership within such time for amounts owed, the unpaid balance shall bear
interest until paid at one (1) percentage point over the prime rate from time to
time charged by Citibank, N.A., New York, N.Y. to responsible commercial and
industrial borrowers, not in excess of the maximum lawful rate.
3. Adjustments
Payment of any bill shall not prejudice the right of the Partnership to
protest or question the correctness thereof; provided, however, all bills and
statements rendered to the Partnership during any calendar year shall
conclusively be presumed to be true and correct after twenty-four (24) months
following the end of such calendar year, unless prior to the end of said
twenty-four (24) month period the Partnership takes written exception thereto
and makes claim for adjustment. The provisions of this paragraph shall not
prevent adjustments resulting from a physical inventory of the assets of the
Partnership or mathematical errors.
B-1
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4. Audits
Any auditor, inspector or auditing committee appointed by the
Partnership shall have the right to audit the accounts and records of each
Partner relating to the accounting hereunder after due notice and during the
usual working hours.
II.
COSTS, EXPENSES AND EXPENDITURES
Subject to the limitations hereinafter prescribed and the provisions of
the Agreement to which this Accounting Procedures is an exhibit, each Partner
shall charge the Partnership for all costs, expenses and expenditures incurred
by it and its affiliated persons and entities, collectively as though solely its
costs, in connection with the administration, accounting, legal, operation,
maintenance, upkeep, repair, replacement, development, expansion, enlargement,
improvement or abandonment of the System or the Partnership (including any NOARK
Related Entity) (hereinafter referred to as "Operation of the System"),
including the following items:
1. Rentals
All rentals paid or the portion thereof attributable to the Operation
of the System.
2. Labor Costs
A. Salaries and wages of employees engaged in connection with the
Operation of the System, and, in addition, amounts paid as salaries and wages of
others temporarily employed in connection therewith. Employees engaged less than
full time in connection with the Operation of the System shall keep an accurate
daily log of the time spent on behalf of the Partnership contemporaneously with
the work being done, including the specific services rendered. Such log shall be
delivered to the Partnership upon request. Said salaries and wages shall not
exceed the going rate for the technical expertise of the employee so engaged.
B. Costs of holiday, vacation, sickness and jury service benefits and
other customary allowances paid to persons whose salaries and wages are
chargeable under Paragraph 2A of this Part II. Costs under this Paragraph 2B
shall be charged on the basis of a percentage assessment on the amount of
salaries and wages chargeable under Paragraph 2A of this Part II.
C. Expenditures or contributions made pursuant to assessments imposed
by governmental authority which are applicable to salaries, wages and costs
chargeable under Paragraphs 2A and 2B of this Part II. Costs under this
Paragraph 2C shall be charged on the basis of a percentage assessment on the
amount of salaries and wages chargeable under Paragraph 2A of this Part II.
B-2
<PAGE>
D. The costs of plans for employees group life insurance,
hospitalization, disability, pension, retirement, thrift and other benefit
plans, applicable to labor costs chargeable under Paragraph 2A of this Part II.
Costs under this Paragraph 2D shall be charged on the basis of a percentage
assessment on the amount of salaries and wages chargeable under Paragraph 2A of
this Part II.
3. Reimbursable Expenses of Employees
Reasonable personal expenses of employees whose salaries and wages are
chargeable under Paragraph 2A of this Part II. Personal expenses shall include
the usual out-of-pocket expenditures incurred by employees in the performance of
their duties directly related to the Operation of the System and for which such
employees are reimbursed, including without limitation travel, hotel,
transportation and meal expenses.
4. Material, Equipment and Supplies
Material, equipment and supplies purchased or furnished from a
Partner's warehouse or other properties for use in the Operation of the System.
So far as it is reasonable, practical and consistent with efficient and
economical operation, only such material shall be obtained for the Operation of
the System as may be required for immediate use, and the accumulation of surplus
stock shall be avoided.
5. Transportation
Transportation of employees, equipment, material and supplied necessary
for the Operation of the System. However, unless otherwise previously agreed to,
the Management Committee may require that charges for transportation of
equipment, material and supplies furnished from a Partner's warehouse or other
properties be recalculated and reduced if such charges are in excess of the
transportation which would have been charged for movement of property from the
nearest reliable supply store or railroad receiving point.
6. Services
A. The cost of contract services and utilities procured from outside
sources, not to exceed $50,000 per occurrence without the approval of the
Management Committee.
B. Use and service of vehicles, equipment and facilities as
provided in Paragraph 5 of Part III.
7. Legal Expenses and Claims
All costs and expenses of handling, investigating and settling claims
arising by reason of the Operation of the System or necessary to protect or
recover any Partnership (including any
B-3
<PAGE>
NOARK Related Entity) property, including, but not limited to, attorneys' fees,
court costs, costs of investigation or procuring evidence and any judgments paid
or amounts paid in settlement or satisfaction of any such claims. Expenditures
in excess of $50,000 for any single item of cost shall require the approval of
the Management Committee as provided in the Partnership Agreement.
8. Taxes
All taxes of every kind and nature assessed or levied upon or incurred
in connection with the Operation of the System or the Partnership (including any
NOARK Related Entity) property, and which taxes have been paid by a Partner for
the benefit of the Partnership.
9. Insurance
Premiums paid or allocated for insurance carried under this Agreement
for the benefit of the Partners and the Partnership.
10. Permits, Licenses and Bonds
Costs of permits, licenses and bond premiums necessary in the
performance of a Partner's duties.
11. Government Compliance Costs
All costs incurred in connection with the Partnership (including any
NOARK Related Entity) or the System as a result of or in compliance with
governmental or regulatory requirements, including without limitation those
relating to Federal Energy Regulatory Commission regulation and environmental,
health or safety considerations applicable to the System. Such costs may
include, but are not limited to, disposal of wastes, surveys of an ecological or
archaeological nature and pollution prevention or control as required by
applicable legal requirements.
12. Land Right Acquisition Costs
All land right acquisition costs, including those for rights-of-way,
surface leases, permits, fee purchases, etc.
13. Other Costs, Expenses and Expenditures
Any other costs, expenses and expenditures not covered or dealt with in
the foregoing provisions of this Part II which are incurred in the Operation of
the System, not to exceed $50,000 per occurrence without approval of the
Management Committee as provided in the Partnership Agreement.
B-4
<PAGE>
14. Overhead Charges
Each Partner authorized by the Partnership to undertake a capital
project on behalf of the Partnership shall charge an amount as set forth below
as overhead.
A. In connection with all capital expenditures in excess of $50,000 per
project (except the interconnection of the NOARK and the Ozark pipeline systems
and the expansion of those pipeline systems as contemplated by the Omnibus
Agreement and Exhibit I thereto), such Partner shall charge an additional amount
equal to the sum of the amounts obtained by applying the following percentages
to the expenditures for a project monthly as they are incurred:
Project Direct Cost Overhead Percentage
$000 to $2,000,000 5.00%
Costs over $2,000,000 2.00%
The above overhead percentages for capital expenditures do not include
engineering, right-of-way, or other construction services directly attributable
to the project even though performed in the Partner's principal business office.
B. As provided in Section 3.7(d)(i), the Management Committee has
delegated to SWPL the continued performance of the accounting services for the
Partnership. In connection with the provision of those services, SWPL shall
receive an amount equal to $5,000 per month as reimbursements for all overhead
amounts related to the performance of such services. This overhead amount is in
addition to all direct or other costs incurred by SWPL in the performance of
such services and chargeable under these Accounting Procedures; provided under
no circumstances will there be any double collection of costs.
III.
BASIS OF CHARGES
l. Purchases
Material purchased and services procured shall be charged at the price
paid after deduction of all discounts actually received.
2. Material Furnished from a Partner's warehouse or other properties
A. New Material
1. Tubular goods, two inch and over, shall be priced on competitive
bids from at least three suppliers. In addition a Partner shall be permitted to
include loading and unloading costs actually sustained.
B-5
<PAGE>
2. Other material shall be priced at the current replacement cost of
the same kind of material, effective at the date of movement by the Partner and
f.o.b. the supply store or railway receiving point nearest the System where
material of the same kind is available.
3. The Partnership shall be credited with cash discounts applicable to
prices provided for in this Paragraph 2 of Part III.
B. Used Material
1. Used material in sound and serviceable condition and suitable for
reuse shall be priced at seventy-five percent (75%) of the current price of new
material as determined in Paragraph 2A above.
2. Used material which cannot be classified as being in a sound and
serviceable condition and which is no longer suitable for its original purpose,
but usable for some other purpose, shall be priced on the basis comparable with
that of items normally used for such other purpose,
3. Premium Prices
Whenever material is not readily obtainable at the prices contemplated
by a Partner for a project (which project has received all necessary approvals
as provided in this Agreement) because of national emergencies, strikes or other
unusual causes over which such Partner has no control, such Partner may charge
for the required material at the premium price (including the cost of making it
suitable for use and of moving it to the System), provided that further approval
therefor has been obtained from the Management Committee.
4. Warranty of Material Furnished
A Partner shall not be required to warrant any material furnished
beyond, or in addition to, the warranty or guaranty of the manufacturer or its
agent. In the case of defective material, credit shall not be passed to the
Partnership until adjustment from such manufacturer or agent has been received
by the Partner.
5. Equipment and Facilities Furnished
A. A Partner shall charge for the use of its vehicles, equipment and
facilities at rates commensurate with the cost of ownership and operation. Such
rates shall include the cost of operation, maintenance, repairs, insurance,
taxes and other necessary and usual expenses and depreciation. Rates for
automotive equipment shall generally be in line with rates currently prevailing
in the area. Rates for laboratory services shall not exceed those currently
prevailing if performed by outside service laboratories. Rates for trucks and
tractors may include wages and expenses of the operators of such trucks and
tractors.
B-6
<PAGE>
B. When requested, a Partner shall inform the Management Committee in
advance of the rates it proposes to charge.
C. Rates shall be revised and adjusted from time to time when found to
be either insufficient or excessive by the Management Committee.
Any other provision of this Article III notwithstanding, all
materials furnished from a Partner's warehouse for an amount in excess of $5,000
per item shall be billed on the basis of competitive bids obtained from at least
three (3) suppliers in the System area.
IV.
DISPOSAL OF MATERIAL
A Partner may purchase, but shall be under no obligation to purchase,
the interest of the Partnership in material which has become surplus material.
The disposition of such surplus material, if not purchased by a Partner, shall
be subject to disposition as directed by the Management Committee, provided,
that, the Project Leader shall dispose of normal accumulations of junk scrap
material. The Project Leader will give notice to the Management Committee of
surplus materials for sale. In connection with the disposal of surplus material,
the following provisions shall apply:
1. Material Purchased by a Partner
Material purchased by a Partner shall be paid for by such Partner in
the month in which the material is removed by such Partner.
2. Sales to Outsiders
Sales of material to outsiders shall be credited by the Project Leader
to the Partnership at the net amount collected by the Project Leader from
vendee. The Project Leader shall take all reasonable and necessary steps to
collect such proceeds. Any claim by vendee related to such sale shall be charged
back to the Partnership if and when paid.
V.
BASIS OF PRICING SURPLUS MATERIAL
TRANSFERRED TO A PARTNER
Material purchased by a Partner, unless otherwise agreed to between
such Partner and the Management Committee, shall be priced after taking at least
three (3) competitive bids on the following basis:
B-7
<PAGE>
1. New Price Defined
New price as used in this Part V shall be the price determined for new
material in Part III.
2. New Material
New Material, being material procured for the System but never used -
at one hundred percent (100%) of current new price (plus sales tax, if any).
3. Used Material
A. Used material which is in sound and serviceable condition and
suitable for reuse at seventy-five percent (75%) of current new price or at such
lesser amount as is agreed upon by the parties.
B. Used material which cannot be classified as being in a sound and
serviceable condition and which is no longer suitable for its original purpose,
but usable for some other purpose - at a price comparable with that of items
normally used for such other purpose, or at such lesser amounts as is agreed
upon by the parties.
C. Junk material, being obsolete and scrap material - at prevailing
prices.
4. Temporarily Used Material
When new material has been used for less than one (1) year and its
service to the System does not justify the reduction in price contemplated by
Paragraph 3 of this Part V, such material shall be priced on a basis that will
leave a net charge to the Partner consistent with the value of the service
rendered.
B-8
<PAGE>
Schedule 4.1
Initial Capital Account Balances
Partner Capital Account Balance
SWPL ($12,000,000)
EAPC ($ 8,000,000)
<PAGE>
Schedule 5.4(a)
Special Revenue Allocation Base Amounts
Fiscal Year Base Amount *
1998 $1,345,800
1999 $1,284,600
2000 $1,225,750
2001 $1,164,400
2002 $1,103,050
2003 $1,045,300
2004 $ 979,100
2005 $ 919,000
2006 $ 857,700
2007 $ 796,300
2008 $ 736,750
2009 $ 672,900
* If a fiscal year is less than 12 months, the Base Amount for such
fiscal year shall be reduced proportionately. For example, if the 1998
fiscal year is 6 months, the Base Amount of $1,345,800 would be reduced
to $672,900.
<PAGE>
Schedule 5.4(b)
Supply Receipt Points on NOARK Pipeline System
Receipt Meter Mile Post
- ------------- ---------
00010 Ft. Chaffee 0.0
00011 SES 0.0
00020 AOG/Prairie 5.7
00021 Kengla/Freedom 5.7
00022 AOG/Lavaca 0.0
00030 Brashears 25.3
00050 AWG 26.3
00060 Huck C.P. 14.4
00070 Dickerson #5 19.5
00101 Xeric 98.6
XXXX AWG (P-282) 21.5
<PAGE>
Schedule 5.4(d)
Example 1
Special Revenue Allocation
Year: 2001
Avg. Daily Quantity of Gas: 275,000 MMBtu per day
Firm Quantity: 175,000 MMBtu per day
Avg. Margin for all other Volume: $0.20/MMBtu
Base Amount = $1,164,400
Increased Volume Amount = (a) - (b)
(a) 275,000 - 175,000 = 100,000 MMBtu per day
times 25% x $0.20 x 365 days per year
= $1,825,000
(b) 244,000 - 175,000 = 69,000 MMBtu per day
times $0.04 x 365 days per year
= $1,007,400
Allocation Amount = $1,164,400 - ($1,825,000 - $1,007,400)
= $1,164,400 - $817,600
$346,800
<PAGE>
Schedule 5.4(d)
Example 2
Special Revenue Allocation
Year: 1999
Avg. Daily Quantity of Gas: 275,000 MMBtu per day
Firm Quantity: 125,000 MMBtu per day
Avg. Margin for all other Volume: $0.15/MMBtu
Base Amount = $1,284,600
Increased Volume Amount = (a) - (b)
(a) 275,000 - 125,000 = 150,000 MMBtu per day
times 25% x $0.16 x 365 days per year
= $2,190,000
(b) 244,000 - 125,000 = 119,000 MMBtu per day
times $0.04 x 365 days per year
= $1,737,400
Allocation Amount = $1,284,600 - ($2,190,000 - $1,737,400)
= $1,284,600 - $452,600
$832,000
<PAGE>
Schedule 5.4(d)
Example 3
Special Revenue Allocation
Year: 2001
Avg. Daily Quantity of Gas: 220,000 MMBtu per day
Firm Quantity: 160,000 MMBtu per day
Avg. Margin for all other Volume: $0.18/MMBtu
Base Amount = $1,164,400
Increased Volume Amount = (a) - (b)
(a) 244,000 - 160,000 = 84,000 MMBtu per day
times 25% x $0.18 x 365 days per year
= $1,379,700
(b) 244,000 - 160,000 = 84,000 MMBtu per day
times $0.04 x 365 days per year
= $1,226,400
Allocation Amount = $1,164,400 - ($1,379,700 - $1,226,400)
= $1,164,400 - $153,300
$1,011,100
<PAGE>
Schedule 5.4(d)
Example 4
Special Revenue Allocation
Year: 1999
Avg. Daily Quantity of Gas: 300,000 MMBtu per day
Firm Quantity: 125,000 MMBtu per day
Avg. Margin for all other Volume: $0.20/MMBtu
Base Amount = $1,284,600
Increased Volume Amount = (a) - (b)
(a) 300,000 - 125,000 = 175,000 MMBtu per day
times 25% x $0.20 x 365 days per year
= $3,193,750
(b) 244,000 - 125,000 = 119,000 MMBtu per day
times $0.04 x 365 days per year
= $1,737,400
Allocation Amount = $1,284,600 - ($3,193,750 - $1,737,400)
= $1,284,600 - $1,456,350
-0-
<PAGE>
Schedule 5.4(d)
Example 5
Special Revenue Allocation
Year: 2001
Avg. Daily Quantity of Gas: 220,000 MMBtu per day
Firm Quantity: 180,000 MMBtu per day
Avg. Margin for all other Volume: $0.14/MMBtu
Base Amount = $1,164,400
Increased Volume Amount = (a) - (b)
(a) 244,000 - 180,000 = 64,000 MMBtu per day
times 25% x $0.16 x 365 days per year
= $934,400
(b) 244,000 - 180,000 = 64,000 MMBtu per day
times $0.04 x 365 days per year
= $934,400
Allocation Amount = $1,164,400 - ($934,400 - $934,400)
= $1,164,400 - $0
$1,164,400
<PAGE>
Schedule 6.3(d)
Insurance
Primary Insurance. Unless otherwise determined by a SuperMajority in
Interest of the Partners, the following insurance shall be carried and
maintained in force for the benefit of the Partnership, the Project Leader and
the Partners.
1. Workmen's Compensation with Statutory Limits and Employer's
Liability Insurance with $1,000,000 per accident or occupational disease
covering employees engaged in connection with the Partnership or the System, in
compliance with the laws of the State of Oklahoma and Arkansas, as applicable.
2. Comprehensive General Liability Insurance in connection with the
Partnership and the System, with bodily injury and death limits of $500,000 for
injury to or the death of one person and $1,000,000 for the death or injury of
more than one person in one occurrence and property damage limits of $1,000,000
for each occurrence.
3. Automobile Public Liability Insurance with bodily injury or death
and property damage in an amount of at least $1,000,000 combined single limit.
4. Excess Comprehensive General Liability Coverage (including
automobile) in excess of the primary limits of Paragraphs 2 and 3 with limits
which are approved by the Partnership.
5. All risk property coverage in an amount of not less than
$50,000,000.
Other Insurance. If requested by the Management Committee and if
available, the following insurance shall be procured on behalf of the
Partnership, the Project Leader and the Partners, and maintained in force for
the benefit of the Partnership, the Project Leader and the Partners; fire and
extended coverage insurance or all risk insurance and other forms of insurance
upon the Partnership and the System, upon the gas it handles and upon operations
pertaining to the Partnership or the System, in such amounts as the Management
Committee may request.
Requirements Relating to Policy. The Partnership, the Project Leader
and the Partners, shall be named insurers on all policies obtained in
satisfaction of this Schedule 6.3(d), and shall be provided with copies of the
policies. All such insurance policies shall provide for material change or
cancellation only after thirty (30) days written notice.
Waiver of Recovery. With respect to claims and losses for damage,
injury or destruction of property, which is a part of the Partnership or the
System and is covered by insurance other than insurance provided for in the
first paragraph of this Schedule 6.3(d), it is agreed that neither the
Partnership, nor the Partners, nor the insurers of either of them, shall have
any right of recovery against the other, and their rights of recovery are
mutually waived, except in cases of gross negligence or willful neglect. All
such policies of insurance purchased to cover the Partnership or the System or
any part thereof or any interest in the Partnership or the System or in any part
thereof, or the Operation of the System or any part thereof, or any gas
transported or handled therein, shall be properly endorsed to effectuate this
waiver of recovery; provided, no such endorsement shall be required if such
policies provide for such waivers if such waivers are in writing and made prior
to a claim or loss.
<PAGE>
Schedule 6.3(d) (continued)
Insurance
Purchase of Insurance.
1. All insurance under the above headings of Primary Insurance and
Other Insurance shall be purchased by the Partnership, and not by one of the
Partners for the Partnership, unless a Partner is agreeable to purchasing such
insurance and a SuperMajority in Interest of the Partners authorizes such
Partner to acquire such insurance. In such event, such Partner shall be
reimbursed for the cost of such insurance pursuant to the Accounting Procedures.
2. Any Partner shall have the right to purchase insurance, at its
expense without reimbursement from the Partnership, to cover the System, the
Partnership and/or its interest in the Partnership.
DLG-6666.5I
<PAGE>
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 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 1997 presentation. These reclassifications had no
effect on previously reported net income.
Results of Operations
Net income in 1997 was $18.7 million, or $.76 per share, down from $19.2
million, or $.78 per share, in 1996. Net income in 1995 was $11.2 million, or
$.45 per share. During 1997, the benefit of higher gas prices and a utility rate
increase was more than offset by increased depreciation, depletion and
amortization expense (DD&A) and higher interest costs, resulting in the slight
drop in earnings. The increase in 1996 earnings, as compared to 1995, was due to
improved natural gas prices and increased deliveries in the gas distribution
segment that resulted from colder weather and customer growth. Revenues and
operating income for the Company's major business segments are shown in the
following table.
<TABLE>
<CAPTION>
1997 1996 1995
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Revenues
Exploration and production $100,129 $ 86,978 $ 63,285
Gas distribution 154,538 143,141 119,855
Energy services and other 83,128 30,225 31,219
Eliminations (61,606) (57,004) (47,534)
- --------------------------------------------------------------------------------
$276,189 $203,340 $166,825
================================================================================
Operating Income
Exploration and production $ 33,303 $ 34,184 $ 20,111
Gas distribution 17,152 14,223 10,833
Energy services and other 1,481 (411) 244
- --------------------------------------------------------------------------------
$ 51,936 $ 47,996 $ 31,188
================================================================================
</TABLE>
Exploration and Production
The Company's exploration and production revenues increased 15% in 1997 and
37% in 1996. The increase in 1997 was due to higher average gas prices and an
increase in the Company's oil production. The increase in 1996 was primarily the
result of higher average gas prices and increased sales of gas to the Company's
gas distribution segment.
Operating income of the exploration and production segment was $33.3
million in 1997, down 3% from $34.2 million in 1996. Operating income was $20.1
million in 1995. During 1997, higher DD&A expense offset the effect of improved
gas pricing and higher oil production.
Gas production decreased to 33.4 billion cubic feet (Bcf) in 1997 from 34.8
Bcf in 1996. Gas production was 34.5 Bcf in 1995. A decrease in sales to the
Company's gas distribution systems in 1997 was partially offset by an increase
in sales to unaffiliated purchasers. The production increase in 1996 resulted
from increased sales to the Company's gas distribution systems, partially offset
by a reduction in sales to unaffiliated purchasers.
<TABLE>
<CAPTION>
1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas Production
Affiliated sales (Bcf) 14.3 16.3 13.9
Unaffiliated sales (Bcf) 19.1 18.5 20.6
- --------------------------------------------------------------------------------
33.4 34.8 34.5
- --------------------------------------------------------------------------------
Average price per Mcf $2.57 $2.26 $1.72
================================================================================
Oil Production
Unaffiliated sales (MBbls) 749 391 229
- --------------------------------------------------------------------------------
Average price per Bbl $19.02 $21.21 $17.15
================================================================================
</TABLE>
Gas sales to unaffiliated purchasers were 19.1 Bcf in 1997, up from 18.5
Bcf in 1996 and down from 20.6 Bcf in 1995. Gas production during 1997 from
producing properties acquired in late 1996 and from drilling in New Mexico more
than offset normal declines in production from the Company's other properties.
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
8.6 Bcf in 1997, 10.1 Bcf in 1996, and 8.5 Bcf in 1995. Colder weather in early
1996, along with the resulting need for injections to replenish the utility's
storage facilities, caused higher demand for gas supply by AWG that year. The
Company's gas production provided approximately 64% of AWG's requirements in
1997, 62% in 1996, and 65% in 1995. Most of the sales to AWG's system are
pursuant to a long-term contract entered into in 1978 which was amended and
restated in 1994 as a result of the Gas Cost Settlement, discussed more fully
below under "Regulatory Matters." The sales price under this contract averaged
$3.35 per thousand cubic feet (Mcf) in 1997, $3.03 per Mcf in 1996, and $2.40
per Mcf in 1995. This contract expires July 24, 1998. In March, 1997, AWG filed
a gas supply plan with the Arkansas Public Service Commission (APSC) which
projects system load growth patterns and long range gas supply needs for the
utility's northwest Arkansas system. As part of its long range supply plan, AWG
has proposed to enter into a new intersegment gas supply contract for a similar
portion of its system needs at a price competitive with the cost of alternative
supplies. The APSC has not yet approved AWG's gas supply plan. The Company
expects that the volumes will continue to be sold to AWG. However, it is
possible that the APSC may reject AWG's gas supply plan and require that the gas
supply now provided under this contract be replaced through a competitive
bidding process involving multiple potential suppliers. If this occurs, SEECO's
continued sales of these volumes to AWG, and the price of any such sales, will
depend on the result of this competitive
23
<PAGE>
bidding process. Other sales to AWG are made under long-term contracts with
flexible pricing provisions.
The Company's intersegment sales to Associated Natural Gas Company
(Associated), a division of AWG which operates the Company's natural gas
distribution systems in northeast Arkansas and parts of Missouri, were 5.7 Bcf
in 1997, 6.2 Bcf in 1996, and 5.4 Bcf in 1995. Deliveries to Associated
decreased in 1997 and increased in 1996 due primarily to corresponding changes
in heating weather. Effective October, 1990, one of the Company's exploration
and production subsidiaries entered into a ten-year contract with Associated to
supply a portion of its system requirements at a price to be redetermined
annually. The sales price under this contract was $2.20 per Mcf for the contract
period ended September 30, 1995, $1.785 per Mcf for the contract period ended
September 30, 1996, and $2.225 per Mcf for the contract period ended September
30, 1997. 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. The sales price under the contract was $2.54 for the month of
December, 1997.
The overall average price received at the wellhead for the Company's gas
production was $2.57 per Mcf in 1997, $2.26 per Mcf in 1996, and $1.72 per Mcf
in 1995. The increase in the average price received since 1995 primarily
reflects changes in average annual spot market prices and an increase in the
proportionate share of the Company's production sold at spot market prices and
under long-term contracts with market-sensitive pricing.
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 expects the average
price it receives for its total gas production to be generally higher than
average spot market prices due to the prices it receives under the contracts
covering its intersegment sales which are long-term and 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.
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 which will continue to be developed and evaluated in the future.
The Company's exploration programs have been directed primarily toward natural
gas in recent years. The Company will continue to concentrate on developing and
acquiring gas reserves, but will also selectively seek opportunities to
participate in projects oriented toward oil production.
Oil production during 1997 totaled 749,000 barrels, up from 391,000 barrels
in 1996 and 229,000 barrels in 1995. The increase in 1997 oil production
resulted from the Company's acquisition of oil and gas properties owned by L.B.
Simmons Energy, Inc. (Simmons). The acquisition was effective November 1, 1996,
and added proved reserves of 6 million barrels of oil and 17 Bcf of gas.
Gas Distribution
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 by 8% in 1997 and by 19% in 1996. The
increase in 1997 resulted from an increase in the average utility rate caused by
higher gas prices and a rate increase implemented in late 1996. The increase in
1996 was due both to an increase in the average utility rate caused by higher
gas prices and weather which was 6% colder than in 1995.
Operating income for Southwestern's utility systems increased 21% in 1997
and by 31% in 1996. The increase in 1997 was the result of the full year effect
of a $5.1 million annual rate increase implemented in late 1996 for the
utility's northwest Arkansas system and customer growth of 2% which more than
offset lower deliveries resulting from warmer weather. The increase in 1996 was
primarily caused by colder weather.
<TABLE>
<CAPTION>
1997 1996 1995
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Gas Distribution Systems
Throughput (Bcf)
Sales volumes 27.6 29.9 27.4
Transportation volumes
End-use 6.6 5.5 5.2
Off-system 2.8 3.6 9.8
- --------------------------------------------------------------------------------
37.0 39.0 42.4
- --------------------------------------------------------------------------------
Average number of sales customers 172,200 168,568 164,672
- --------------------------------------------------------------------------------
Heating weather
Degree days 4,131 4,341 4,064
Percent of normal 103% 108% 102%
- --------------------------------------------------------------------------------
Average sales rate per Mcf $5.36 $4.57 $4.12
================================================================================
</TABLE>
In 1997, AWG sold 17.4 Bcf to its customers at an average rate of $5.34 per
Mcf, compared to 18.8 Bcf at $4.40 per Mcf in 1996 and 17.1 Bcf at $3.93 per Mcf
in 1995. Additionally, AWG transported 5.0 Bcf in 1997, 4.2 Bcf in 1996, and 4.3
Bcf in 1995 for its end-use customers. Associated sold 10.2 Bcf to its customers
in 1997 at an average rate of $5.39 per Mcf, compared to 11.1 Bcf in 1996 at
$4.87 per Mcf and 10.3 Bcf at $4.45 per Mcf in 1995. Associated transported 1.6
Bcf for its end-use customers in 1997, compared to 1.3 Bcf in 1996 and .9 Bcf in
1995. The decrease in the combined volumes sold and transported in 1997, as
compared to 1996, for both AWG and Associated resulted from warmer weather,
partially offset by increases in the average number of customers. The
fluctuations in the average sales rates reflect changes in the average cost of
gas purchased for delivery to the
24
<PAGE>
Company's customers, which are passed through to customers under automatic
adjustment clauses, and a rate increase for AWG that was implemented December,
1996.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, were 13.2 Bcf in both 1997 and 1996 and 13.0 Bcf in
1995. AWG also transported 2.8 Bcf of gas through its gathering system in 1997
for off-system deliveries, all to the NOARK Pipeline System (NOARK), compared to
3.6 Bcf in 1996 and 9.8 Bcf in 1995. The decreases in off-system deliveries in
1997 and 1996 were due to the on-system demands of the Company's gas
distribution systems resulting from the colder than normal weather combined with
normal production declines in the area served by the utility's gathering system.
The average transportation rate was approximately $.16 per Mcf, exclusive of
fuel, in 1997 and 1996, and $.13 in 1995.
Gas distribution revenues in future years will be impacted by both customer
growth and rate increases allowed by regulatory commissions. In recent years,
AWG has experienced customer growth of approximately 3% to 4% annually, while
Associated has experienced customer growth of approximately 1% annually. Based
on current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue. In December, 1996, AWG
received approval from the APSC for a rate increase of $5.1 million annually.
The Company received approvals in December, 1997, from the APSC and the Missouri
Public Service Commission (MPSC) for rate increases and tariff changes which
will 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 will
review these gathering costs annually as part of its annual 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 plans to appeal this issue to the courts and intends to bill its
ratepayers gas gathering costs based on its cost of service until the matter is
resolved.
If usage of the Company's gathering system to obtain system gas supply or
to source gas delivered to its industrial customers should decrease, then
recovery of these gathering costs would decrease as well. Gathering costs have
been recovered in this manner from Missouri customers since Associated's 1990
rate case. Prior to the current changes, Associated's gathering costs were
recovered from Arkansas customers through its base rates.
Tariffs implemented in Arkansas as a result of both the 1996 and 1997 rate
increases 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
investments in property, plant and equipment.
Energy Services
Operating income for the energy services segment was $1.3 million on
revenues of $82.8 million in 1997, compared to a loss of $.5 million on revenues
of $30.0 million in 1996, and income of $.1 million on revenues of $31.0 million
in 1995. The Company increased its marketing activities when it formed an energy
services group in mid-1996 to better enable the Company to capture downstream
opportunities which arise through marketing and transportation activity. The
Company marketed 36.2 Bcf in 1997, compared to 13.0 Bcf in 1996 and 19.9 Bcf in
1995. 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).
A portion of the activity of the energy services segment involves the NOARK
Pipeline System, Limited Partnership. At December 31, 1997, the Company held a
48% general partnership interest in NOARK. NOARK is a 258-mile long intrastate
gas transmission system which extends across northern Arkansas, crossing three
major interstate pipelines and interconnecting with the Company's distribution
systems. NOARK has 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 for NOARK included in other income was $4.5 million in 1997,
$3.8 million in 1996, and $.7 million in 1995. The 1995 pretax loss included
$2.9 million of income for the Company's share of a $6.0 million settlement of
contract issues with one of NOARK's transporters. Deliveries are currently being
made by NOARK to portions of AWG's distribution system, to Associated, and to
the interstate pipelines with which NOARK interconnects. In 1997, NOARK had an
average daily throughput of 39.8 million cubic feet of gas per day (MMcfd),
compared to 57.5 MMcfd in 1996, and 86 MMcfd in 1995. NOARK has a total
transportation capacity of approximately 141 MMcfd. AWG has a transportation
contract with NOARK for 52.3 MMcfd of firm capacity. The contract expires in
2002 and is renewable annually thereafter until terminated with 180 days'
notice.
The APSC currently regulates NOARK and has established a maximum
transportation rate of approximately $.285 per dekatherm based on its original
construction cost estimate of approximately $73 million. Due to construction
conditions and the addition of a compressor station, the ultimate cost of the
pipeline exceeded the original estimate by approximately $30 million. NOARK's
operating performance has also been negatively impacted by a lack of access to
adequate gas supplies.
As a result of the continuing losses from its investment in NOARK, the
Company investigated various options to improve the financial prospects of the
venture, including an extension
25
<PAGE>
to Oklahoma which would access additional gas supply. 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 the integration of NOARK with the Ozark Gas Transmission System
(Ozark). Ozark is a 437-mile interstate pipeline system which begins near
McAlester, Oklahoma and terminates near Searcy, Arkansas. Ozark has a throughput
capacity of approximately 170 MMcfd. Enogex has entered into an agreement to
acquire Ozark from NGC Corporation for $55.0 million and will contribute Ozark
to the NOARK partnership when regulatory approvals are obtained. Enogex has also
acquired the NOARK partnership interests not held by Southwestern. Subject to
approval by the Federal Energy Regulatory Commission, NOARK will be converted to
an interstate pipeline and be operated with Ozark as an integrated system.
In addition to its purchase of Ozark, Enogex will fund the integration
project and an expansion of the combined system at an estimated cost of $15
million. The two pipelines have a minor interconnection and run in general
proximity to each other in western Arkansas, but a larger interconnecting
pipeline and compression will be constructed to enable the Ozark line in
Oklahoma to serve as the supply line for both NOARK and Ozark. The combined
pipelines will have capacity of approximately 330 MMcfd. The integrated system
is expected to be operational in late 1998.
After the integration is complete, Southwestern will have a 25% interest in
the expanded project and Enogex will have a 75% interest. As further explained
in Note 12 to 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 NOARK. As a part of the transaction with Enogex,
$50.4 million of NOARK's 9.74% Senior Secured Notes were prepaid and refinanced
with an interim loan from Enogex. The partners plan to refinance the interim
loan on a permanent basis before the end of 1998. The Company's interest will
continue to bear 60% of the debt service on the existing level of NOARK debt
after its refinancing. 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 eliminate 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.
Regulatory Matters
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 is to begin in 1998 in accordance with a procedural
schedule established by the APSC.
During 1994, the Company entered into a settlement with the Staff of the
APSC and the Office of the Attorney General of the State of Arkansas to resolve
a dispute concerning the Company's pricing of intersegment sales (the Gas Cost
Settlement). The issues involved the price of gas sold under a long-term
contract between AWG and one of the Company's gas producing subsidiaries. The
Gas Cost Settlement, which was effective July 1, 1994, increased the volumes
which could be sold by the Company's exploration and production segment to AWG,
but made the sales price equal to a spot market index plus a premium. The
amended contract provides that volumes equal to the historical level of sales
under the contract be sold at the spot market index plus a premium of $.95 per
Mcf, while incremental sales volumes receive a premium of $.50 per Mcf. As
discussed above in "Exploration and Production," this contract expires July 24,
1998. While the APSC has not yet approved a gas supply plan submitted by AWG to
address the expiration of this contract, the Company anticipates that the
volumes will continue to be sold to AWG. In 1997, approximately 8.2 Bcf (net to
the Company's interest) was sold under the existing contract, compared to
approximately 8.6 Bcf and 7.7 Bcf in 1996 and 1995, respectively.
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. Such exposure has increased in
recent years as a result of a decline in its gas purchase requirements which has
occurred as some of its large business customers converted to a transportation
service offered by AWG and began to obtain their own gas supplies directly from
other sources. The Company expects to be able to continue to satisfactorily
manage its exposure to take-or-pay liabilities.
Operating Costs and Expenses
The Company's operating costs and expenses, exclusive of gas purchases by
the Company's utility and marketing segments, increased by 16% in both 1997 and
1996. The increases in both years were due primarily to increases in operating
and general expenses, and depreciation, depletion and amortization expense.
Increased operating and general expenses primarily relate to the Company's
exploration and production segment. The higher costs in large part represent
increased operating costs associated with the Company's expansion into areas
outside of Arkansas. During 1997, production costs associated with certain oil
properties acquired in November, 1996 accounted for most of the increase in
operating expense. General and administrative expenses have increased in 1997
and 1996 due to inflationary increases in payroll and other costs and from
personnel additions. The increase in DD&A expense for both 1997 and 1996 was
primarily due to an increase in the amortization rate per unit of production in
the exploration and production segment.
The Company follows the full cost method of accounting for the exploration,
development, and acquisition of oil and gas properties. DD&A is calculated using
the units-of-production method. The Company's annual gas and oil production, as
well as the amount of proved reserves owned by the Company and the costs
associated with adding those reserves, are all components of the amortization
calculation. The DD&A rate in 1997 was $1.06 per Mcfe, up from $.95
26
<PAGE>
per Mcfe in 1996 and $.82 per Mcfe in 1995. The increases in the Company's
amortization rate were caused by increases in the Company's average finding
costs. The Company's full cost ceiling is evaluated at the end of each quarter.
Market prices, production rates, levels of reserves, and the evaluation of costs
excluded from amortization all influence the calculation of the full cost
ceiling. A decline in oil and gas prices from year-end 1997 levels or other
factors, without other mitigating circumstances, could cause a future write-down
of capitalized costs and a noncash charge against future earnings.
Gas purchased for resale by the Company's marketing segment increased to
$63.1 million in 1997, compared to $14.1 million in 1996 and $13.7 million in
1995, due to an increase in volumes marketed and higher per unit gas costs.
Increases in purchased gas costs for the Company's gas distribution segment in
both 1997 and 1996 were due primarily to higher per unit gas costs. Purchased
gas costs for the gas distribution segment are influenced primarily by changes
in requirements for gas sales, the price and mix of gas purchased, and the
timing of recoveries of deferred purchased gas costs.
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 1997 the impact of inflation intensified in the Company's
exploration and production segment as shortages in drilling rigs, third party
services and qualified labor increased. Increased competition in south Louisiana
also had the impact of increasing 3-D seismic and land costs in the area.
Additionally, delays inherent in the rate-making process prevent the Company
from obtaining immediate recovery of increased operating costs of its gas
distribution segment.
Other Costs and Expenses
Interest costs, net of capitalization, were up 26% in 1997 and 17% in 1996,
both as compared to prior years, due to increases in long-term debt. The
increases in long-term debt are discussed below in "Liquidity and Capital
Resources." Interest capitalized increased 8% in 1997 and 69% in 1996. The
increase in 1996 was due primarily to higher capital expenditures in 1996 and
1995 in the exploration and production segment where interest is capitalized on
costs excluded from amortization.
The changes in other income in 1997 and 1996, as compared to 1995, relate
primarily to increases in the Company's share of operating losses incurred by
NOARK as discussed above.
The Company's primary information processing systems are currently year
2000 compliant, or upgraded versions that are year 2000 compliant will be
implemented during 1998 at no additional cost to the Company. The Company is
currently in the process of evaluating its remaining information tech-nology
infrastructure for year 2000 compliance. It does not expect the cost to modify
the technology infrastructure to obtain year 2000 compliance to be material to
its financial condition or results of operations, nor does it anticipate any
material disruption in its operations as a result of any year 2000
noncompliance.
Liquidity and Capital Resources
The Company continues to depend principally on internally generated funds
as its major source of liquidity. However, the Company has sufficient ability to
borrow additional funds to meet its short-term seasonal needs for cash, to
finance a portion of its routine spending, if necessary, or to finance other
extraordinary investment opportunities which might arise. In 1997, 1996, and
1995, net cash provided from operating activities totaled $75.4 million, $67.6
million, and $55.9 million, respectively. The primary components of cash
generated from operations are net income, depreciation, depletion and
amortization, and the provision for deferred income taxes. Net cash from
operating activities provided 75% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1997, 77% in 1996, and 59% in 1995.
Capital Expenditures
Capital expenditures totaled $88.8 million in 1997, $124.9 million in 1996,
and $101.6 million in 1995. The Company's exploration and production segment
expenditures included acquisitions of oil and gas producing properties totaling
$45.8 million in 1996 and $6.0 million in 1995. The Company made no producing
property acquisitions in 1997.
<TABLE>
<CAPTION>
1997 1996 1995
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Capital Expenditures
Exploration and production $73,526 $110,352 $ 82,237
Gas distribution 12,561 12,752 18,523
Other 2,734 1,809 866
- --------------------------------------------------------------------------------
$88,821 $124,913 $101,626
================================================================================
</TABLE>
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending 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.
Capital spending planned for 1998 totals $74.2 million, a decrease of 16%
from actual 1997 spending, consisting of $59.2 million for exploration and
production, $12.3 million for gas distribution system expenditures, and $2.7
million for general purposes.
Financing Requirements
At year-end 1997, Southwestern's total debt was $299.5 million. This
compares to year-end 1996 total debt of $278.3 million.
Two floating rate revolving credit facilities provide the Company access to
$80.0 million of variable rate long-term capital. These facilities were
temporarily expanded to $120 million in 1996 to provide additional debt
financing to fund the acquisition of the Simmons properties. Borrowings
outstanding under these credit facilities totaled $46.4 million at the end of
1997 and $96.5 million at the end of 1996.
27
<PAGE>
In May, 1997, the Company issued $60.0 million of 7.625% Medium-Term Notes
due 2027. The notes may be repaid prior to maturity on May 1, 2009, at the
noteholder's option. In October, 1997, the Company issued $40.0 million of
Medium-Term Notes due 2017 at a weighted average interest rate of 7.21%.
Proceeds from the issuance of these notes were used to repay certain borrowings
under the Company's revolving credit facilities. All of 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's public notes are rated BBB+ by Standard and Poor's and Baa2 by
Moody's.
As explained above in "Energy Services," the Company has severally
guaranteed 60% of the principal and interest payments on approximately $78.2
million of debt payable by NOARK at December 31, 1997. Of the total, Senior
Secured Notes with a principal balance of $50.4 million are now pay-able to the
other general partner of NOARK pursuant to an interim arrangement requiring
annual principal payments of $3.2 million, plus interest on the unpaid balance.
NOARK's remaining debt is pursuant to a $30.0 million unsecured revolving credit
agreement with a group of banks which currently matures April 26, 1998. The
partnership intends during 1998 to refinance the Senior Secured Notes and
revolving credit agreement through a new issue of long-term notes. In 1997, the
Company advanced $5.0 million to NOARK to fund its share of debt service
payments. The Company expects to advance up to $3.6 million to NOARK during 1998
in connection with its guarantees.
Under its existing debt agreements, the Company may not issue long-term
debt in excess of 65% of its total capital and may not issue total debt in
excess of 70% of its total capital. To issue additional long-term debt, the
Company must also have, after giving effect to the debt to be issued, a ratio of
earnings to fixed charges of at least 1.5 or higher. At the end of 1997, the
capital structure consisted of 57.2% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
42.8% equity, with a ratio of earnings to fixed charges of 2.1. Over the long
term, the Company expects to lower the debt portion of its capital structure by
limiting its routine capital spending.
Working Capital
The Company maintains access to funds which may be needed to meet seasonal
requirements through the revolving lines of credit explained above. The Company
had net working capital of $39.0 million at the end of 1997, up from $31.1
million at the end of 1996. Current assets increased by 21% to $88.0 million in
1997, while current liabilities increased 17% to $49.0 million. The increase in
current assets at December 31, 1997, was due primarily to increases in accounts
receivable, gas storage inventory and under-recovered purchased gas costs. The
increase in accounts receivable was due primarily to higher weather-related
sales at year-end 1997 and increased gas volumes marketed by the energy services
segment. The increase in gas storage inventory at December 31, 1997, was due to
both higher volumes stored and a higher weighted average cost. The increase in
under-recovered purchased gas costs relates to the increased cost of natural gas
purchased during 1997. These costs will be recovered from the Company's utility
customers in subsequent months through automatic cost of gas adjustment clauses
included in the utility's filed rate tariffs. The increase in current
liabilities resulted primarily from an increase in accounts payable due to the
timing of invoices received.
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 and Section 21E of the Securities Exchange Act of
1934. These statements reflect the Company's current views with respect to
future events and performance. The Company believes that its expectations are
based on reasonable assumptions. No assurances, however can be given that its
goals will be achieved. Important factors that could cause actual results to
differ materially from those in the forward-looking statements herein include
(1) the timing and extent of changes in commodity prices for gas and oil and
interest rates, (2) the timing and extent of the Company's success in
discovering, developing, producing, and estimating reserves, (3) the effects of
weather and regulation on the Company's gas distribution segment, and (4)
conditions in capital markets, availability of oil field services, drilling
rigs, and other equipment, as well as other competitive factors during the
periods covered by the forward-looking statements.
28
<PAGE>
Reports of Management and
Independent Public Accountants
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 generally accepted accounting principles 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 and an ongoing program of internal audits 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 auditors, Arthur Andersen LLP. In accordance with generally accepted
auditing standards, 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 preformed.
The Audit Committee of the Board of Directors, composed solely of outside
directors, meets with management, internal auditors, 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, 1997 and
1996, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1997.
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 generally accepted auditing
standards. 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, 1997 and 1996, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 4, 1998
29
<PAGE>
<TABLE>
<CAPTION>
Statements of Income
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
<S> <C> <C> <C>
Operating Revenues
Gas sales $ 190,298 $ 174,738 $ 142,455
Gas marketing 65,435 14,153 14,032
Oil sales 14,258 8,294 3,924
Gas transportation and other 6,198 6,155 6,414
- -----------------------------------------------------------------------------------------------------------------------------
276,189 203,340 166,825
- -----------------------------------------------------------------------------------------------------------------------------
Operating Costs and Expenses
Gas purchases - utility 46,806 42,851 37,133
Gas purchases - marketing 63,054 14,114 13,714
Operating and general 59,167 50,509 44,436
Depreciation, depletion and amortization 48,208 42,394 35,992
Taxes, other than income taxes 7,018 5,476 4,362
- -----------------------------------------------------------------------------------------------------------------------------
224,253 155,344 135,637
- -----------------------------------------------------------------------------------------------------------------------------
Operating Income 51,936 47,996 31,188
Interest Expense, Net 16,414 13,044 11,167
Other Income (Expense) (5,017) (4,015) (1,227)
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Income Taxes and Extraordinary Item 30,505 30,937 18,794
- -----------------------------------------------------------------------------------------------------------------------------
Income Taxes
Current (732) (5,569) (4,908)
Deferred 12,522 17,320 12,167
- -----------------------------------------------------------------------------------------------------------------------------
11,790 11,751 7,259
- -----------------------------------------------------------------------------------------------------------------------------
Income Before Extraordinary Item 18,715 19,186 11,535
Extraordinary Item - - (295)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $ 18,715 $ 19,186 $ 11,240
=============================================================================================================================
Basic Earnings Per Share
Income before extraordinary item $.76 $.78 $.46
Extraordinary item - - (.01)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $.76 $.78 $.45
=============================================================================================================================
Weighted Average Common Shares Outstanding 24,738,882 24,705,256 25,130,781
=============================================================================================================================
Dilutive Earnings Per Share
Income before extraordinary item $.76 $.77 $.46
Extraordinary item - - (.01)
- -----------------------------------------------------------------------------------------------------------------------------
Net Income $.76 $.77 $.45
=============================================================================================================================
Dilutive Weighted Average Common Shares Outstanding 24,777,906 24,788,587 25,199,258
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
</TABLE>
30
<PAGE>
<TABLE>
<CAPTION>
Balance Sheets
Southwestern Energy Company and Subsidiaries
December 31, 1997 1996
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Assets
Current Assets
Cash $ 4,603 $ 2,297
Accounts receivable 45,752 39,928
Income taxes receivable 3,074 6,623
Inventories, at average cost 20,465 17,571
Under-recovered purchased gas costs 9,428 3,030
Other 4,633 3,484
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 87,955 72,933
- -----------------------------------------------------------------------------------------------------------------------------
Investments 7,039 6,557
- -----------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $69,304,000
in 1997 and $53,942,000 in 1996 excluded from amortization 708,094 637,100
Gas distribution systems 212,779 203,070
Gas in underground storage 23,748 25,636
Other 25,319 22,031
- -----------------------------------------------------------------------------------------------------------------------------
969,940 887,837
Less: Accumulated depreciation, depletion and amortization 366,638 319,135
- -----------------------------------------------------------------------------------------------------------------------------
603,302 568,702
- -----------------------------------------------------------------------------------------------------------------------------
Other Assets 12,570 11,998
- -----------------------------------------------------------------------------------------------------------------------------
$ 710,866 $ 660,190
=============================================================================================================================
Liabilities and Shareholders' Equity
Current Liabilities
Current portion of long-term debt $ 3,071 $ 3,071
Accounts payable 29,903 25,644
Taxes payable 3,893 3,290
Interest payable 2,569 1,628
Customer deposits 5,307 4,904
Other 4,246 3,285
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 48,989 41,822
- -----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 296,472 275,214
- -----------------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 139,256 130,686
Other 4,584 4,527
- -----------------------------------------------------------------------------------------------------------------------------
143,840 135,213
- -----------------------------------------------------------------------------------------------------------------------------
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 21,475 21,336
Retained earnings, per accompanying statements 230,669 217,889
- -----------------------------------------------------------------------------------------------------------------------------
254,918 241,999
Less: Common stock in treasury, at cost, 2,904,519 shares in 1997 and
3,019,200 shares in 1996 32,357 33,603
Unamortized cost of restricted shares issued under stock incentive
plan, 90,375 shares in 1997 and 40,020 shares in 1996 996 455
- -----------------------------------------------------------------------------------------------------------------------------
221,565 207,941
- -----------------------------------------------------------------------------------------------------------------------------
$ 710,866 $ 660,190
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 18,715 $ 19,186 $ 11,240
Adjustments to reconcile net income to net cash provided
by operating activities:
Depreciation, depletion and amortization 48,488 42,674 36,272
Deferred income taxes 12,522 17,320 12,167
Equity in loss of partnership 4,523 3,778 696
Change in assets and liabilities:
Increase in accounts receivable (5,824) (4,387) (3,216)
(Increase) decrease in income taxes receivable 3,549 1,598 (6,729)
(Increase) decrease in under-recovered purchased gas costs (6,398) (10,357) 3,700
Increase in inventories (2,894) (2,123) (3,249)
Increase in accounts payable 4,259 1,655 5,319
Net change in other current assets and liabilities (1,584) (1,759) (339)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 75,356 67,585 55,861
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (88,821) (124,913) (101,626)
Investment in partnership (4,962) (1,266) (4,968)
(Increase) decrease in gas stored underground 1,888 (2,190) 4,013
Other items 5,175 55 2,814
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (86,720) (128,314) (99,767)
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt (50,100) 73,600 (29,400)
Payments on other long-term debt (28,643) (6,143) (3,071)
Proceeds from issuance of long-term debt 98,348 - 121,978
Retirement of 10.63% Senior Notes - - (24,958)
Purchase of treasury stock - - (14,259)
Dividends paid (5,935) (5,929) (6,038)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by financing activities 13,670 61,528 44,252
- -----------------------------------------------------------------------------------------------------------------------------
Increase in cash 2,306 799 346
Cash at beginning of year 2,297 1,498 1,152
- -----------------------------------------------------------------------------------------------------------------------------
Cash at end of year $ 4,603 $ 2,297 $ 1,498
=============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
For the Years Ended December 31, 1997 1996 1995
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Retained Earnings, beginning of year $217,889 $204,632 $199,430
Net income 18,715 19,186 11,240
Cash dividends declared ($.24 per share) (5,935) (5,929) (6,038)
- -----------------------------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $230,669 $217,889 $204,632
=============================================================================================================================
The accompanying notes are an integral part of the financial statements.
</TABLE>
32
<PAGE>
Notes to Financial Statements
Southwestern Energy Company and Subsidiaries
December 31, 1997, 1996 and 1995
(1) Summary of Significant Accounting Policies
Nature of Operations and Consolidation
Southwestern Energy Company (Southwestern or the Company) is a diversified
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.
Approximately 65% of the Company's business is derived from the exploration and
production segment based on operating income. Southwestern's exploration and
production activities are concentrated in Arkansas, Oklahoma, Texas, New Mexico,
Louisiana, and the Gulf Coast (primarily onshore). The gas distribution segment
operates in northern Arkansas and parts of Missouri, and obtains approximately
60% 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.
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,
Arkansas Western Pipeline Company, and A.W. Realty 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 1997 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
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 cost 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 December 31, 1997, 1996, and 1995, the Company's cost of oil and
gas properties did not exceed such ceiling amounts.
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 2.2% to 5.6%. 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 40 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 costs 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 gas distribution customers
represent a diversified base of residential, commercial, and industrial users.
Approximately 108,000 of these customers are served in northwest Arkansas and
approximately 69,000 are served in northeast Arkansas and Missouri.
The Company records gas distribution revenues on an accrual basis, as gas
volumes are used, to provide a proper matching of revenues with expenses.
33
<PAGE>
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. Effective December, 1996, for the Company's northwest Arkansas system,
and effective December, 1997, for the northeast Arkansas system, 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.
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,
1997 and 1996 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 has limited involvement with derivative financial instruments
and does not use them for trading purposes. They are used to manage defined
commodity price risks. The Company uses commodity swap agreements and options to
hedge sales of natural gas and crude oil. Gains and losses resulting from
hedging activities are recognized when the related physical transactions are
recognized. Gains or losses from commodity swap agreements and options that do
not qualify for accounting treatment as hedges are recognized currently as other
income or expense. See Note 8 for a discussion of the Company's commodity
hedging activity.
Earnings Per Share and Shareholders' Equity
The Company has adopted Financial Accounting Standards Board Statement No.
128, "Earnings Per Share" (SFAS No. 128). 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 impact of the adoption of SFAS No. 128 had no effect on reported
earnings per share for 1996 and 1995.
During 1997 the Company issued 117,740 treasury shares under a compensatory
plan and for stock awards and returned to treasury 3,059 shares canceled from an
earlier issue under the compensatory plan. The net effect of these transactions
was a $1.2 million decrease in treasury stock.
(2) Long-Term Debt
Long-term debt as of December 31, 1997 and 1996 consisted of the following:
<TABLE>
<CAPTION>
1997 1996
---------------------------
(in thousands)
<S> <C> <C>
Senior Notes
8.69% Series due 1997 $ - $ 22,500
8.86% Series due in annual installments of $3.1 million through 1999 6,143 12,285
9.36% Series due in annual installments of $2.0 million beginning 2001 22,000 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 -
7.21% Series due 2017 40,000 -
- -----------------------------------------------------------------------------------------------------------------------------
253,143 181,785
Other
Variable rate (6.27% at December 31, 1997) unsecured revolving credit arrangements 46,400 96,500
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt 299,543 278,285
Less: Current portion of long-term debt 3,071 3,071
- -----------------------------------------------------------------------------------------------------------------------------
$ 296,472 $ 275,214
=============================================================================================================================
</TABLE>
The Company has several prepayment options under the terms of certain of
its Senior Notes. Prepayments made without premium are subject to certain
limitations. Other prepayment options involve the payment of premiums based in
some instances on market interest rates at the time of prepayment.
Two variable rate credit facilities provide the Company access to $80.0
million of long-term revolving credit. Borrowings outstanding under these credit
facilities totaled $46.4 million at December 31, 1997, all of which was
classified as long-term debt. Each facility allows the Company four interest
rate options-the floating prime rate, a fixed rate tied to either short-term
certificate of deposit or Eurodollar rates, or a fixed rate based on the
lenders' cost of funds. The revolving credit facilities expire in 2000. The
Company intends to renew or replace the facilities prior to expiration.
34
<PAGE>
The terms of the long-term debt instruments and agreements contain
covenants which impose certain restrictions on the Company, including limitation
of additional indebtedness and restrictions on the payment of cash dividends. At
December 31, 1997, approximately $129.1 million of retained earnings was
available for payment as dividends.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1998 through 2002, are $3.1 million, $3.1 million, $46.4 million,
$2.0 million, and $2.0 million. Total interest payments of $18.8 million, $15.6
million, and $12.9 million were made in 1997, 1996, and 1995, respectively.
(3) Income Taxes
The provision for income taxes included the following components:
<TABLE>
<CAPTION>
1997 1996 1995
------------------------------------------
(in thousands)
<S> <C> <C> <C>
Federal:
Current $ (1,614) $ (5,788) $ (5,436)
Deferred 11,422 15,799 11,434
State:
Current 882 219 528
Deferred 1,219 1,833 1,046
Investment tax credit amortization (119) (312) (313)
- ----------------------------------------------------------------------------------------------
Provision for income taxes $ 11,790 $ 11,751 $ 7,259
==============================================================================================
</TABLE>
The provision for income taxes was an effective rate of 38.6% in 1997,
38.0% in 1996, and 38.6% in 1995. The following reconciles the provision for
income taxes included in the consolidated statements of income with the
provision which would result from application of the statutory federal tax rate
to pretax financial income:
<TABLE>
<CAPTION>
1997 1996 1995
------------------------------------------
(in thousands)
<S> <C> <C> <C>
Expected provision at federal statutory rate of 35% $10,677 $10,828 $6,578
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,365 1,334 1,023
Other (252) (411) (342)
- --------------------------------------------------------------------------------------------------------------
Provision for income taxes $11,790 $11,751 $7,259
==============================================================================================================
</TABLE>
The components of the Company's net deferred tax liability as of December 31,
1997 and 1996 were as follows:
<TABLE>
<CAPTION>
1997 1996
--------------------------
(in thousands)
<S> <C> <C>
Deferred tax liabilities:
Differences between book and tax basis of property $124,634 $116,036
Stored gas difference 7,133 6,008
Deferred purchased gas costs 5,223 3,907
Prepaid pension costs 1,779 1,637
Book over tax basis in partnerships 6,071 5,099
Other 665 748
- ----------------------------------------------------------------------------------------------
145,505 133,435
- ----------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 754 814
Alternative minimum tax credit carryforward 4,593 2,716
Other 534 437
- ----------------------------------------------------------------------------------------------
5,881 3,967
- ----------------------------------------------------------------------------------------------
Net deferred tax liability $139,624 $129,468
==============================================================================================
</TABLE>
Total income tax payments of $4.2 million, $4.0 million, and $.9 million
were made in 1997, 1996, and 1995, respectively.
(4) Pension Plan and Other Postretirement Benefits
Substantially all employees are covered by the Company's defined benefit
pension plan. Benefits are based on years of benefit service and the employee's
"average compensation," as defined. The Company's funding policy is to
contribute amounts which are actuarially determined to provide the plan with
sufficient assets to meet future benefit payment requirements and which are tax
deductible.
Plan assumptions for 1997 and 1996 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 7.5% for the
net pension cost computation, and a salary progression rate of 5%. The
reconciliation of prepaid pension cost at December 31, 1997 utilizes a discount
rate of 7.5% for future settlements.
35
<PAGE>
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1997 and 1996:
<TABLE>
<CAPTION>
1997 1996
--------------------------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits $(32,597) $(30,371)
Nonvested benefits (2,787) (2,574)
- -----------------------------------------------------------------------------------------------
Accumulated benefit obligation (35,384) (32,945)
Effect of projected future compensation levels (11,524) (9,096)
- -----------------------------------------------------------------------------------------------
Projected benefit obligation (46,908) (42,041)
Plan assets at fair value, primarily common stocks and bonds 65,966 56,457
- -----------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 19,058 14,416
Unrecognized net gain (14,336) (9,962)
Unrecognized net asset (586) (769)
Unrecognized prior service cost 352 354
- -----------------------------------------------------------------------------------------------
Prepaid pension cost $ 4,488 $ 4,039
===============================================================================================
</TABLE>
Net pension cost for 1997, 1996, and 1995 included the following
components:
<TABLE>
<CAPTION>
1997 1996 1995
----------------------------------------------
(in thousands)
<S> <C> <C> <C>
Service costs (benefits earned during the period) $ 1,728 $ 1,520 $ 1,101
Interest cost on projected benefit obligation 3,189 2,850 2,316
Actual return on plan assets (11,635) (8,332) (15,172)
Net amortization and deferral 6,269 3,710 11,699
- -----------------------------------------------------------------------------------------------------
Net pension credit $ (449) $ (252) $ (56)
=====================================================================================================
</TABLE>
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $54,000,
$81,000, and $221,000 in 1997, 1996, and 1995, respectively. At December 31,
1997, the supplemental retirement plan had an accrued pension cost of $216,000.
The Company provides postretirement health care and life insurance benefits
to eligible employees. 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. Net
postretirement benefit cost for 1997 and 1996 included the following components:
<TABLE>
<CAPTION>
1997 1996
-----------------------
(in thousands)
<S> <C> <C>
Service cost of benefits earned during the year $ 90 $ 61
Amortization of transition amount 103 103
Amortization of unrecognized loss 40 4
Interest cost on accumulated postretirement benefit obligation (APBO) 213 161
- ---------------------------------------------------------------------------------------------------
Net postretirement benefit cost $446 $329
===================================================================================================
</TABLE>
The APBO as of December 31, 1997 and 1996 was comprised of the following:
<TABLE>
<CAPTION>
1997 1996
---------------------
(in thousands)
<S> <C> <C>
Retirees $1,370 $1,037
Active participants, fully eligible 440 326
Other participants 1,257 926
- --------------------------------------------------------------------------------------------------
Total APBO $3,067 $2,289
==================================================================================================
</TABLE>
In determining the APBO, an assumed weighted average discount rate of 7.5%
was used for 1997 and 1996. An increase of 10% in the cost of covered health
care benefits was assumed for 1998. This rate is assumed to decrease ratably to
6% over 8 years and remain at that level thereafter. The effect of a one
percentage point increase in the assumed health care cost trend rate for each
future year would increase the total APBO at year-end 1997 by $368,000 and the
1997 net postretirement benefit cost by $39,000.
36
<PAGE>
(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>
1997 1996 1995
--------------------------------------------
(in thousands)
<S> <C> <C> <C>
Sales $100,129 $ 86,978 $ 63,285
Production (lifting) costs (17,155) (10,607) (7,930)
Depreciation, depletion and amortization (40,340) (35,533) (29,607)
- ---------------------------------------------------------------------------------------------
42,634 40,838 25,748
Income tax expense (16,331) (15,528) (9,862)
- ---------------------------------------------------------------------------------------------
Results of operations $ 26,303 $ 25,310 $ 15,886
=============================================================================================
</TABLE>
The results of operations shown above exclude overhead and interest costs.
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 1997, 1996,
and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
-------------------------------------------
(in thousands)
<S> <C> <C> <C>
Property acquisition costs $10,911 $ 60,748 $27,715
Exploration costs 33,225 25,436 29,843
Development costs 28,825 23,667 24,429
- ----------------------------------------------------------------------------------------------
Capitalized costs incurred $72,961 $109,851 $81,987
==============================================================================================
Amortization per Mcf equivalent $1.057 $.949 $.817
==============================================================================================
</TABLE>
Capitalized interest is included as part of the cost of oil and gas
properties. The Company capitalized $4.5 million, $4.1 million, and $2.5 million
during 1997, 1996, and 1995, 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 $6.0 million, $5.9 million, and $4.4 million during 1997, 1996, and
1995, 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.
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 1997 and 1996:
<TABLE>
<CAPTION>
1997 1996
--------------------------
(in thousands)
<S> <C> <C>
Proved properties $628,549 $575,458
Unproved properties 79,545 61,642
- -------------------------------------------------------------------------------------
Total capitalized costs 708,094 637,100
Less: Accumulated depreciation, depletion and amortization 281,595 241,237
- -------------------------------------------------------------------------------------
Net capitalized costs $426,499 $395,863
=====================================================================================
</TABLE>
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1997. Included in these costs is
$5.1 million representing leasehold and seismic costs related to the remaining
unevaluated portion of acreage located on the Fort Chaffee military reservation.
These costs are expected to be evaluated and subjected to amortization within
the next several years as this acreage is further explored and developed. Also
included in these costs is $37.2 million related to 3-D seismic projects in
south Louisiana. These costs and subsequent costs to be incurred 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>
1997 1996 1995 Prior Total
------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition c $ 8,123 $ 7,738 $4,224 $5,983 $26,068
Exploration costs 18,551 9,270 4,417 1,780 34,018
Capitalized interest 4,318 3,538 644 718 9,218
- ------------------------------------------------------------------------------------------------------------------
$30,992 $20,546 $9,285 $8,481 $69,304
==================================================================================================================
</TABLE>
37
<PAGE>
(6) Natural Gas and Oil Reserves (Unaudited)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
---------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year 297,467 8,238 294,876 2,152 316,098 1,231
Revisions of previous estimates 861 (51) (11,772) 74 (25,970) (199)
Extensions, discoveries, and other additions 26,430 426 16,429 61 34,801 498
Production (33,355) (749) (34,758) (391) (34,515) (229)
Acquisition of reserves in place 76 - 32,713 6,350 4,462 851
Disposition of reserves in place (101) (12) (21) (8) - -
- ----------------------------------------------------------------------------------------------------------------------------
Proved reserves, end of year 291,378 7,852 297,467 8,238 294,876 2,152
============================================================================================================================
Proved, developed reserves:
Beginning of year 255,234 7,804 248,714 1,975 261,690 1,116
End of year 252,393 7,312 255,234 7,804 248,714 1,975
============================================================================================================================
</TABLE>
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, 1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
----------------------------------------------
(in thousands)
<S> <C> <C> <C>
Future cash inflows $ 973,536 $1,340,804 $ 751,261
Future production and development costs (197,021) (187,825) (106,092)
Future income tax expense (261,173) (398,625) (229,064)
- -------------------------------------------------------------------------------------------------------------------
Future net cash flows 515,342 754,354 416,105
10% annual discount for estimated timing of cash flows (256,279) (383,410) (212,583)
- -------------------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 259,063 $ 370,944 $ 203,522
===================================================================================================================
</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
1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
--------------------------------------------
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $370,944 $203,522 $189,492
Sales and transfers of gas and oil produced, net of production costs (82,975) (76,371) (55,355)
Net changes in prices and production costs (173,730) 185,234 39,928
Extensions, discoveries, and other additions,
net of future production and development costs 41,267 40,264 49,471
Acquisition of reserves in place 116 98,245 7,962
Revisions of previous quantity estimates 646 (19,839) (29,851)
Accretion of discount 55,852 31,043 28,733
Net change in income taxes 62,186 (80,662) (9,073)
Changes in production rates (timing) and other (15,243) (10,492) (17,785)
- -----------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $259,063 $370,944 $203,522
=============================================================================================================================
</TABLE>
38
<PAGE>
(7) Investment in Unconsolidated Partnership
At December 31, 1997, the Company held a 48% general partnership interest
in NOARK. NOARK is a 258-mile long intrastate gas transmission system which
extends across northern Arkansas. In January, 1998, the Company entered into an
agreement with Enogex Inc. (Enogex) which will result in the expansion of NOARK
and provide 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 is a 437-mile interstate pipeline system
which begins in eastern Oklahoma and terminates in eastern Arkansas. Enogex has
entered into a separate agreement to acquire the Ozark system and will
contribute it to the NOARK partnership. Enogex has also acquired the NOARK
partnership interests not owned by Southwestern. The acquisition of Ozark and
its integration with NOARK is subject to approval by the Federal Energy
Regulatory Commission (FERC). Management expects to obtain approval from FERC in
1998 at which time NOARK will be converted to an interstate pipeline and be
operated in combination with Ozark. Enogex will fully fund the acquisition of
Ozark and the expansion and integration with NOARK. After the integration is
complete, the Company will own a 25% interest in the partnership and the
expanded project and Enogex will own a 75% interest. The parties expect the
integrated system to be operational by late 1998.
The Company's investment in NOARK totaled $7.0 million at December 31, 1997
and $6.5 million at December 31, 1996. The Company's investment in NOARK
includes advances of $5.0 million made during 1997, $1.3 million made during
1996, and $5.0 million made during 1995, primarily to provide certain minimum
cash balances to service NOARK's long-term debt.
In connection with the Enogex transaction, the Company and a previous
general partner converted certain of their loans to the 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. See Note 12 for further discussion of
NOARK's funding requirements and the Company's investment in NOARK.
NOARK's financial position at December 31, 1997 and 1996 is summarized
below, including an unaudited pro forma balance sheet that presents the effects
of the reorganization of the partnership (excluding the pending contribution and
integration of the Ozark system) as if such transactions had occurred at
December 31, 1997:
<TABLE>
<CAPTION>
Pro Forma
1997 1997 1996
---------------------------------------------
(in thousands)
<S> <C> <C> <C>
Current assets $ 1,923 $ 923 $ 925
Noncurrent assets 101,448 92,856 95,490
- -----------------------------------------------------------------------------------------------
$ 103,371 $ 93,779 $ 96,415
===============================================================================================
Current liabilities $ 4,594 $ 9,762 $ 7,668
Long-term debt 75,000 75,000 79,150
Loans from general partners - 21,885 13,615
Partners' capital (deficit) 23,777 (12,868) (4,018)
- -----------------------------------------------------------------------------------------------
$ 103,371 $ 93,779 $ 96,415
===============================================================================================
</TABLE>
The Company's share of NOARK's pretax loss, before the effect of accrued
interest expense on general partner loans, was $4.5 million, $3.8 million, and
$.7 million for 1997, 1996, and 1995, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
income. The 1995 pretax loss included $2.9 million of income for the Company's
share of a $6.0 million settlement of contract issues with one of NOARK's
transporters.
NOARK's results of operations for 1997, 1996, and 1995 are summarized
below:
<TABLE>
<CAPTION>
1997 1996 1995
---------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating revenues $ 4,963 $ 5,114 $11,657
Pretax loss $ (8,850) $(8,106) $(2,167)
===============================================================================================
</TABLE>
(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 and Customer Deposits-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.
39
<PAGE>
The carrying amounts and estimated fair values of the Company's financial
instruments as of December 31, 1997 and 1996 were as follows:
<TABLE>
<CAPTION>
1997 1996
------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Cash $4,603 $4,603 $2,297 $2,297
Customer deposits $5,307 $5,307 $4,904 $4,904
Long-term debt $299,543 $304,392 $278,285 $279,692
Commodity hedges $1,442 $2,454 $518 $(1,717)
=============================================================================================================================
</TABLE>
Anticipated regulatory treatment of the excess of fair value over carrying
value of the portion of the Company's long-term debt attributable to its
regulatory activities, if such debt were settled at amounts approximating those
above, would dictate that these amounts be used to increase the Company's rates
over a prescribed amortization period. Accordingly, any settlement would not
result in a material impact on the Company's financial position or results of
operations.
Price Risk Management
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 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), and (2) transactions in which parties agree
to pay a price based on two different indices (referred to as basis swaps).
At December 31, 1997, the Company had outstanding natural gas price swaps
on total notional volumes of 2.2 Bcf. Of the total, the Company will receive
fixed prices ranging from $2.49 to $3.27 per MMBtu on 2.0 Bcf. Under contracts
covering the remaining .2 Bcf, the Company will make average fixed price
payments of $2.42 per MMBtu and receive variable prices based on the NYMEX
futures market. The Company held outstanding basis swaps on a notional volume of
1.9 Bcf. At December 31, 1996, the Company had outstanding natural gas price
swaps on total notional volumes of 12.1 Bcf. Of the total, the Company received
fixed prices ranging from $2.11 to $2.82 per MMBtu on 11.5 Bcf. Under contracts
covering the remaining .6 Bcf, the Company made average fixed price payments of
$3.21 per MMBtu and received variable prices based on the NYMEX futures market.
At December 31, 1996, the Company held outstanding basis swaps on a no-tional
volume of 5.5 Bcf. The Company also had outstanding a price swap on a notional
volume of 450,000 barrels of crude oil for calendar year 1997 at a fixed price
of $20.75 per barrel. During 1997, the Company recognized losses from price risk
management activities of $2.7 million, which were offset by corresponding
revenue receipts from physical transactions. In 1996 and 1995, the Company
recognized price risk management losses of $3.4 million and $.6 million,
respectively.
The Company uses options to fix a floor, a ceiling, or both a floor and
ceiling (a "collar") for prices on its production volumes. At December 31, 1997,
the Company had a crude oil price floor of $18.00 per barrel (based on the NYMEX
futures market) on total notional volumes of 1,450,000 barrels covering
production during calendar years 1998 through 2001. At December 31, 1996, the
Company had a fixed-priced collar agreement for a notional volume of 5.6 Bcf
covering the period April through October, 1997, which provided a floor price of
$2.00 per MMBtu and a ceiling price of $2.80 per MMBtu.
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 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 1993 Stock Incentive Plan (1993 Plan)
provides for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan provides for grants of options, shares of
restricted stock, and stock bonuses that in the aggregate do not exceed
1,275,000 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 do not exceed 1,275,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). 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 plan.
The Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors provides for annual stock option grants of 12,000 shares (with 12,000
limited SARs) to each non-employee director. Options may be awarded under the
plan on no more than 240,000 shares.
40
<PAGE>
The Company's 1985 Nonqualified Stock Option Plan expired in 1992, except
with respect to awards then outstanding. The following table summarizes stock
option activity for the years 1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
------------------------------------------------------------------------------------
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 1,501,641 $13.39 1,552,558 $13.39 1,411,558 $13.50
Granted 433,248 $12.58 129,000 $14.89 186,000 $13.22
Exercised 56,850 $5.96 6,000 $12.81 - -
Canceled 258,925 $13.82 173,917 $14.51 45,000 $16.03
- -----------------------------------------------------------------------------------------------------------------------------
Options outstanding at December 31 1,619,114 $13.37 1,501,641 $13.39 1,552,558 $13.39
=============================================================================================================================
Options exercisable at December 31 521,782 $12.61 588,695 $11.71 472,224 $10.71
=============================================================================================================================
</TABLE>
All options are issued at fair market value at the date of grant and expire
ten years from the date of grant. The options outstanding at December 31, 1997
had a range of exercise prices from $5.58 to $17.50 and a weighted average
remaining contractual life of 7.2 years. Options generally vest to employees and
directors over a three to four year period from the date of grant. Of the total
options outstanding, 510,000 performance accelerated options were granted in
1994 at an option price of $14 5/8. These options vest over a four-year period
beginning six years from the date of grant or earlier if certain corporate
performance criteria are achieved.
The Company has granted 114,686 shares of restricted stock to employees
through 1997. Of this total, 75,007 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.
The Company adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS No. 123) in 1996. 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 and earnings per share would have been reduced to
the pro forma amounts indicated below:
<TABLE>
<CAPTION>
1997 1996
-------------------------
(in thousands)
<S> <C> <C>
Net income
As reported $18,715 $19,186
Pro forma $18,378 $19,055
Basic earnings per share
As reported $.76 $.78
Pro forma $.74 $.77
Diluted earnings per share
As reported $.76 $.77
Pro forma $.74 $.77
===================================================================================
</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: dividend yield of 1.7% to 2.0%; expected volatility of 26.2% to
26.8%; risk-free interest rate of 5.7% to 6.8%; and expected lives of 6 years.
41
(10) Common Stock Purchase Rights
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 $25.00, subject to adjustment. These
rights will become exercisable in the event that a person or group acquires or
commences a tender offer for 20% 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 20% of the common stock (10% or
more if the Board determines such acquiror is adverse), rightholders (other than
the 20% 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.
The rights may be redeemed by the Board for $.003 per right 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 1999.
41
<PAGE>
(11) Segment Information
Intersegment sales by the exploration and production segment to the gas
distribution segment are priced in accordance with terms of existing contracts
and current market conditions. Following is industry segment data for the years
ended December 31, 1997, 1996, and 1995:
<TABLE>
<CAPTION>
1997 1996 1995
--------------------------------------------
(in thousands)
<S> <C> <C> <C>
Revenues
Exploration and production $100,129 $ 86,978 $ 63,285
Gas distribution 154,538 143,141 119,855
Energy services and other 83,128 30,225 31,219
Eliminations (61,606) (57,004) (47,534)
- -----------------------------------------------------------------------------------------------
$276,189 $203,340 $166,825
===============================================================================================
Intersegment Revenues
Exploration and production $ 43,471 $ 40,416 $ 29,811
Gas distribution 443 516 536
Energy services and other 17,692 16,072 17,187
- -----------------------------------------------------------------------------------------------
$ 61,606 $ 57,004 $ 47,534
===============================================================================================
Operating Income
Exploration and production $ 33,303 $ 34,184 $ 20,111
Gas distribution 17,152 14,223 10,833
Energy services and other 1,481 (411) 244
- -----------------------------------------------------------------------------------------------
$ 51,936 $ 47,996 $ 31,188
===============================================================================================
Identifiable Assets
Exploration and production $460,193 $423,321 $346,514
Gas distribution 206,285 197,880 183,410
Other 44,388 38,989 39,169
- -----------------------------------------------------------------------------------------------
$710,866 $660,190 $569,093
===============================================================================================
Depreciation, Depletion and Amortization
Exploration and production $ 40,340 $ 35,533 $ 29,607
Gas distribution 6,651 5,792 5,338
Other 1,217 1,069 1,047
- -----------------------------------------------------------------------------------------------
$ 48,208 $ 42,394 $ 35,992
===============================================================================================
Capital Additions
Exploration and production $ 73,526 $110,352 $ 82,237
Gas distribution 12,561 12,752 18,523
Other 2,734 1,809 866
- -----------------------------------------------------------------------------------------------
$ 88,821 $124,913 $101,626
===============================================================================================
</TABLE>
(12) Contingencies and Commitments
The Company and the other general partner of NOARK have severally
guaranteed the principal and interest payments on approximately $78.2 million of
debt incurred in connection with the construction of the existing NOARK
pipeline. The Company's share of the several guarantee is 60%. Of the total
debt, Senior Secured Notes with a fixed interest rate of 9.74% and principal
balance of $50.4 million were outstanding at December 31, 1997, pursuant to a
long-term arrangement requiring annual principal payments of $3.2 million
together with interest on the unpaid balance. The remaining debt is pursuant to
a $30.0 million unsecured revolving credit agreement with a group of banks which
currently matures April 26, 1998. In connection with the partnership changes
discussed further in Note 7, NOARK also prepaid its 9.74% Senior Secured Notes
in January, 1998. The notes were refinanced with Senior Secured Notes payable to
the other general partner of NOARK. The partnership intends to refinance its
Senior Secured Notes and revolving credit agreement through a new issue of
long-term debt during 1998. Additionally, the Company's gas distribution
subsidiary has a transportation contract with NOARK for firm capacity of 52.3
MMcfd. The contract expires in 2002, and is renewable year-to-year thereafter
until terminated by 180 days' notice.
Under the several guarantee, the Company is required to fund its share of
NOARK's debt service which is not funded by either operations of the pipeline or
by the available line of credit. As a result of the expected integration of
NOARK 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.
42
<PAGE>
In May, 1996, a lawsuit was filed against the Company involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties. In a related matter, a class action suit was filed against the
Company in May, 1996 on behalf of royalty owners alleging improprieties in the
disbursements of royalty proceeds. The Company feels these claims are
substantially without merit and intends to vigorously contest the claims brought
in each matter. While the amount of the potential claims is significant in the
aggregate, management believes, based on its investigation, that the Company's
ultimate liability, if any, will not be material to its consolidated financial
position or 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 noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial condition or reported results of operations
of the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
(13) Quarterly Results (Unaudited)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1997 and 1996:
<TABLE>
<CAPTION>
Quarter Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
1997
------------------------------------------------------------
Operating revenues $88,919 $51,244 $48,644 $87,382
Operating income $25,094 $5,089 $3,121 $18,632
Net income (loss) $12,319 $29 $(1,267) $7,634
Basic and diluted earnings (loss) per share $.50 $.00 $(.05) $.31
1996
------------------------------------------------------------
Operating revenues $64,864 $36,382 $34,424 $67,670
Operating income $19,518 $8,073 $4,260 $16,145
Net income $9,334 $2,791 $212 $6,849
Basic and diluted earnings per share $.38 $.11 $.01 $.28
========================================================================================================
</TABLE>
43
<PAGE>
Financial and Operating Statistics
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Financial Review (in thousands)
Operating revenues:
Exploration and production $100,129 $ 86,978 $ 63,285 $ 79,787 $ 79,374 $ 60,554
Gas distribution 154,538 143,141 119,855 127,060 131,892 117,495
Energy services and other 83,128 30,225 31,219 28,832 262 256
Intersegment revenues (61,606) (57,004) (47,534) (60,055) (36,684) (34,475)
- -----------------------------------------------------------------------------------------------------------------------------
276,189 203,340 166,825 175,624 174,844 143,830
- -----------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses
Gas purchases - utility 46,806 42,851 37,133 36,395 42,962 35,848
Gas purchases - marketing 63,054 14,114 13,714 5,438 - -
Operating and general 59,167 50,509 44,436 42,506 40,093 34,970
Depreciation, depletion and amortization 48,208 42,394 35,992 35,546 30,944 23,880
Taxes, other than income taxes 7,018 5,476 4,362 3,657 3,281 3,144
- -----------------------------------------------------------------------------------------------------------------------------
224,253 155,344 135,637 123,542 117,280 97,842
- -----------------------------------------------------------------------------------------------------------------------------
Operating income 51,936 47,996 31,188 52,082 57,564 45,988
Interest expense, net (16,414) (13,044) (11,167) (8,867) (9,025) (9,983)
Other income (expense) (5,017) (4,015) (1,227) (2,362) (1,657) (421)
- -----------------------------------------------------------------------------------------------------------------------------
Income before income taxes, extraordinary item and
the cumulative effect of accounting change 30,505 30,937 18,794 40,853 46,882 35,584
- -----------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current (732) (5,569) (4,908) 9,288 13,704 7,403
Deferred 12,522 17,320 12,167 6,441 6,128 5,916
- -----------------------------------------------------------------------------------------------------------------------------
11,790 11,751 7,259 15,729 19,832 13,319
- -----------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and
cumulative effect of accounting change 18,715 19,186 11,535 25,124 27,050 22,265
Extraordinary item - - (295) - - -
Cumulative effect of change in accounting for
income taxes - - - - 10,126 -
- -----------------------------------------------------------------------------------------------------------------------------
Net income $ 18,715 $ 19,186 $ 11,240 $25,124 $ 37,176 $ 22,265
=============================================================================================================================
Cash flow from operations, net of working
capital changes (in thousands) $ 75,356 $ 67,585 $ 55,861 $66,613 $ 70,199 $ 49,730
Return on equity 8.45% 9.23% 5.78% 12.35% 14.66%(1) 14.53%
Gross profit margin 18.80% 23.60% 18.70% 29.66% 32.92% 31.97%
Net profit margin 6.78% 9.44% 6.74% 14.31% 15.47%(1) 15.48%
=============================================================================================================================
Common Stock Statistics(2)
Basic earnings per share before extraordinary item
and cumulative effect of accounting change $.76 $.78 $.46 $.98 $1.05 $.87
Basic earnings per share $.76 $.78 $.45 $.98 $1.44 $.87
Cash dividends declared and paid per share $.24 $.24 $.24 $.24 $.22 $.20
Book value per share $8.92 $8.41 $7.87 $7.92 $7.18 $5.97
Market price at year-end $12.88 $15.13 $12.75 $14.88 $18.00 $12.96
Number of shareholders of record at year-end 2,379 2,572 2,759 2,875 3,005 2,930
Average shares outstanding 24,738,882 24,705,256 25,130,781 25,684,110 25,684,110 25,683,963
============================================================================================================================
(1)Before the cumulative effect of accounting change.
(2)All share and per share data have been restated to reflect the effect of a
three-for-one stock split distributed in 1993.
</TABLE>
44
<PAGE>
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------
<S>
Capitalization (in thousands) <C> <C> <C> <C> <C> <C>
Long-term debt, including current portion $299,543 $278,285 $210,828 $142,300 $127,000 $143,335
Common shareholders' equity 221,565 207,941 194,504 203,456 184,530 153,233
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization $521,108 $486,226 $405,332 $345,756 $311,530 $296,568
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $710,866 $660,190 $569,093 $486,074 $445,454 $427,175
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 57.23% 56.96% 51.65% 40.10% 40.19% 48.31%
Equity 42.77% 43.04% 48.35% 59.90% 59.81% 51.69%
=============================================================================================================================
Capital Expenditures (in millions)
Exploration and production $73.5 $110.3 $ 82.2 $55.4 $37.4 $30.8
Gas distribution 12.6 12.8 18.5 17.6 19.9 12.2
Other 2.7 1.8 .9 3.9 1.9 1.9
- -----------------------------------------------------------------------------------------------------------------------------
$88.8 $124.9 $101.6 $76.9 $59.2 $44.9
=============================================================================================================================
Exploration and Production
Natural gas:
Production, Bcf 33.4 34.8 34.5 37.7 35.7 25.8
Average price per Mcf $2.57 $2.26 $1.72 $2.04 $2.18 $2.26
Oil:
Production, MBbls 749 391 229 200 97 120
Average price per barrel $19.02 $21.21 $17.15 $15.89 $17.20 $19.75
Average production (lifting) cost per Mcf equivalent $.45 $.29 $.22 $.17 $.18 $.16
Proved reserves at year-end:
Natural gas, Bcf 291.4 297.5 294.9 316.1 318.8 312.3
Oil, MBbls 7,852 8,238 2,152 1,231 479 359
Total reserves, Bcf equivalent 338.5 346.9 307.8 323.5 321.7 314.5
=============================================================================================================================
Gas Distribution
Sales and transportation volumes, Bcf:
Residential 12.6 13.4 12.1 11.6 12.9 10.8
Commercial 8.4 8.8 7.6 7.2 7.8 6.6
Industrial 6.6 7.7 7.7 7.5 6.1 6.1
End-use transportation 6.6 5.5 5.2 4.8 5.6 5.2
- -----------------------------------------------------------------------------------------------------------------------------
34.2 35.4 32.6 31.1 32.4 28.7
Off-system transportation 2.8 3.6 9.8 10.7 11.7 2.5
- -----------------------------------------------------------------------------------------------------------------------------
37.0 39.0 42.4 41.8 44.1 31.2
- -----------------------------------------------------------------------------------------------------------------------------
Customers - year-end
Residential 154,864 151,880 147,267 144,486 140,761 136,895
Commercial 21,431 20,845 20,109 19,489 19,121 18,819
Industrial 311 326 340 348 348 357
- -----------------------------------------------------------------------------------------------------------------------------
176,606 173,051 167,716 164,323 160,230 156,071
- -----------------------------------------------------------------------------------------------------------------------------
Degree days 4,131 4,341 4,064 3,823 4,598 3,720
Percent of normal 103% 108% 102% 96% 115% 93%
=============================================================================================================================
</TABLE>
45
<PAGE>
Shareholder Information
Annual Meeting
The Annual Meeting of Shareholders of Southwestern Energy Company will be held
at the Northwest Arkansas Holiday Inn in Springdale, Arkansas, on Thursday, May
21, 1998, at 11:00 a.m. Central Daylight Time.
Stock Exchange Listing
Southwestern Energy Company's common stock is traded on the New York Stock
Exchange under the symbol SWN and is listed in alphabetical quotation listings
in most major newspapers as SowestEngy.
Independent Public Accountants
Arthur Andersen LLP
6450 South Lewis
Suite 300
Tulsa, Oklahoma 74136-1068
Financial Information
Financial analysts and investors who need additional information should contact
Stanley D. Green, Executive Vice President - Finance and Corporate Development,
at corporate headquarters, 501-521-1141.
Transfer Agent and Registrar
First Chicago Trust Company of New York
525 Washington Blvd.
Jersey City, NJ 07310
Phone 1-800-446-2617
Dividend Reinvestment Plan
Southwestern Energy Company offers holders of record
of its common stock the opportunity to purchase additional shares through its
Dividend Reinvestment Plan. Dividends and/or optional cash investments of up to
$1,000 monthly may be used to purchase additional shares of the Company's stock
for nominal service and broker's fees. Information about the Plan is available
from the administrator:
First Chicago Trust Company of New York
P.O. Box 2598
Jersey City, NJ 07303-2598
Phone 1-800-446-2617
Annual Report
The 1997 Annual Report filed with the Securities and Exchange Commission on Form
10-K is available to shareholders upon request by writing to the Secretary at
corporate headquarters.
Market Prices and Quarterly Dividends Paid
<TABLE>
<CAPTION>
Range of Market Prices Cash Dividends Paid
- -----------------------------------------------------------------------------------------------------
1997 1996 1997 1996
- ------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
March 31 $15.75 $13.25 $13.25 $10.63 $.06 $.06
June 30 $13.75 $11.63 $14.75 $11.88 $.06 $.06
September 30 $14.31 $12.00 $16.13 $13.63 $.06 $.06
December 31 $13.13 $11.25 $17.38 $14.25 $.06 $.06
- ------------------------------------------------------------------------------------------------------
</TABLE>
Market prices represent transactions on the New York Stock Exchange.
46
<PAGE>
Southwestern Energy Company and Subsidiaries
APPENDIX to 1997 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in four
areas; the Arkoma Basin, the Anadarko Basin, the Gulf Coast, and the Permian
Basin. The Arkoma Basin is located in the central section of western Arkansas
and the central section of eastern Oklahoma. Southwestern's activities are
concentrated in the historically productive Arkansas section of the Arkoma
Basin. The Anadarko Basin covers most of the western part of Oklahoma and
extends to the northwest into the northern panhandle of Texas and the panhandle
area of Oklahoma. The Permian Basin is located in west Texas and the southeast
corner of New Mexico. Southwestern's Gulf Coast operations include both onshore
and offshore activity along both the Texas and Louisiana coasts.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where it also provides distribution
service to communities in that area, including the towns of Ozark and
Clarksville. AWG's transmission and distribution lines extend north and supply
communities in the northwest part of the state, including the towns of
Fayetteville, Springdale, and Rogers. AWG's service area also extends east to
the Harrison and Mountain Home areas. This eastern section of the AWG system
receives a portion of its gas supply from a lateral line off of the NOARK
Pipeline System (NOARK) as discussed below. Through its division, Associated
Natural Gas Company (Associated), AWG provides distribution of natural gas to
communities in northeast Arkansas and parts of Missouri. Major communities
served in northeast Arkansas include Blytheville, Piggott, and Osceola. The
Associated distribution system also serves the "bootheel" area in southeast
Missouri, including the communities of Sikeston, New Madrid, and Caruthersville
and extends north to the Jackson area. In addition, Associated provides service
to Butler, Missouri, near the state's western border and Kirksville, Missouri,
near the state's northern border through connections off of interstate pipelines
in those areas.
Description of NOARK Pipeline System Operating Area:
Southwestern Energy Pipeline Company owns a general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Company's gathering and
transmission pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Forth Smith, at
the Fort Chaffee military reservation, and extends east through the Arkoma Basin
and across northern Arkansas. A lateral from NOARK extends north and connects to
AWG's distribution line in the Mountain Home area. NOARK crosses three
interstate pipelines in northeast Arkansas and ends at an interconnection with
Arkansas Western Pipeline Company's 8-mile interstate pipeline at the
Arkansas/Missouri border. This pipeline transports gas from NOARK to
Associated's distribution system.
<TABLE>
<CAPTION>
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
<S> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------
Gathering 442 -- 442
Transmission 753 606 1,359
Distribution 3,016 1,651 4,667
- -----------------------------------------------------------------------------------------------------------
4,211 2,257 6,468
===========================================================================================================
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 4,603
<SECURITIES> 0
<RECEIVABLES> 45,752
<ALLOWANCES> 0
<INVENTORY> 20,465
<CURRENT-ASSETS> 87,955
<PP&E> 969,940
<DEPRECIATION> 366,638
<TOTAL-ASSETS> 710,866
<CURRENT-LIABILITIES> 48,989
<BONDS> 296,472
0
0
<COMMON> 2,774
<OTHER-SE> 218,791
<TOTAL-LIABILITY-AND-EQUITY> 710,866
<SALES> 269,991
<TOTAL-REVENUES> 276,189
<CGS> 0
<TOTAL-COSTS> 224,253
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 16,414
<INCOME-PRETAX> 30,505
<INCOME-TAX> 11,790
<INCOME-CONTINUING> 18,715
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 18,715
<EPS-PRIMARY> .76
<EPS-DILUTED> .76
<FN>
The information has been prepared in accordance with SFAS No. 128.
Basic and diluted EPS have been entered in place of primary and fully diluted,
respectively.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 2,297
<SECURITIES> 0
<RECEIVABLES> 39,928
<ALLOWANCES> 0
<INVENTORY> 17,571
<CURRENT-ASSETS> 72,933
<PP&E> 887,837
<DEPRECIATION> 319,135
<TOTAL-ASSETS> 660,190
<CURRENT-LIABILITIES> 41,822
<BONDS> 275,214
0
0
<COMMON> 2,774
<OTHER-SE> 205,167
<TOTAL-LIABILITY-AND-EQUITY> 660,190
<SALES> 197,185
<TOTAL-REVENUES> 203,340
<CGS> 0
<TOTAL-COSTS> 155,344
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 13,044
<INCOME-PRETAX> 30,937
<INCOME-TAX> 11,751
<INCOME-CONTINUING> 19,186
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 19,186
<EPS-PRIMARY> .78
<EPS-DILUTED> .77
<FN>
The information has been prepared in accordance with SFAS No. 128.
Basic and diluted EPS have been entered in place of primary and fully diluted,
respectively.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 1,498
<SECURITIES> 0
<RECEIVABLES> 35,541
<ALLOWANCES> 0
<INVENTORY> 15,448
<CURRENT-ASSETS> 63,896
<PP&E> 763,570
<DEPRECIATION> 277,751
<TOTAL-ASSETS> 569,093
<CURRENT-LIABILITIES> 45,410
<BONDS> 207,757
0
0
<COMMON> 2,774
<OTHER-SE> 191,730
<TOTAL-LIABILITY-AND-EQUITY> 569,093
<SALES> 160,411
<TOTAL-REVENUES> 166,825
<CGS> 0
<TOTAL-COSTS> 135,637
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 11,167
<INCOME-PRETAX> 18,794
<INCOME-TAX> 7,259
<INCOME-CONTINUING> 11,535
<DISCONTINUED> 0
<EXTRAORDINARY> (295)
<CHANGES> 0
<NET-INCOME> 11,240
<EPS-PRIMARY> .45
<EPS-DILUTED> .45
<FN>
The information has been prepared in accordance with SFAS No. 128.
Basic and diluted EPS have been entered in place of primary and fully diluted,
respectively.
</FN>
</TABLE>
