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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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FORM 10-K
(Mark one)
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 (Fee required)
For the fiscal year ended December 31, 1994
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or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 (No fee required)
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 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, Fayetteville, Arkansas 72703
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(Address of principal executive offices) (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 on
Title of each class which registered
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Common Stock - Par Value $.10 New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. __________
The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $351,357,014 based on the New York Stock Exchange -
Composite Transactions closing price on March 24, 1995 of $13.875.
The number of shares outstanding as of March 24, 1995, of the
Registrant's common stock, par value $.10, was 25,607,365.
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 fiscal year ended December 31, 1994 - 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 31, 1995 - PART III.
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SOUTHWESTERN ENERGY COMPANY
FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1994
TABLE OF CONTENTS
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PART I
Page
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Item 1. Business ............................................................................... 1
Natural gas and oil exploration and production ......................................... 1
Natural gas gathering, transmission and distribution ................................... 4
Real estate development ................................................................ 9
Employees .............................................................................. 9
Industry segment and statistical information ........................................... 9
Item 2. Properties ............................................................................. 9
Item 3. Legal Proceedings ...................................................................... 10
Item 4. Submission of Matters to a Vote of Security Holders .................................... 11
Executive Officers of the Registrant ................................................... 11
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters .................. 12
Item 6. Selected Financial Data ................................................................ 12
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 12
Item 8. Financial Statements and Supplementary Data ............................................ 12
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ... 12
PART III
Item 10. Directors and Executive Officers of the Registrant ..................................... 12
Item 11. Executive Compensation ................................................................. 12
Item 12. Security Ownership of Certain Beneficial Owners and Management ......................... 12
Item 13. Certain Relationships and Related Transactions ......................................... 13
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K ........................ 13
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PART I
ITEM 1. BUSINESS
Southwestern Energy Company (the Company) is a diversified natural gas
company which conducts its primary activities through four wholly owned
subsidiaries. The Company operates principally in the exploration and production
segment, the gas distribution segment and the gas transmission segment of the
natural gas industry. The Company was incorporated on July 2, 1929, under the
laws of the state of Arkansas. The Company operates an integrated natural gas
gathering, transmission and distribution system in northwest Arkansas, and
natural gas distribution systems in northeast Arkansas and parts of Missouri.
The nature of the Company's natural gas transmission and distribution operations
changed in 1992 when a new 258 mile long intrastate pipeline in which the
Company owns an interest commenced operations. The intrastate pipeline crosses
three interstate pipelines and ties the Company's distribution and gathering
pipeline systems in northwest Arkansas to its distribution systems in northeast
Arkansas and southeast Missouri. The Company also serves as operator of the
pipeline. 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.
The exploration, development and production activities are a separate, primary
business of the Company. The Company is an exempt holding company under the
Public Utility Holding Company Act of 1935.
Exploration and production activities consist of ownership of mineral
interests in productive and undeveloped leases located entirely within the
United States. The Company engages in gas and oil exploration and production
through its subsidiaries, SEECO, Inc. (SEECO) and Southwestern Energy Production
Company (SEPCO). 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 an exploration program in areas outside Arkansas,
primarily the Gulf Coast areas of Texas and Louisiana. SEPCO also holds a block
of leasehold acreage located on the Fort Chaffee military reservation in western
Arkansas and in other parts of Arkansas away from the operating areas of the
Company's other subsidiaries. The Company's subsidiary Arkansas Western Gas
Company (Arkansas Western) operates integrated natural gas distribution systems
in Arkansas and Missouri. Arkansas Western is the largest single purchaser of
SEECO's gas production. Southwestern Energy Pipeline Company (SWPL) owns an
interest in the NOARK Pipeline System (NOARK), an intrastate natural gas
transmission system which extends across northern Arkansas. A discussion of the
primary businesses conducted by the Company through its wholly owned
subsidiaries follows.
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
Substantially all of the Company's exploration and production activities and
reserves are concentrated in the Arkoma Basin of Arkansas and the Gulf Coast
areas of Texas and Louisiana. At December 31, 1994, the Company had proved
natural gas reserves of 316.1 billion cubic feet (Bcf) and proved oil reserves
of 1,231 thousand barrels (MBbls). Revenues of the exploration and production
subsidiaries are predominately generated from production of natural gas. The
Company's gas production increased for the seventh consecutive year in 1994,
totaling 37.7 Bcf, up 6% from 35.7 Bcf in 1993. Sales of gas production
accounted for 96% of total operating revenues for this segment in 1994, 98% in
1993, and 96% in 1992. SEECO's largest customer for sales of its gas production
was the Company's utility subsidiary. Sales to unaffiliated purchasers by both
SEECO and SEPCO have increased significantly, however, during the last few years
primarily as a result of higher production from Arkansas properties and from
properties in the Gulf Coast areas. Sales to unaffiliated purchasers accounted
for 63% of total gas volumes sold by the exploration and production segment in
1994, 64% in 1993, and 55% in 1992.
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Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas
division (AWG) were approximately 8.8 Bcf in 1994, 7.1 Bcf in 1993 and 7.2 Bcf
in 1992. Through these sales, SEECO furnished approximately 64% of the northwest
Arkansas system's requirements in 1994 and 50% in both 1993 and 1992. The
increase in 1994 was due largely to increased storage injections and higher
volumes resulting from a settlement reached to resolve certain gas cost issues
before the Arkansas Public Service Commission (APSC). The settlement, which
involved the price of gas sold under a long-term contract between SEECO and AWG,
is hereafter referred to as "the gas cost settlement", and is discussed more
fully below. SEECO also delivered approximately 1.5 Bcf in 1994, 2.2 Bcf in 1993
and 2.8 Bcf in 1992 directly to certain large business customers of AWG through
a transportation service of the utility subsidiary that became effective in
October, 1991. 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 had been
frozen since 1984. This contract was amended in 1994 as a result of the gas cost
settlement. The 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 an additional premium. The settlement results in a lower contract
price based on current market conditions. That effect is offset in part by
provisions which allow additional volumes to be sold under the contract. The
amended contract provides for volumes equal to the historical level of sales
under the contract to be sold at the spot market index plus a premium of $.95
per Mcf, while any incremental sales volumes will receive a premium of $.50 per
Mcf. In 1994, approximately 8.1 Bcf (net to the Company's interest) was sold
under the contract compared to approximately 6.0 Bcf in 1993. Other significant
terms of the settlement prevent any of the parties thereto from asking for
refunds, transfer certain of AWG's storage facilities to SEECO, and prohibits
AWG from filing a rate case before January, 1996. In addition to this contract,
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 AWG accounted for approximately 32%, 31% and 45% of total exploration and
production revenues in 1994, 1993 and 1992, respectively.
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 5.1 Bcf in 1994, 5.7 Bcf in 1993 and 4.3
Bcf in 1992. These deliveries accounted for approximately 58% of Associated's
total requirements in 1994, 67% in 1993 and 56% in 1992. These sales represented
14% of total exploration and production revenues in 1994, 15% in 1993 and 14% in
1992. Deliveries to Associated decreased in 1994 due to warmer weather in the
heating season and increased in 1993 primarily due to colder heating weather and
storage requirements during the summer months. Effective October, 1990, SEECO
entered into a ten-year contract with Associated to supply its base load system
requirements at a price to be redetermined annually. Deliveries under this
contract were made at a price of $1.90 per thousand cubic feet (Mcf) from
inception of the contract through the first nine months of 1993, increased to
$2.385 per Mcf for the contract period ended September 30, 1994, and are
currently being made at a price of $2.20 per Mcf.
In 1990, SEECO completed the initial mapping and engineering phases of a
multi-year geological field study of the Arkoma Basin of Arkansas. The product
developed was an extensive database and geologic interpretations of the
distribution of gas-bearing sands in the region and resulted in the
identification of 69.7 Bcf of proved undeveloped reserves that were added to the
Company's base of proved reserves. At December 31, 1994, after transfers and
revisions, the remaining proved undeveloped reserves identified by the study
were 46.4 Bcf. The data base developed is continually updated by drilling
activity and serves as the guide for a development drilling program that the
Company plans to continue over the next several years. The development drilling
program added 22.2 Bcf in 1994, 27.0 Bcf in 1993, and 22.5 Bcf in 1992 of new
natural gas reserve additions and resulted in the transfer of 3.0 Bcf in 1994,
2.6 Bcf in 1993, and 8.7 Bcf in 1992 from the proved undeveloped category to the
proved developed category. SEECO participated in a total of 97 development wells
during 1994 with a completion rate of 72%. SEECO expects the number of wells it
participates in to increase during 1995, but due to anticipated lower working
interests, expects the number
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of wells net to the Company's interest to remain approximately the same as 1994.
SEECO's sales to unaffiliated purchasers increased to 10.7 Bcf in 1994, from
10.0 Bcf in 1993 and 4.7 Bcf in 1992. The increase in both years resulted from
the Company's development drilling program. At present, SEECO's contracts for
sales of gas to unaffiliated customers consist of short-term sales made to
customers of AWG's transportation program and spot sales into markets away from
AWG's distribution system. These sales are subject to seasonal price swings. In
the past, the Company's ability to enter into sales arrangements with
unaffiliated customers has generally been constrained by a lack of pipeline
transportation to markets away from the Arkoma Basin. Initiatives of the FERC to
restructure the natural gas interstate pipeline service rules through its Order
No. 636 series have improved and should continue to improve the Company's
ability to market its existing and potential reserves. Also contributing to the
increase in the ability of SEECO to market its gas to unaffiliated customers was
the completion in September, 1992 of NOARK, as explained more fully below under
"Natural gas gathering, transmission and distribution." SEECO's sales to
unaffiliated purchases accounted for approximately 23%, 22% and 13% of total
exploration and production revenues in 1994, 1993 and 1992, respectively.
At December 31, 1994, the gas reserves of SEPCO were located primarily in
the states of Arkansas, Oklahoma and the Gulf Coast areas of Texas and
Louisiana, while its oil reserves were located primarily in Oklahoma and the
Gulf Coast areas of Louisiana and Texas. SEPCO holds about 26% of the Company's
natural gas reserves and all of its oil reserves. SEPCO's gas sales increased to
13.1 Bcf in 1994, from 12.9 Bcf in 1993 and 9.6 Bcf in 1992. The increased
production since 1992 was primarily from properties located in the Gulf Coast
areas of Texas and Louisiana. The increase in 1994 was the result of the
completion of a production platform at the Galveston Block 283 gas field late in
1993 and first production from the Earl Chauvin No. 1 well, a 1993 discovery in
southeast Louisiana. The increase in 1993 was primarily the result of the
completion of a production platform at Brazos Block 397 and the start of
production in November 1993 from Galveston Block 283. The Company's production
from the Gulf Coast areas is sold under contracts which reflect current short-
term prices and which are subject to seasonal price swings. The Company
curtailed part of its gas production during 1992 when sales prices were deemed
below acceptable levels. Oil production was 200 MBbls in 1994, compared to 97
MBbls in 1993, and 120 MBbls in 1992. The increase in oil production in 1994
primarily resulted from the acquisition of certain Oklahoma producing properties
during the year. The Company's exploration program has been directed almost
exclusively toward natural gas in recent years. The Company plans to continue to
concentrate on developing gas reserves, but will also selectively seek
opportunities to participate in projects oriented toward oil production. Over
the long-term, however, oil sales are not expected to account for a significant
part of the Company's future revenues. SEPCO's gas and oil sales accounted for
approximately 33% of total exploration and production operating revenues in 1994
and 1993, and 31% in 1992.
In 1989, SEPCO purchased at oral auction 11,000 undrilled acres containing
17 separate drilling units on the Fort Chaffee military reservation of western
Arkansas. The total cost of this acreage was approximately $11.0 million. To
date, the Company has drilled or participated in eight wells at Fort Chaffee
that have discovered an estimated 47.0 Bcf of new gas reserves, net to the
Company's interest. The Company is currently in the process of testing a well
recently drilled at Fort Chaffee. Sales of gas production from Fort Chaffee
totaled 4.3 Bcf in 1994, 5.1 Bcf in 1993 and 5.8 Bcf in 1992. The decrease is a
result of the natural decline in the productive capability of these properties.
Conflicts with military training activities have limited SEPCO's drilling
operations at Fort Chaffee. The Company has attempted to work with the military
to improve work schedules and operating restrictions, but those efforts have
been to little avail even though the base was scheduled for closing. As a
result, Fort Chaffee will probably play a lesser role in the Company's plans.
From late 1992 through 1993 sales from Fort Chaffee took place under a firm
sales contract for 25 million cubic feet per day (MMcfd) to an independent
marketer. The gas was transported by the marketer
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under a firm transportation contract on NOARK. The Company met its obligation
under the firm sales contract in part by providing gas supplied from SEECO's
development drilling program. In late 1993, the marketer filed suit against
NOARK, the Company and certain of its affiliates, seeking rescission of the firm
sales and transportation contracts. Since that time, the Company has entered
into its own sales arrangements covering the affected gas production. This gas
production continues to be transported through NOARK at a price based on current
spot market prices, net of transportation. See discussion at "Natural gas
gathering, transmission and distribution" for additional information concerning
the independent marketer's decision to cease honoring its contractual
obligations.
Outside Arkansas, the Company added 8.7 Bcf of new reserves in 1994 and 19.0
Bcf in 1993 from drilling. Of that total, 8.5 Bcf in 1994 and 15.2 Bcf in 1993
was from discoveries in the coastal areas of Texas and Louisiana. The Gulf Coast
region continues to be the focus of most of the Company's exploration activity
outside Arkansas. The Company expects in the future to continue to direct its
exploration activities toward the onshore Gulf Coast.
During 1994, the Company increased its emphasis on acquisitions of producing
properties and expects that effort to continue as a supplement to its
exploration and development drilling programs. The Company acquired
approximately 20.6 Bcf of gas and 1,038 MBbls of oil during 1994, mostly in the
Anadarko Basin of Oklahoma.
In the natural gas and oil exploration segment, competition is encountered
primarily in obtaining leaseholds for future exploration. Competition in the
state of Arkansas has increased in recent years, due largely to the development
of improved access to interstate pipelines. Due to the Company's significant
leasehold acreage position in Arkansas and its long-time presence and reputation
in this area, the Company believes it will continue to be successful in
acquiring new leases in Arkansas. While improved intrastate and interstate
pipeline transportation in Arkansas should increase the Company's access to
markets for its gas production, these markets will generally be served by a
number of other suppliers. Thus, the Company will encounter competition 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.
The Company expects its 1995 capital expenditures for gas and oil
exploration and development to total $55.2 million, approximately equal to the
$55.4 million incurred in 1994. Most of the capital spending will be directed to
the continued development of the Company's proved acreage in the Arkoma Basin
and the Company's exploration program in the Gulf Coast areas of Texas and
Louisiana. The Company will review this budget periodically during the year for
possible adjustment depending upon cash flow projections related to fluctuating
prices for oil and natural gas.
NATURAL GAS GATHERING, TRANSMISSION AND DISTRIBUTION
The Company's natural gas distribution operations are concentrated primarily
in north Arkansas and southeast Missouri. The Company serves approximately
164,000 retail customers and obtains a substantial portion of the gas they
consume through its Arkoma Basin gathering facilities. The Company is also a
participant in a partnership that owns the NOARK Pipeline System. The complexity
of AWG's distribution operations, particularly its gathering system in the
Arkoma Basin gas fields, increased significantly with the start up of NOARK. 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. The Company completed a pipeline in 1993 that connects
NOARK to Associated's distribution system, tying together the Company's two
primary gas distribution systems.
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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 97,000 customers in
northwest Arkansas. The Associated division currently receives its gas from
transportation pipelines and delivers the gas through its own transmission and
distribution systems, ultimately delivering it at retail to approximately 67,000
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. The Arkansas
Public Service Commission (APSC) and the Missouri Public Service Commission
(Missouri Commission) regulate the Company's utility rates and operations. 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.
AWG and Associated deliver natural gas to residential, commercial and
industrial customers. The industrial customers are generally smaller concerns
using gas for plant heating or product processing. 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. Associated has not denied service to
new customers within its service area or experienced curtailments because of
supply constraints since the acquisition date, although service restrictions and
supply related curtailments did occur prior to that time. Curtailment of large
industrial customers of AWG and Associated occurs only infrequently when
extremely cold weather requires their systems to be dedicated exclusively to
human needs customers.
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 as a result
of the significant declines in prices of petroleum products and the
deliverability surplus of natural gas experienced in the recent past. Industrial
customers are most likely to consider utilization of these alternatives, as they
are less readily available to commercial and residential customers. In an effort
to provide some pricing alternatives to its large industrial customers with
relatively stable loads, AWG offers an optional tariff to its larger business
customers and to any other large business customer which shows that it has an
alternate source of fuel at a lower price or that one of its direct competitors
in another area 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 costs 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. In an effort to more fully meet
the service needs of larger business customers, both AWG and Associated
instituted a transportation service in October, 1991, that allows such customers
in Arkansas to obtain their own gas supplies directly from other suppliers.
Associated has offered transportation service to its larger customers in
Missouri for several years and AWG's spot market purchasing program has provided
customers in northwest Arkansas with many of the benefits of transportation
service. Under the programs, transportation service is available in Arkansas to
any large business customer which consumes a minimum of 150,000 Mcf per year and
no less than 3,000 Mcf per month. Transportation service is available in
Missouri to any customer whose average monthly usage exceeds 2,000 Mcf. The
minimums can be met by aggregating facilities under common ownership. A total of
eleven customers are currently using the Arkansas
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transportation service, including three of AWG's four largest customers in
northwest Arkansas and Associated's two largest customers in northeast Arkansas.
In its 1991 order approving the transportation program, the APSC indicated that
the program's approval would be on a one year trial basis to allow for time to
gain operating experience in an effort to make improvements, if needed, in the
program. Since the expiration of the first trial year, the APSC has continued to
extend the program on an annual basis. The APSC has established a procedural
schedule for considering during 1995 finalization of the transportation program.
In addition, the public hearing will also address whether there is a need to
continue AWG's spot market purchasing program. Other issues may also be raised
by the parties to the proceeding.
AWG purchases its system gas supply directly at the wellhead under long-term
contracts. Purchases are made from approximately 300 working interest owners in
491 producing wells. As previously indicated, SEECO furnished approximately 64%
of AWG's requirements in 1994 and 50% in both 1993 and 1992. A significant
portion of the unaffiliated volumes purchased by AWG are covered by contracts
which contain provisions for periodic or automatic escalation in the price to be
paid. In the mid-1980's, however, AWG took steps to freeze the prices paid under
those contracts containing indefinite price escalators tied to Section 102 or
prices escalating under Section 103 of the NGPA. Producers under these contracts
were offered an amendment freezing the price at the December, 1984 level, with a
right to renegotiate in one year. AWG received acceptances from producers
holding the majority of the reserves under such contracts, either accepting the
amendment or agreeing to freeze the price. Since that time, the price freeze has
remained in effect and AWG has continued to make payments at the frozen 1984
price levels. This price freeze also applied to purchases from SEECO under its
long-term contract with AWG until the gas cost settlement became effective July
1, 1994. A significant portion of AWG's supply comes from newer, market
responsive, long-term contracts which take advantage of the lower prices
presently available from gas suppliers.
At December 31, 1994, AWG had a gas supply available to its northwest
Arkansas system of approximately 239 Bcf of proved developed reserves, equal to
17 times current annual usage. Of this total, approximately 113 Bcf were net
reserves available from SEECO. Under the terms of the gas cost settlement,
SEECO's reserves are no longer dedicated to AWG. However, 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.
During 1993, Associated renegotiated its purchase contracts with interstate
pipelines in accordance with the pipeline restructuring as mandated by the
Federal Energy Regulatory Commission's (FERC) Order No. 636. Prior to Order 636,
Associated purchased its system supply from six interstate pipelines, SEECO and
various spot market suppliers. Associated now purchases gas for its system
supply from unaffiliated suppliers in the producing fields 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 nine 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 of the 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.
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 FERC's Order No. 636 series
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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 AWG, 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 a result of pipeline deregulation, Associated has paid approximately $3.2
million in contract reformation costs and take-or-pay costs and $1.9 million in
transition costs which its interstate pipeline suppliers incurred and were
allowed to recover. The Company anticipates full recovery of the $1.9 million in
transition costs incurred. To date, the Company has recovered, subject to
refund, approximately $1.6 million of the contract reformation costs and take-
or-pay costs from its utility sales customers in the state of Missouri. Of the
unrecovered $1.6 million related to contract reformation costs and take-or-pay
costs, $.7 million is applicable to Associated's transportation customers in the
state of Missouri and $.9 million is applicable to all customers in the state of
Arkansas. The Staff of the Missouri Commission (Staff) has reviewed these
payments and made a recommendation that the unrecovered $.7 million related to
Associated's transportation customers should be disallowed on the grounds that
such recovery would constitute retroactive ratemaking. The Company disagreed
with this recommendation and a hearing was held on January 31, 1995. The Company
is awaiting the Missouri Commission's order.
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 purchase requirements. This decline
occurred because some of its large business customers converted to the
transportation service offered by AWG and Associated 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.
As discussed earlier, Associated purchases a portion of its gas supply at
the wellhead from one of the Company's gas producing subsidiaries under a long-
term firm contract entered into in October, 1990. As a result of recent gas cost
audits in Missouri for the two-year period ended August 31, 1992, the Staff
recommended disallowance of approximately $3.1 million in gas costs incurred
under this contract. This amount represents the difference between the price
paid by Associated and a spot market index price for gas delivered into an
interstate pipeline operating in the Arkoma Basin. The price paid by Associated
under the contract was $1.90 per Mcf during the period in question. In making
its recommendation, the Staff acknowledged that Associated had lowered its gas
cost and saved its ratepayers money by purchasing gas from its affiliate. The
Staff also acknowledged that the appropriate price for purchases made under this
long-term firm contract should include a premium over the spot market price.
However, a Staff consultant testified that there was insufficient data upon
which to determine an appropriate premium over a spot market index for pricing
purchases under this contract and that he was unable to determine what the
appropriate premium should be. A hearing was held on January 31, 1995. The
Company presented testimony to demonstrate that the price paid under the
contract was at or below the market price for contracts with similar terms
during the period in which the purchases were made. The APSC previously reviewed
the costs charged to Arkansas ratepayers under this contract and found them to
be proper and allowable for recovery. The Missouri Commission has not yet issued
an order in this proceeding. The Staff has also audited Associated's gas
purchases for the period from September, 1992 through August, 1993 and
recommended no changes to the gas costs for that period.
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
7
<PAGE>
fluctuations in temperature in recent years as the structure of the Company's
utility rates has become somewhat flatter; i.e., most recovery of return on rate
base is built into a customer charge and the first step of its rates.
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 3.5% to 4.0% annually,
while Associated has experienced customer growth of 1% to 2% 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. As previously mentioned, the APSC
and the Missouri Commission regulate the Company's utility rates and operations.
Late in 1990, the APSC and the Missouri Commission approved rate increases for
the Company totaling $7.4 million annually. AWG received an increase of $5.7
million annually and Associated was awarded an increase of $.9 million annually
for its Missouri properties and $.8 million annually for its system in Arkansas.
Rate increase requests which may be filed in the future will depend upon
customer growth, increases in operating expenses, and additional investments in
property, plant and equipment. AWG is precluded from filing an application for a
rate increase with the APSC prior to January 1, 1996, as a result of the gas
cost settlement. The Company anticipates filing a rate increase request for AWG
in early 1996 and will continue to monitor the status of returns on the systems
operated by Associated and file rate cases as the need arises. AWG's rates for
gas delivered to its 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.
NOARK is an intrastate pipeline constructed by a limited partnership in
which SWPL holds a 47.93% general partnership interest and is the pipeline's
operator. 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. The 258 mile long
pipeline originates near the Fort Chaffee military reservation in western
Arkansas and terminates in northeast Arkansas. NOARK interconnects with three
major interstate pipelines and provides additional access to markets for gas
production of both the Company and other producers. Construction of an eight-
mile interstate pipeline connecting NOARK to the distribution system of
Associated was completed during 1993. NOARK is a public utility regulated by the
APSC. The APSC established NOARK's maximum transportation rate based on its
original construction cost estimate of approximately $73.0 million. Due to
construction problems and the addition of a compressor station, the ultimate
costs of the pipeline exceeded the original estimate by approximately $30
million. NOARK has a capacity of 141 MMcfd. In 1994, NOARK had an average daily
throughput of 82 MMcfd, compared to 79 MMcfd in 1993, its first full year of
operation. Arkansas Western has contracted for 41 MMcfd of firm capacity on
NOARK under a ten-year transportation contract. NOARK also has a five-year
transportation contract with an independent marketer to transport 50 MMcfd
through NOARK on a firm basis. The Company's exploration and production segment
was supplying 25 MMcfd of the volumes transported by the marketer under that
agreement. In late 1993, the gas marketing company filed suit against NOARK, the
Company and certain of its affiliates, and, effective January 1, 1994, ceased
transporting gas under its agreement with NOARK. The complaint and subsequent
filings seek rescission of the transportation contract and a contract to
purchase gas from the Company's affiliates, and actual and punitive damages. The
Company and NOARK both believe the suit is without merit and have filed
counterclaims seeking enforcement of the contracts and damages. The Company is
currently making its own sales arrangements and transporting production through
NOARK which was previously purchased by the marketer.
8
<PAGE>
As a result of the developments described above, NOARK is currently
incurring losses and the Company expects further losses from its equity
investment in NOARK until the pipeline is able to increase its level of
throughput and until improvement occurs in the competitive conditions which
determine the transportation rates NOARK can charge. NOARK provides additional
pipeline capacity to a portion of the Arkoma Basin in Arkansas which was not
previously adequately served by pipelines offering firm transportation. NOARK
competes primarily with two interstate pipelines in its gathering area. One of
those elected to become an open access transporter subsequent to NOARK's start
of construction. That pipeline, which was recently sold, has not offered firm
transportation, but the increased availability of interruptible transportation
service has intensified the competitive environment within which NOARK operates.
The Company and the other partners of NOARK are currently investigating options
which could improve NOARK's future financial prospects.
The Company is subject to laws and regulations relating to the protection of
the environment. The Company's policy is to accrue environmental and cleanup
related costs of a non-capital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. The Company
has no material amounts accrued at December 31, 1994. Additionally, management
believes any future remediation or other compliance related costs will not have
any material effect upon capital expenditures, earnings or the competitive
position of the Company's subsidiaries in the segments in which they operate.
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, 1994, the Company had 661 employees, 89 of whom are
represented under a collective bargaining agreement.
INDUSTRY SEGMENT AND STATISTICAL INFORMATION
The following portions of the 1994 Annual Report to Shareholders (filed as
Exhibit 13 to this filing) are hereby incorporated by reference for the purpose
of providing additional information about its business. Refer to Note 9 to the
financial statements for information about industry segments and "Financial and
Operating Statistics" for additional statistical information, including the
average sales price per unit of gas produced and of oil produced and the average
production cost per unit.
ITEM 2. PROPERTIES
The portions of the 1994 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 for information concerning areas of operation of the
Company's gas distribution systems. For information concerning the Company's
exploration and production areas of operation, also refer to the Appendix. See
the table entitled "Operating Properties" at the Appendix for information
concerning miles of pipe of the Company's gas distribution systems and for
information regarding leasehold acreage and producing wells by geographic region
of the Company's exploration and production segment. Also, see Notes 5 and 6 to
the financial statements for additional information about the Company's gas and
oil operations.
9
<PAGE>
For information concerning capital expenditures, refer to the "Capital
Expenditures" section of "Management's Discussion and Analysis of Financial
Condition and Results of Operations". Also refer to "Financial and Operating
Statistics" for information concerning gas and oil wells drilled and gas and oil
produced.
The following information is provided to supplement that presented in the
1994 Annual Report to Shareholders:
NET WELLS DRILLED DURING THE YEAR
EXPLORATORY
<TABLE>
<CAPTION>
PRODUCTIVE
YEAR WELLS DRY HOLES TOTAL
---- ---------- --------- -----
<S> <C> <C> <C>
1994........ 4.7 1.8 6.5
1993........ 2.8 4.0 6.8
1992........ 1.2 6.1 7.3
</TABLE>
<TABLE>
<CAPTION>
DEVELOPMENT
PRODUCTIVE
YEAR WELLS DRY HOLES TOTAL
---- ---------- --------- -----
<S> <C> <C> <C>
1994........ 45.5 14.7 60.2
1993........ 37.9 10.5 48.4
1992........ 53.4 13.4 66.8
WELLS IN PROGRESS AS OF DECEMBER 31, 1994
<CAPTION>
TYPE OF WELL GROSS NET
------------ ----- ---
<S> <C> <C>
Exploratory.................... 2.0 .5
Development.................... 6.0 1.6
----- -----
Total.......................... 8.0 2.1
===== =====
</TABLE>
Due to the insignificance of the Company's oil reserves and producing oil
wells to its total reserves and producing wells, separate disclosure of gas and
oil producing wells has not been made.
No individually significant discovery or other major favorable or adverse
event has occurred since December 31, 1994.
During 1994, SEECO and SEPCO were 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 1994 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
either SEECO or SEPCO is the operator.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are involved in various 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.
10
<PAGE>
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, 1994, to a vote of security holders, through the
solicitation of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following is information with regard to executive officers of the
Company:
<TABLE>
<CAPTION>
NAME OFFICER POSITION AGE
---- ---------------- ---
<C> <S> <C>
Charles E. Scharlau ........ Chairman of the Board (since 1979),
Southwestern Energy Company and 68
Subsidiaries,and Chief Executive
Officer (since 1968), Southwestern
Energy Company.
Dan B. Grubb ............... President and Chief Operating 59
Officer(since 1992), Director
(1988-1992), Southwestern Energy
Company.Chairman and Chief Executive
Officer of Grubb Industries, Inc.,and
Investor and Business Consultant
(since 1988). Previously, President
and Chief Operating Officer, Midcon
Corporation (since 1987).
Stanley D. Green ........... Executive Vice President - Finance 41
and Corporate Development
(since 1992), and Chief Financial
Officer (since 1987), Vice President
- Treasurer and Secretary
(since 1987), Controller (since 1981),
Southwestern Energy Company and
Subsidiaries.
B. Brick Robinson .......... Executive Vice President and Chief 64
Operating Officer (since 1988),
Southwestern Energy Production
Company and SEECO, Inc. (subsidiaries
of Southwestern Energy Company).
Previously, various positions
with Occidental Petroleum Corporation
and its subsidiaries, including Vice
President, Far East and Domestic
Frontier Exploration,Occidental
International (since 1985).
Gregory D. Kerley .......... Vice President - Treasurer and 39
Secretary (since 1992), and Chief
Accounting Officer (since 1990),
Controller (since 1990), Southwestern
Energy Company and Subsidiaries.
Previously, Treasurer and Controller,
Agate Petroleum, Inc. (since 1984).
</TABLE>
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.
Information concerning compliance with Section 16(a) of the Securities Exchange
Act of 1934, as amended, is presented in the definitive Proxy Statement dated
April 21, 1995, under the section entitled "Security Ownership of Directors,
Nominees and Executive Officers" and is incorporated herein by reference.
11
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The "Shareholder Information" and "Financial and Operating Statistics"
sections of the 1994 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 the Company's long-term debt instruments and agreements impose
restrictions on the payment of cash dividends. At December 31, 1994,
$121,754,000 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 earned since January 1, 1990, plus $20,000,000 less
dividends paid and purchases, redemptions or retirements of capital stock during
the period since December 4, 1991.
The Board of Directors increased the quarterly dividend by 20% in the third
quarter of 1993, to $.06 per share, equal to an annual rate of $.24 per share
(after the effect of a three-for-one stock split distributed August 5, 1993).
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
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following portions of the 1994 Annual Report to Shareholders (filed as
Exhibit 13 to this filing) are hereby incorporated by reference.
"Financial and Operating Statistics" for selected financial data of the
Company.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
The consolidated financial statements as detailed in Item 14 (a)(1) below.
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 31, 1995 (the 1995 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 1995 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 1995 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 section "Security Ownership
12
<PAGE>
of Directors, Nominees and Executive Officers" for information about security
ownership of certain beneficial owners and management.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The 1995 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" and
"Compensation Committee Interlocks and Insider Participation" 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 with its 1994 Annual Report to Shareholders (filed as
Exhibit 13 to this filing) and the report of independent auditors on such report
are hereby incorporated by reference:
Report of Independent Auditors.
Consolidated Balance Sheets as of December 31, 1994 and 1993.
Consolidated Statements of Income for the years ended December 31,
1994, 1993 and 1992.
Consolidated Statements of Cash Flows for the years ended December
31, 1994, 1993 and 1992.
Consolidated Statements of Retained Earnings for the years ended
December 31, 1994, 1993 and 1992.
Notes to Consolidated Financial Statements, December 31, 1994, 1993
and 1992.
(2) The consolidated financial statement schedules have been omitted
because they are not required under the related instructions, or are
inapplicable and therefore have been omitted.
(3) The exhibits listed on the accompanying Exhibit Index (pages 15-17)
are filed as part of, or incorporated by reference into, this Report.
(b) Reports on Form 8-K:
A Current Report on Form 8-K was filed on November 8, 1994,
regarding a news release dated October 31, 1994, announcing that two
of the Company's wholly owned subsidiaries entered into a settlement
with the Staff of the Arkansas Public Service Commission (APSC) and
the Attorney General of the State of Arkansas regarding certain gas
cost issues which had been outstanding before the APSC for almost four
years. The issues in question involved the price of gas sold by one of
the Company's gas producing subsidiaries under a long-term contract
with the Company's utility subsidiary. Under the settlement, the price
paid by the Company's utility subsidiary will be referenced to an
index plus a premium. At current market prices, the new provision will
result in a reduced sales price under the contract. The terms of the
settlement became effective as of July 1, 1994, and were approved by
the APSC on January 5, 1995. The settlement is discussed in more
detail on page 2 in the "Natural gas and oil exploration and
production" section of Item 1.
A Current Report on Form 8-K was filed on March 10, 1995,
regarding a news release dated February 23, 1995, announcing that the
Company's Board of Directors authorized the Company to repurchase up
to $30.0 million of the Company's common shares. The Company plans to
buy the shares from time to time, depending on market conditions, in
the open market or in private negotiated transactions. Shares
repurchased will be held in treasury and may be used for general
corporate purposes, including issuance under option plans. The
repurchase program will continue until terminated by the Company's
Board of Directors.
13
<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 24, 1995 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 24, 1995.
/s/ CHARLES E. SCHARLAU Director, Chairman, and
-------------------------------
Charles E. Scharlau Chief Executive Officer
Executive Vice President -
/s/ STANLEY D. GREEN Finance and Corporate Development,
-------------------------------
Stanley D. Green and Chief Financial Officer
Vice President - Treasurer
/s/ GREGORY D. KERLEY and Secretary, and
-------------------------------
Gregory D. Kerley Chief Accounting Officer
/s/ E. J. BALL Director
-------------------------------
E. J. Ball
/s/ JAMES B. COFFMAN Director
-------------------------------
James B. Coffman
/s/ JOHN PAUL HAMMERSCHMIDT Director
-------------------------------
John Paul Hammerschmidt
/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
14
<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, as amended (filed herewith).
4. 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).
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 (filed herewith).
10.2 Agreement between Southwestern Energy Company, Arkansas Western Gas
Company, Arkansas Power & Light Company and Associated Natural Gas
Company, dated September 1, 1987, as amended February 22, 1988, and May
16, 1988 (original agreement and first amendment to the Agreement
incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for
the year ended December 31, 1987; second amendment to the Agreement
thereto incorporated by reference to Exhibit 10 to Annual Report on Form
10-K for the year ended December 31, 1988).
10.3 Gas Purchase Contract between SEECO, Inc. and Associated Natural Gas
Company, dated October 1, 1990 (incorporated by reference to Exhibit 10 to
Annual Report on Form 10-K for the year ended December 31, 1990).
10.4 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).
(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).
15
<PAGE>
EXHIBIT
NO. DESCRIPTION
------- -----------
(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).
10.5 Southwestern Energy Company Supplemental Retirement Plan, adopted May 31,
1989, and Amended and Restated as of December 15, 1993 (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).
10.6 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).
10.7 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).
10.8 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).
10.9 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).
10.10 Executive Severance Agreement for Dan B. Grubb, effective July 8, 1992
(incorporated by reference to Exhibit 10.13 to Annual Report on Form 10-K
for the year ended December 31, 1992).
10.11 Executive Severance Agreement for Gregory D. Kerley, effective December
14, 1994 (filed herewith).
10.12 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; amendment filed herewith).
10.13 Employment Agreement for Dan B. Grubb, effective July 8, 1992
(incorporated by reference to Exhibit 10.16 to Annual Report on Form 10-K
for the year ended December 31, 1992).
10.14 Form of Indemnity Agreement, between the Company and each officer and
director of the Company, dated May 25, 1988 or October 9, 1991
(incorporated by reference to Exhibit 10 to Annual Report on Form 10-K for
the year ended December 31, 1988; and incorporated by reference to Exhibit
10.20 to Annual Report on Form 10-K for the year ended December 31, 1991).
10.15 Gas Transportation Agreement between NOARK Pipeline System, Limited
Partnership and Arkansas Western Gas Company, dated February 4, 1991, and
amended February 14, 1992 (original agreement incorporated by reference to
Exhibit 10.22 to Annual Report on Form 10-K for the year ended December
31, 1991; amended agreement incorporated by reference to Exhibit 10.19 to
Annual Report on Form 10-K for the year ended December 31, 1992).
10.16 Limited Partnership Agreement of NOARK Pipeline System, Limited
Partnership, dated October 10, 1991, and amended February 24, 1993
(original agreement incorporated by reference to Exhibit 10.23 to Annual
Report on Form 10-K for the year ended December 31, 1991; amended
agreement incorporated by reference to Exhibit 10.21 to Annual Report on
Form 10-K for the year ended December 31, 1992).
10.17 Operating Agreement of NOARK Pipeline System, dated March 19, 1991
(incorporated by reference to Exhibit 10.25 to Annual Report on Form 10-K
for the year ended December 31, 1991).
16
<PAGE>
EXHIBIT
NO. DESCRIPTION
------- -----------
10.18 Agreement for Sale of Partnership Interest between Southwestern Energy
Pipeline Company and GRUBB NOARK Pipeline, Inc., dated July 24, 1992
(incorporated by reference to Exhibit 10.25 to Annual Report on Form 10-K
for the year ended December 31, 1992).
13. 1994 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).
22. Subsidiaries of the Registrant (incorporated by reference to Exhibit 22 to
Annual Report on Form 10-K for the year ended December 31, 1992).
17
<PAGE>
EXHIBIT 3
SOUTHWESTERN ENERGY COMPANY
---------------------------
BY-LAWS
* * * * * *
ARTICLE I
---------
STOCKHOLDERS
SECTION 1. The place for holding all meetings of stockholders shall be the
---------
office of the Corporation in the City of Fayetteville, State of Arkansas, or at
such other place or places as shall be decided upon from time to time by the
Board of Directors of the Corporation. The presiding officer, who shall conduct
all stockholder meetings, shall be the Chairman of the Board or in the absence
of a Chairman of the Board shall be the President, or in the absence of the
President a member of the Board of Directors selected by the other members of
the Board of Directors. At any meeting requiring a vote of the stockholders for
the election of directors or for any other purpose requiring a ballot and vote
by the stockholders there shall be two judges of election, appointed by the
Chairman of the meeting, who shall take an oath of office to faithfully perform
their duties. The judges of election shall canvass the meeting, determine the
number of stockholders present in person and by proxy and determine if a quorum
is present. It shall be the duty of the judges of election to examine, validate
and tabulate the proxies voted and the votes cast in person. Upon completion of
the tabulation, their report shall be read to the meeting and the results of
such elections then formally declared by the Chairman of the meeting.
SECTION 2. VOTING: Stockholders having the right to vote shall be entitled
--------- ------
to vote at meetings either in person or by proxy appointed by instrument in
writing subscribed by the stockholder or by his duly authorized attorney. Such
stockholder shall be entitled to one vote for each share of stock having voting
power registered in his name on the books of the Company.
A complete list of the stockholders entitled to vote at any election of
directors, arranged in alphabetical order with the address of each and the
number of voting shares held by each, shall be prepared by the Secretary and
filed in the office where the election is to be held, at least ten days before
every election, and shall at all times during the usual hours for business, and
during the whole time of said election, be open to examination of any
stockholder.
SECTION 3. QUORUM: Except as provided in the next section hereof, any
--------- ------
number of stockholders together holding at least a majority of the stock issued
and outstanding and entitled to vote thereat, who shall be present in person or
represented by proxy at any meeting duly called, shall constitute a quorum for
the transaction of business.
SECTION 4. ADJOURNMENT OF MEETING: If less than a quorum shall be in
--------- ----------------------
attendance at any time for which the meeting shall have been called, the meeting
may, after the lapse of at least half an hour, be adjourned from
<PAGE>
time to time by a majority vote of the stockholders present or represented and
entitled to vote thereat. If notice of such adjourned meeting is sent to the
stockholders entitled to receive the same, such notice also containing a
statement of the purpose of the meeting and that the previous meeting failed for
lack of a quorum, and that under the provisions of this Section it is proposed
to hold the adjourned meeting with a quorum of those present, then any number of
stockholders, in person or by proxy, shall constitute a quorum at such meeting
unless otherwise provided by statute.
SECTION 5. ANNUAL ELECTION OF DIRECTORS: The annual meeting of
--------- ----------------------------
stockholders for the election of directors and the transaction of other business
shall be held on such date and at such time as may be determined by the Board of
Directors from time to time. At each annual meeting, the stockholders entitled
to vote thereat shall by plurality vote by ballot elect a Board of Directors,
and they may also transact such other corporate business as shall be stated in
the notice of meeting.
Only persons who are nominated in accordance with the following procedures
shall be eligible for election as directors. Nominations of persons for
election to the Board of Directors of the Company may be made at a meeting of
stockholders by or at the direction of the Board of Directors, by any nominating
committee or person appointed by the Board of Directors, or by any stockholder
of the Company entitled to vote for the election of directors at the meeting who
has complied with the notice procedures set forth in this Section 5 of Article
I. Such nominations, other than those made by or at the direction of the Board
of Directors, shall be made pursuant to timely notice in writing to the
secretary of the Company. To be timely, a stockholder's notice shall be
delivered to or mailed and received at the principal executive offices of the
Company not less than 50 nor more than 75 days prior to the meeting date;
provided, however, that in the event that less than 65 days' notice of the
meeting date is given to stockholders, notice by the stockholder must be so
received no later than the close of business on the 15th day following the day
on which notice of the meeting date was mailed. Such stockholder's notice shall
set forth (a) as to each nominee whom the stockholder proposes to nominate for
election or reelection as a director, (i) the name, age, business address and
residence address of the nominee, (ii) the principal occupation or employment of
the nominee, (iii) the class and number of shares of capital stock of the
Company which are beneficially owned by the nominee and (iv) any other
information relating to the nominee that is required to be disclosed in
solicitations for proxies for election of directors pursuant to Schedule 14A
under the Securities Exchange Act of 1934, as amended; and (b) as to the
stockholder giving the notice, (i) the name and record address of the
stockholder and (ii) the class and number of shares of capital stock of the
Company that are beneficially owned by the stockholder. The Company may require
any proposed nominee to furnish such other information as may reasonably be
required by the Company to determine the eligibility of such proposed nominee to
serve as a director of the Company. The presiding officer of the meeting shall,
if the facts warrant, determine that a nomination was not made in accordance
with the foregoing procedure, and if he should so determine, he may so declare
to the meeting and the defective nomination shall be disregarded.
2
<PAGE>
At any meeting of stockholders, only such business shall be conducted as
shall have been properly brought before the meeting. For business to be
properly brought before a meeting by a stockholder, the stockholder must have
given timely notice thereof to the secretary of the Company. To be timely, such
notice must be delivered to or mailed and received at the principal executive
offices of the Company not less than 50 nor more than 75 days prior to the
meeting date; provided, however, that in the event that less than 65 days'
notice of the meeting date is given to stockholders, notice by the stockholder
must be so received no later than the close of business on the 15th day
following the day on which notice of the meeting date was mailed. Such
stockholder's notice shall set forth as to each matter the stockholder proposes
to bring before the meeting: (i) a brief description of the business desired to
be brought before the meeting and the reasons for conducting such business at
the meeting, (ii) the name and address of the stockholder proposing such
business, (iii) the class and number of shares of capital stock of the Company
that are beneficially owned by such stockholder and (iv) any material interest
of such stockholder in such business. The presiding officer of the meeting
shall, if the facts warrant, determine that business was not properly brought
before the meeting in accordance with the foregoing procedure and, if he should
so determine, he may so declare to the meeting and any such business not
properly brought shall not be transacted. Notwithstanding the provisions of
this paragraph, so long as the Company is subject to Rule 14a-8 under the
Securities Exchange Act of 1934, as amended, business consisting of a proposal
properly included in the Company's proxy statement with respect to a meeting
pursuant to such Rule may be transacted at a meeting.
SECTION 6. SPECIAL MEETING - HOW CALLED: Special meetings of the
--------- ----------------------------
stockholders for any purpose or purposes may be called by the President or
Secretary, and shall be called upon a resolution in writing therefor, stating
the purpose or purposes thereof, delivered to the President or Secretary, signed
by two directors or by a majority in interest of the stockholders entitled to
vote, or by resolution of the directors.
The record date for determining stockholders entitled to request a special
meeting shall be fixed by the Board of Directors of the Company. Any
stockholder seeking to request a special meeting shall, by written notice,
request the Board of Directors to fix a record date. The Board of Directors
shall, upon receipt of such a request, fix the record date in accordance with
Section 4-27-707 of the Arkansas Business Corporation Act of 1987 (the "ABCA").
If the record date falls on a Saturday, Sunday or legal holiday, the record date
shall be the day next following which is not a Saturday, Sunday or legal
holiday.
SECTION 7. MANNER OF VOTING AT STOCKHOLDERS MEETINGS: At all meetings of
--------- -----------------------------------------
stockholders all questions, except as otherwise expressly provided by statute or
by these By-Laws, shall be determined by a majority vote of the stockholders
present in person or represented by proxy and entitled to vote; provided,
however, that any qualified voter may demand a vote by ballot, and in that case,
such vote shall immediately be taken.
3
<PAGE>
SECTION 8. NOTICE OF STOCKHOLDERS MEETING: Written or printed notice,
--------- ------------------------------
stating the place and time of the meeting, shall be given by the Secretary to
each stockholder entitled to vote thereat at his last known post office address,
at least ten (10) days before the meeting in the case of an annual meeting and
five (5) days before the meeting in the case of a special meeting.
SECTION 9. SPECIFIC POWERS OF STOCKHOLDERS: The directors in their
--------- -------------------------------
discretion may submit any contract or act for approval or ratification at any
annual meeting of the stockholders or at any meeting of the stockholders called
for the purpose of considering any such act or contract, and any contract or act
that shall be approved or be ratified by the vote of the holders of a majority
of the capital stock of the Corporation which is represented in person or by
proxy at such meeting (provided that a lawful quorum of stockholders be there
represented in person or by proxy) shall be as valid and as binding upon the
Corporation and upon all the stockholders, as though it had been approved or
ratified by every stockholder of the Corporation, whether or not the contract or
act would otherwise be open to legal attack because of directors' interest, or
for any other reason.
SECTION 10. ACTION WITHOUT MEETING:
-----------------------------------
(a) Notice of Action by Written Consent. Prompt notice of the taking of
-----------------------------------
any action without a meeting pursuant to Section 4-27-704 of the Arkansas
Business Corporation Act of 1987 (the "ABCA"), by less than unanimous written
consent, shall be given to those stockholders who have not consented in writing.
(b) Record Date. The record date for determining stockholders entitled to
-----------
express consent to an action in writing without a meeting shall be fixed by the
Board of Directors of the Company. Any stockholder seeking to have the
stockholders authorize or take action by written consent without a meeting
shall, by written notice, request the Board of Directors to fix a record date.
The Board shall, upon receipt of such a request, fix the record date in
accordance with Section 4-27-707 of the ABCA. If the record date falls on a
Saturday, Sunday or legal holiday, the record date shall be the day next
following which is not a Saturday, Sunday or legal holiday.
(c) Date of Consent. The date for determining if an action has been
---------------
consented to by the holder or holders of shares having requisite voting power to
authorize or take the action specified therein (the "Consent Date") shall be the
close of business on the 31st day after the later of (x) the record date fixed
pursuant to paragraph (b) of this Section 10 and (y) the date on which materials
soliciting consents are mailed to stockholders if such materials are required to
be mailed under applicable law. If the Consent Date falls on a Saturday, Sunday
or legal holiday, the Consent Date shall be the day next following which is not
a Saturday, Sunday or legal holiday. On or prior to the Consent Date, consents
may be revoked by written notice (i) to the Company, (ii) to the stockholder or
stockholders soliciting consents or soliciting revocations in opposition to
4
<PAGE>
action by consent proposed by the Company (the "Soliciting Stockholders"), or
(iii) to a proxy solicitor or other agent designated by the Company or the
Soliciting Stockholder.
(d) Procedures. In the event of the delivery to the Company of a written
----------
consent or consents purporting to authorize or take action and/or related
revocations (each such written consent and related revocation being referred to
in this Section 10 as a "Consent"), the Secretary of the Company shall provide
for the safekeeping of such Consent and, as soon as practicable after the
Consent Date, shall conduct such reasonable investigation as he deems necessary
or appropriate for the purpose of ascertaining the validity of such Consent and
all matters incident thereto, including, without limitation, whether the holders
of shares having the requisite voting power to authorize or take the action
specified in the Consent have given consent; provided, however, that if the
-------- -------
action to which the Consent relates is the removal or replacement of one or more
members of the Board, the Secretary of the Company shall designate two persons,
who may not be members of the Board or otherwise affiliated with the Company, or
a firm of nationally recognized independent inspectors of election, to serve as
Inspectors with respect to such Consent and such Inspectors shall discharge the
functions of the Secretary of the Company under this paragraph (d). If after
such investigation the Secretary or the Inspectors (as the case may be) shall
determine that the Consent is valid, that fact shall be certified on the records
of the Company kept for the purpose of recording the proceedings of meetings of
stockholders, and the Consent shall be filed in such records, at which time the
Consent shall become effective as stockholder action as of the fifth business
day following such certification.
ARTICLE II
----------
DIRECTORS
SECTION 1. FIRST MEETING: The newly elected directors may hold their first
--------- -------------
meeting for the purpose of organization and the transaction of business, if a
quorum be present, immediately after the annual meeting of the stockholders; or
the time and place of such meeting may be fixed by consent in writing of all the
directors.
SECTION 2. ELECTION OF OFFICERS: At such meeting the directors may elect a
--------- --------------------
Chairman of the Board and shall elect a President from their number, one or more
Vice Presidents, a Secretary and a Treasurer, who need not be directors. Such
officers shall hold office until the next annual election of officers and until
their successors are elected and qualify. In case such officer shall not be
elected at such first meeting, they may be chosen at any subsequent meeting of
directors called for the purpose.
SECTION 3. REGULAR MEETINGS: Regular meetings of the directors may be held
--------- ----------------
without notice at such place, either within or without the State of Arkansas,
and at such time as shall be determined from time to time by resolution of the
directors.
5
<PAGE>
SECTION 4. SPECIAL MEETINGS - HOW CALLED - NOTICE: Special meetings of the
--------- --------------------------------------
Board may be called by the President or by the Secretary on the written request
of any two directors upon notice given to each director by letter delivered at
least two days before the meeting or by telegram delivered at least one day
before the meeting or by such shorter telephone or other notice as the person or
persons calling the meeting may deem appropriate in the circumstances.
SECTION 5. NUMBER, QUORUM, QUALIFICATIONS AND RETIREMENT:
--------- ---------------------------------------------
(a) The number of directors shall be five (5). A majority of the directors
shall constitute a quorum for the transaction of business. Directors need not
be stockholders. Directors shall retire after reaching the age of 78 in 1995,
77 in 1996, 76 in 1997, and 75 in any year thereafter.
(b) Any director retiring in the year 1994 or after and meeting all of the
requirements of this Section 5 shall be appointed to the position of director
emeritus. Directors emeriti shall be invited, but not required, to attend each
board of directors meeting and any board committee meetings they may be assigned
to as ad hoc members. At such meetings directors emeriti shall participate in
all discussions but shall not be entitled to vote on any matter.
(c) Only existing non-employee members of the board of directors are
eligible to become directors emeriti. Employee members of the board of
directors will become eligible for the position of director emeritus after their
employee status has ended. Any director becoming a director emeritus is no
longer eligible for election as a director.
(d) A director shall become a director emeritus and not eligible for
renomination as director after 20 years of service and having attained the age
of 78 in 1995, 77 in 1996, 76 in 1997, and 75 in any year thereafter.
(e) A director emeritus may resign at any time. A director emeritus shall
be discharged if that director emeritus shall fail to attend, except for good
cause, three consecutive regularly scheduled meetings or one half of the regular
scheduled meetings in a calendar year.
A director emeritus shall receive a fee of $1,000 for each meeting attended
or such other fee as may be set by the board of directors and shall be
reimbursed for his reasonable expenses incurred in attending a meeting.
SECTION 6. PLACE OF MEETING: The directors may hold their meetings and
--------- ----------------
have one or more offices, and keep the books of the Company outside the State of
Arkansas, at any office or offices of the Company, or at any other place as they
may from time to time by resolution determine; provided, however, that a
duplicate stock ledger shall always be kept at the principal office in Arkansas.
6
<PAGE>
SECTION 7. GENERAL POWERS OF DIRECTORS: The Board of Directors shall have
--------- ---------------------------
the management of the business of the Company, and subject to the
restrictions imposed by law, by the Certificate of Incorporation, or by these
By-Laws, may exercise all the powers of the Corporation.
SECTION 8. SPECIFIC POWERS OF DIRECTORS: Without prejudice to such general
--------- ----------------------------
powers it is hereby expressly declared that the directors shall have the
following powers, to wit:
(1) To adopt and alter a common seal of the Corporation.
(2) To make and change regulations, not inconsistent with these By-Laws, for
the management of the Company's business and affairs.
(3) To purchase or otherwise acquire for the Company any property, rights or
privileges which the Company is authorized to acquire.
(4) To pay for any property purchased for the Company either wholly or
partly in money, stock, bonds, debentures or other securities of the
Company.
(5) To borrow money and to make and issue notes, bonds and other negotiable
and transferable instruments, mortgages, deeds of trust and trust
agreements, and to do every act and thing necessary to effectuate the
same.
(6) To remove any officer for cause, or any officer other than the President
summarily without cause, and in their discretion, from time to time, to
devolve the powers and duties of any officer upon any other person for
the time being.
(7) To appoint and remove or suspend such subordinate officers, agents or
factors, as they may deem necessary, and to determine their duties, and
fix and, from time to time, change their salaries or remuneration, and
to require security as and when they think fit.
(8) To confer upon any officer of the Company the power to appoint, remove
and suspend subordinate officers, agents and factors.
(9) To determine who shall be authorized on the Company's behalf to make and
sign bills, notes, acceptances, endorsements, checks, releases,
receipts, contracts and other instruments.
(10) To determine who shall be entitled to vote in the name and behalf of
the Company, or to assign and transfer, any shares of stock, bonds, or
other securities of other corporations held by the Company.
(11) To delegate any of the powers of the Board in relation to the ordinary
business of the Company to any standing or special committee, or to any
officer, or agent (with power of subdelegate), upon such terms as they
think fit.
7
<PAGE>
(12) To call special meetings of the stockholders for any purpose or
purposes.
(13) To submit any contract or act for authorization or ratification by the
stockholders in the manner and with the effect provided in Section 9 of
Article I.
SECTION 9. COMPENSATION OF DIRECTORS: By resolution of the Board, the
--------- -------------------------
directors may be paid their expenses of attendance and may be paid a fixed fee
for attendance at each meeting of the Board of Directors or a stated fee as
director. No such payment or anything herein contained shall preclude any
director from serving the Company in any other capacity as an officer, attorney,
agent or otherwise and receiving compensation therefor.
ARTICLE III
-----------
EXECUTIVE COMMITTEE
SECTION 1. HOW APPOINTED: The directors may appoint from their number an
--------- -------------
executive committee which may make its own rules of procedure and shall meet
where and as provided by such rules, or by a resolution of the directors. A
majority shall constitute a quorum, and in every case the affirmative vote of a
majority of all the members of the committee shall be necessary to the adoption
of any resolution.
SECTION 2. POWERS: During the intervals between the meetings of the
--------- ------
directors the executive committee shall have and may exercise all the powers of
the directors in the management of the business and affairs of the Company,
including power to authorize the seal of the Company to be affixed to all papers
which may require it, in such manner as such committee shall deem best for the
interests of the Company, in all cases in which specific directions shall not
have been given by the directors.
ARTICLE IV
----------
OFFICERS
SECTION 1. The officers of the Company may be a Chairman of the Board,
---------
which office may be filled by resolution of the Board of Directors, and shall be
a President, one or more Vice Presidents, one of whom to be designated as
Executive Vice President and shall have senior authority, a Secretary, a
Treasurer, and such assistants and other officers as may from time to time be
elected or appointed by the Board of Directors. Any two offices (but not more
than two) may be held by the same person.
SECTION 2. CHAIRMAN OF THE BOARD OF DIRECTORS: The Chairman of the Board
--------- ----------------------------------
of Directors shall preside at all meetings of the stockholders and of the Board
of Directors; and by virtue of his office shall be a member of the executive
committee. He shall have supervision of such matters as may be designated to
him by the Board of Directors or the executive committee.
8
<PAGE>
SECTION 2-A. VICE CHAIRMAN OF THE BOARD OF DIRECTORS: The Vice Chairman of
----------- ---------------------------------------
the Board of Directors shall be vested with all the powers and shall perform all
the duties of the Chairman in the absence or disability of the latter unless or
until the Board of Directors shall otherwise determine. He shall have such
other powers and perform such other duties as shall be prescribed by the Board
of Directors.
SECTION 3. PRESIDENT: The President shall, in the absence of a Chairman of
--------- ---------
the Board, preside at all meetings of the directors, and act as Chairman at, and
call to order all meetings of the stockholders; and he shall have power to call
special meetings of the stockholders and directors for any purpose or purposes,
appoint and discharge, subject to the approval of the directors, employees and
agents of the Corporation and fix their compensation, make and sign contracts
and agreements in the name and behalf of the Corporation, except that he be not
authorized to dispose or encumber material assets of the Corporation without the
authority of the Board of Directors, and while the directors and/or committees
are not in session he shall have general management and control of the business
and affairs of the Corporation; he shall see that the books, reports, statements
and certificates required by the statute under which this Corporation is
organized or any other laws applicable thereto are properly kept, made and filed
according to law; and he shall generally do and perform all acts incident to the
office of President, or which are authorized or required by law.
SECTION 4. VICE PRESIDENTS: The Vice Presidents in the order of their
--------- ---------------
seniority shall be vested with all the powers and shall perform all the duties
of the President in the absence or disability of the latter, unless or until the
directors shall otherwise determine. They shall have such other powers and
perform such other duties as shall be prescribed by the directors.
SECTION 5. SECRETARY: The Secretary shall give, or cause to be given,
--------- ---------
notice of all meetings of the stockholders and directors, and all other notices
required by law or by these By-Laws, and in case of his absence or refusal or
neglect so to do, any such notice may be given by any person thereunto directed
by the President, or by the directors or stockholders upon whose requisition the
meeting is called as provided in these By-Laws. He shall record all proceedings
of the meetings of the Corporation and of the directors in a book to be kept for
that purpose, and shall perform such other duties as may be assigned to him by
the directors or the President. He shall have custody of the seal of the
Company and shall affix the same to all instruments requiring it, when
authorized by the directors or the President, and attest the same. He shall be
sworn to the faithful discharge of his duties.
SECTION 6. ASSISTANT SECRETARY: The Assistant Secretary shall be vested
--------- -------------------
with the powers and shall perform all the duties of Secretary in the absence or
disability of the latter, unless or until the directors shall otherwise
determine. He shall have such other powers and perform such other duties as
shall be prescribed by the directors.
SECTION 7. TREASURER: The Treasurer shall have the custody of all funds,
--------- ---------
securities, evidences of indebtedness and other valuable documents
9
<PAGE>
of the Company; he shall receive and give or cause to be given receipts and
acquittances for moneys paid in on account of the Company and shall pay out of
the funds on hand all just debts of the Company of whatever nature upon maturity
of the same; he shall enter or cause to be entered in books of the Company to be
kept for that purpose full and accurate accounts of all monies received and paid
out on account of the Company, and, whenever required by the President or the
Board of Directors, he shall render a statement of his cash accounts. He shall,
unless otherwise determined by the Board of Directors, have charge of the
original stock books, transfer books and stock ledgers and act as transfer agent
in respect of the stock and securities of the Company; he shall prepare and
submit from time to time to the Board of Directors financial, cash and operating
budgets or estimates; he shall prepare and submit such other financial data and
information as he shall be directed to by the Board of Directors; and he shall
perform all of the other duties incident to the office of Treasurer. He shall
give the Company a bond for the faithful discharge of his duties in such amount
and with such surety as the Board of Directors shall prescribe.
SECTION 8. ASSISTANT TREASURER: The Assistant Treasurer shall be vested
--------- -------------------
with all the powers and shall perform all the duties of Treasurer in the absence
or disability of the latter, unless or until the directors shall otherwise
determine. He shall have such other powers and perform such other duties as
shall be prescribed by the directors.
SECTION 9. CONTROLLER: The Corporate Controller shall be responsible for
--------- ----------
directing the Corporation's accounting functions. Specific areas include the
development and maintenance of planning and budgeting systems, analysis and
interpretation of trends requiring management's attention, the preparation of
financial and management reports and procedures, and senior management.
Ancillary responsibilities include the supervision of external auditors, and
participation in the planning and execution of the utility rate cases.
ARTICLE V
---------
RESIGNATIONS: FILLING OF VACANCIES:
INCREASE OF NUMBER OF DIRECTORS
SECTION 1. RESIGNATIONS: Any director, member of a committee or other
--------- ------------
officer may resign at any time. Such resignation shall be made in writing and
shall take effect at the time specified therein, and if no time be specified, at
the time of its receipt by the President or Secretary. The acceptance of a
resignation shall not be necessary to make it effective.
SECTION 2. FILLING OF VACANCIES: If the office of any director, member of
--------- --------------------
a committee or other office becomes vacant, the directors in office may appoint
any qualified person to fill such vacancy, who shall hold office for the
unexpired term and until his successor shall be duly chosen.
10
<PAGE>
SECTION 3. INCREASE OF NUMBER OF DIRECTORS: The number of directors may be
--------- -------------------------------
increased at any time by the affirmative vote of a majority of the directors,
(or, by the affirmative vote of a majority in interest of the stockholders), at
a special meeting called for that purpose, and by like vote the additional
directors may be chosen at such meeting to hold office until the next annual
election and until their successors are elected and qualify.
ARTICLE VI
----------
CAPITAL STOCK
SECTION 1. ISSUE OF CERTIFICATES OF STOCK: The President shall cause to be
--------- ------------------------------
issued to each stockholder one or more certificates, under the seal of the
Company, signed by the President or Vice President and the Treasurer or
Assistant Treasurer, or Secretary or Assistant Secretary, certifying the number
of shares owned by him in the Company; provided, when any such certificate is
signed by a transfer agent or registrar, the signature of any officer of the
Company or its corporate seal, or both such signatures and seal, may be
facsimiles engraved or printed.
SECTION 2. LOST CERTIFICATES: A new certificate of stock may be issued in
--------- -----------------
the place of any certificate theretofore issued by the Corporation, alleged to
have been lost or destroyed, and the directors may, in their discretion, require
the owner of the lost or destroyed certificate, or his legal representatives, to
give the Corporation a bond, in such sum as they may direct, not exceeding
double the value of the stock, to indemnify the Company against any claim that
may be made against it on account of the alleged loss of any such certificate or
the issuance of any such new certificate.
SECTION 3. TRANSFER OF SHARES: The shares of stock of the Company shall be
--------- ------------------
transferable only upon its books by the holders thereof in person or by their
duly authorized attorneys or legal representatives, and upon such transfer the
old certificates shall be surrendered to the Company by the delivery thereof to
the person in charge of the stock and transfer books and ledgers, or to such
other person as the directors may designate, by whom they shall be cancelled,
and new certificates shall thereupon be issued. A record shall be made of each
transfer and whenever a transfer shall be made for collateral security, and not
absolutely, it shall be so expressed in the entry of the transfer.
SECTION 4. CLOSING OF TRANSFER BOOKS: The Board of Directors shall have
--------- -------------------------
power to close the stock transfer books of the Corporation for a period not
exceeding twenty (20) days preceding the date of any meeting of stockholders or
the date for payment of any dividend or the date for the allotment of rights or
the date when any change or conversion or exchange of capital stock shall go
into effect; provided, however, that in lieu of closing the stock transfer books
as aforesaid, the Board of Directors may fix in advance a date, not exceeding
sixty-five (65) days preceding the date of any meeting of stockholders or the
date for the payment of any dividend, or the date for the allotment of rights,
or the date when any change or conversion or exchange of capital stock shall go
into effect, as
11
<PAGE>
a record date for the determination of the stockholders entitled to notice of,
and to vote at, any such meeting, or entitled to receive payment of any such
dividend or to any such allotment of rights, or to exercise the rights in
respect of any such change, conversion or exchange of capital stock, and in such
case such stockholders only as shall be stockholders of record on the date so
fixed shall be entitled to such notice of, and to vote at, such meeting, or to
receive payment of such dividend, or to receive such allotment rights, or to
exercise such rights, as the case may be, not withstanding any transfer of any
stock on the books of the Corporation after such record date fixed as aforesaid.
SECTION 5. DIVIDENDS: The directors may declare dividends from the surplus
--------- ---------
or net profits arising from the business of the Corporation as and when they
deem expedient. Before declaring any dividend there may be reserved out of the
accumulated profits such sum or sums as the directors from time to time in their
discretion think proper for working capital or as a reserve fund to meeting
contingencies or for equalizing dividends or for such other purposes as the
directors shall think conducive to the interests of the Company. The directors
may close the transfer books for not exceeding twenty (20) days next preceding
the day appointed for the payment of any dividend.
ARTICLE VII
-----------
MISCELLANEOUS PROVISIONS
SECTION 1. CORPORATE SEAL: The corporate seal shall be circular in form
--------- --------------
and shall contain the name of the Corporation, and the word "Seal." Said seal
may be used by causing it or a facsimile thereof to be impressed or affixed or
reproduced or otherwise.
SECTION 2. FISCAL YEAR: The fiscal year of the Company shall be the
--------- -----------
calendar year.
SECTION 3. PRINCIPAL OFFICE: The principal office of this Corporation
--------- ----------------
shall be established and maintained at 1083 Sain Street in the City of
Fayetteville, Washington County, State of Arkansas, and there shall be kept at
such office a book containing the names alphabetically arranged of stockholders
of the Corporation and their addresses and the number of shares held by them
respectively.
SECTION 4. CHECKS, DRAFTS, NOTES: All checks, drafts or other orders for
--------- ---------------------
the payment of money, notes, or other evidences of indebtedness issued in the
name of the Corporation shall be signed by the President or such other officer
or officers, agent or agents of the Corporation, and in such manner as shall
from time to time be determined by resolution of the Board of Directors.
SECTION 5. NOTICE AND WAIVER OF NOTICE: Whenever any notice is required by
--------- ---------------------------
these By-Laws to be given, personal notice is not meant unless expressly so
stated, and any notice so required shall be deemed to be sufficient if given by
depositing the same in a post office box in a sealed postpaid wrapper, addressed
to the person entitled thereto at his last
12
<PAGE>
known post office address, and such notice shall be deemed to have been given on
the date of such mailing. Any notice required to be given under these By-Laws
may be waived by the person entitled thereto. Stockholders not entitled to vote
shall not be entitled to receive notice of any meetings except as otherwise
provided by statute.
SECTION 6. INDEMNIFICATION OF DIRECTORS AND OFFICERS: Directors and
--------- -----------------------------------------
officers of the Company shall be indemnified to the fullest extent now or
hereafter permitted by law in connection with any actual or threatened action or
proceeding (including civil, criminal, administrative or investigative
proceedings) arising out of their service to the Company or to any other
organization at the Company's request. Employees and agents of the Company who
are not directors or officers thereof may be similarly indemnified in respect of
such service to the extent authorized at any time by the Board of Directors.
The provisions of this Section shall be applicable to actions or proceedings
commenced after the adoption hereof, whether arising from acts or omissions
occurring before or after the adoption hereof, and to persons who have ceased to
be directors, officers or employees and shall inure to the benefit of their
heirs, executors, and administrators. For the purposes of this Section,
directors, officers, trustees or employees of an organization shall be deemed to
be rendering service thereto at the Company's request if such organization is,
directly or indirectly, a wholly owned subsidiary of the Company or is
designated by the Board of Directors as an organization service to which shall
be deemed to be so rendered.
SECTION 7. ADVANCEMENT OF LITIGATION EXPENSES: Expenses incurred by a
----------------------------------------------
director or officer of the Corporation in defending any actual or threatened
action, or proceeding (including civil, criminal, administrative or
investigative proceedings) arising out of their service to the Company or to any
other organization at the Company's request shall be paid by the Company in
advance of the final disposition of such action or proceeding upon receipt of an
undertaking by, or on behalf of, such person to repay such amount if it shall
ultimately be determined that he is not entitled to be indemnified by the
Company as authorized by the relevant provisions of the Arkansas Business
Corporation Act as it now exists or as it may hereafter be amended. Such
expenses of employees and agents of the Company who are not directors or
officers may be similarly advanced to the extent authorized at any time by the
Board of Directors. The provisions of this section shall be applicable to
actions or proceedings commenced after the adoption hereof, whether arising from
acts occurring before or after the adoption hereof, and to persons who have
ceased to be directors, officers, and employees and shall inure to the benefit
of their heirs, executors, and administrators. For the purposes of this section,
directors, officers, trustees, or employees of an organization shall be deemed
to be rendering service thereto at the Company's request if such organization
is, directly or indirectly, a wholly owned subsidiary of the Company or is
designated by the Board of Directors as an organization service to which shall
be deemed to be so rendered.
13
<PAGE>
ARTICLE VIII
------------
AMENDMENTS
SECTION 1. AMENDMENT OF BY-LAWS: The stockholders, by the affirmative vote
--------- --------------------
of the holders of a majority of the stock issued and outstanding, or the
directors, by the affirmative vote of a majority of the directors, may at any
meeting, provided the substance of the proposed amendment shall have been stated
in the notice of the meeting, amend or alter any of these By-Laws.
1/95
14
<PAGE>
EXHIBIT 10.1
GAS PURCHASE AGREEMENT
AMENDED AND RESTATED CONTRACT 59
between
SEECO, INC.
SELLER
and
ARKANSAS WESTERN GAS COMPANY
BUYER
<PAGE>
ARKANSAS WESTERN GAS COMPANY
GAS PURCHASE CONTRACT
SELLER: SEECO, INC.
CONTENTS
--------
<TABLE>
<CAPTION>
Section Page
------- ----
<S> <C>
1. Definitions................................................... 1
2. Term.......................................................... 3
3. Delivery...................................................... 3
4. Equipment..................................................... 3
5. Price......................................................... 3
6. Taxes......................................................... 4
7. Pressure...................................................... 4
8. Quantities.................................................... 5
9. Royalties..................................................... 7
10. General Terms and Conditions.................................. 8
11. Condensate.................................................... 8
Signature of the Parties........................................... 9
</TABLE>
GENERAL TERMS AND CONDITIONS SUPPLEMENT
---------------------------------------
(A) Measurement (H) Force Majeure
(B) Quality (I) Warranty
(C) Addresses and Notices (J) Termination on Default
(D) Successors and Assigns (K) Arbitration
(E) Multiple Completions (L) Commingled Stream
(F) Easements (M) Operation of Wells
(G) Government Regulations
<PAGE>
EXHIBIT A
AMENDED AND RESTATED CONTRACT 59
<PAGE>
THIS AGREEMENT, executed this 3rd day of February, 1995, by and between
ARKANSAS WESTERN GAS COMPANY, an Arkansas corporation, hereby referred to as
"Buyer," and SEECO, INC., an Arkansas corporation herein referred to as
"Seller."
WITNESSETH THAT:
1. Buyer and Seller have previously entered into a gas purchase contract
dated July 24, 1978, which is known to the parties as "Contract 59." As a
result of a certain stipulation and agreement entered into by the parties in
Arkansas Public Service Commission Docket No. 92-028-U, the parties desire to
amend and restate Contract 59 to include the terms contained herein. This
Amended and Restated Contract 59 constitutes the entire agreement of the parties
with respect to the subject matter hereof from the Effective Date forward and
supersedes all previous versions of Contract 59 and all previous amendments
thereto.
THEREFORE, for and in consideration of the premises and mutual covenants
herein contained, the parties hereby contract as follows:
Section 1: DEFINITIONS. As used in this contract, the following terms and
-----------
phrases shall have the following particular meanings.
(A) "AWG Division" refers to Buyer's Northwest Arkansas gas utility
--------------
operations but shall not include the operations of Buyer's Associated Natural
Gas Company Division in Northeast Arkansas and parts of Missouri.
(B) "Contract Year" shall be the same as the calendar year, except that the
---------------
first Contract Year shall begin on the Effective Date and end on December 31,
1994, while the last Contract Year shall begin on January 1, 1998 and end on
July 24, 1998.
(C) "Contract Annual Volume" refers to an annual volume equal to 9.0
------------------------
billion cubic
1
<PAGE>
feet ("Bcf"), however, for the period from the Effective Date to December 31,
1994, the Contract Annual Volume shall be 4.906 Bcf, and for the period January
1, 1998 to the Primary Expiration Date, the Contract Annual Volume shall be 5.25
Bcf.
(D) "Contract Daily Maximum" refers to 58,000 Mcf/d.
------------------------
(E) "Contract Price Schedule" refers to the price to be paid for gas
-------------------------
delivered hereunder during the term hereof. Gas shall be assumed to be
delivered on a dry basis, subject to such adjustments as may be authorized by
the contract. The price per thousand cubic feet ("Mcf") payable for volumes
purchased hereunder shall be equal to 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 from Arkansas and Oklahoma plus the premiums described below:
<TABLE>
<CAPTION>
Contract Year Volume Premium
------------------------ --------- ---------
<S> <C> <C>
1994 (July 1 - 3.816 Bcf $.95/Mcf
December 31) 1.09 Bcf $.50/Mcf
1995 7.0 Bcf $.95/Mcf
2.0 Bcf $.50/Mcf
1996 7.0 Bcf $.95/Mcf
2.0 Bcf $.50/Mcf
1997 7.0 Bcf $.95/Mcf
2.0 Bcf $.50/Mcf
1998 (January 1 - 4.083 Bcf $.95/Mcf
July 24) 1.167 Bcf $.50/Mcf
</TABLE>
During each month of each Contract Year, the different premiums will be applied
on a pro rata basis to all purchases made hereunder throughout the Contract Year
up to the Contract Annual Volume. In the event that the above described index
ceases to be available, Buyer and Seller
2
<PAGE>
shall select a mutually agreeable replacement index as promptly as possible.
(F) "Effective Date" refers to the date July 1, 1994.
----------------
(G) "Primary Expiration Date" refers to 7:00 a.m. on July 24, 1998.
-------------------------
(H) "Point(s) of Delivery" refers to the inlet of Buyer's metering
----------------------
facilities to be located at or near each of the wells from which gas is
delivered hereunder or such other point or points as may be designated by Seller
from time to time. All Points of Delivery shall be either directly connected to
Buyer's system or deliverable to Buyer's system at no additional cost to Buyer.
Section 2: TERM.
----
This contract shall continue in effect until the Primary Expiration Date.
Section 3: DELIVERY.
--------
The gas shall be delivered and title and responsibility shall pass to Buyer
at the Point of Delivery. Responsibility for damage caused by, or arising out
of possession of, the gas prior to its passage at the Point of Delivery shall be
borne by Seller.
Section 4: EQUIPMENT.
---------
Seller, at Seller's sole cost, risk and expense, shall be responsible for
the diligent and workmanlike construction, operation and maintenance of all
equipment and roads necessary to enable Seller to effect deliveries of gas in
accordance with the contract to Buyer at the Point of Delivery. Buyer shall be
responsible for the diligent and workmanlike construction, operation and
maintenance of all equipment necessary to receive deliveries of gas under this
contract at the Point of Delivery.
Section 5: PRICE.
-----
3
<PAGE>
(A) Subject to the other provisions hereof, Buyer shall pay to Seller the
applicable price under the Contract Price Schedule for each Mcf of gas delivered
to Buyer hereunder.
(B) Buyer agrees to pay Seller on or before the twenty-fifth (25th) day of
each calendar month following Buyer's accounting month for all gas delivered
during such prior accounting month.
(C) Should the heating value of the gas delivered hereunder be found to be
more or less than one thousand (1,000) British thermal units ("Btu") per cubic
foot, the price provided for in this Section 5 shall be adjusted by multiplying
the price otherwise payable by a fraction whose numerator is the Btu content of
gas delivered hereunder, measured on a dry basis, and whose denominator is one
thousand (1,000). There shall be no other adjustments to the price payable
hereunder.
Section 6: TAXES.
-----
All taxes now or hereafter imposed in respect of any production from wells
from which gas is delivered hereunder shall be accounted for and paid to the
taxing authority by the party liable for such tax under the language of the
statute imposing same, provided that Buyer shall have the right, at Buyer's
option, to account for and pay to the taxing authority for Seller's account any
or all such taxes for which Seller may be liable. Buyer further agrees to
reimburse Seller for 100% of any new, increased or additional taxes (exclusive
of ad valorem or income taxes) imposed after July 24, 1978 on gas prior to
delivery to Buyer.
Section 7: PRESSURE.
--------
Seller shall deliver gas hereunder at the normal operating pressure
contained in Buyer's pipeline system from time to time.
4
<PAGE>
Section 8: QUANTITIES.
----------
(A) (1) Subject to the further provisions hereof, Buyer agrees to
purchase and receive during each Contract Year the Contract Annual volume.
(2) Buyer's receipts of gas hereunder will fluctuate from time to time
because of Buyer's fluctuating requirements for its system, and Buyer shall take
gas hereunder at a rate which matches as closely as reasonably possible the rate
of consumption of its AWG Division utility sales customers; provided, however,
that Buyer may take gas for injection into its storage facilities in such
volumes and at such times as Buyer reasonably deems necessary to meet the
requirements of its AWG Division utility customers. Buyer shall balance its
receipts hereunder over each Contract Year in order to receive the Contract
Annual Volume for that Contract Year, provided that to permit such balancing of
receipts Buyer shall have the right to require deliveries hereunder at a daily
rate of at least the Contract Daily Maximum. Nothing herein is intended to
limit Buyer's right to request deliveries from time to time at daily rates in
excess of the Contract Daily Maximum provided Seller is willing and able to sell
such excess volumes hereunder.
(B) The provisions of this section are subject to all the other terms and
conditions of this contract and the rules and regulations of any regulatory
authority having jurisdiction.
(C) Buyer may request to purchase hereunder, in addition to the Contract
Annual Volumes provided to be received hereunder, such additional volumes of gas
as Buyer may in the prudent operation of its business require from time to time
and which Seller is willing and able to sell hereunder. The price payable by
Buyer for such volumes shall be determined in the month of delivery using the
same index, assumptions, and adjustments described in the Contract
5
<PAGE>
Price Schedule plus a total premium over the index of $.50/Mcf.
(D) Seller recognizes that the efficient conduct of Buyer's business
requires the operation of Points of Delivery in accordance with the demands of
the system taking into consideration Buyer's take requirements under other gas
purchase contracts, and Seller agrees that Buyer shall operate any wells
designated as Points of Delivery and which are directly connected to Buyer's
pipeline system, as well as any other Points of Delivery which are directly
connected to Buyer's pipeline system, in accordance with the needs of its
utility system and with good field operating practices, and Buyer shall supply
at its sole cost and expense and by its own means and methods such labor as may
be required to operate said wells or other Points of Delivery and to perform
such other duties as are ordinarily required in the regular course of producing
and operating said wells or other Points of Delivery except that any remedial
work on wells such as a well workover or a recompletion shall be done by and
paid by Seller.
(E) Seller may designate additional wells to be connected to Buyer's
system, and Buyer shall promptly connect such wells; provided however, that
Buyer shall not be obligated, but shall have the right at its option, to connect
its system to and receive gas from any particular well or wells if Buyer's
estimate of the cost of the facilities necessary to connect the well to Buyer's
then existing system is more than $20,000 per Bcf of gas reserves. By "cost of
facilities" is meant the cost of the right of way, cost of pipe and other
equipment necessary, and cost of installing same. If it is not economically
feasible for Buyer to connect to a well under the foregoing cost standard,
Buyer, at Seller's request, shall make such connection if Seller shall agree to
contribute to Buyer the portion of the actual cost of the facilities in excess
of $20,000 per Bcf of gas reserves, as set forth above, or Seller may, at
Seller's option and at Seller's cost,
6
<PAGE>
risk and expense, install, own, operate and maintain the necessary facilities to
deliver gas from the particular well to Buyer at a mutually agreeable point
which is close enough to Buyer's then existing system so that it will be
"economically feasible" under the cost standard hereinabove set forth for Buyer
to connect to such mutually agreeable point; and, in such event, Buyer shall be
obligated to connect to that point, and the "Point of Delivery" for purposes of
this contract as to the gas from that particular well shall be the inlet of
Buyer's meter installation at that point.
Section 9: ROYALTIES.
---------
Seller shall bear all royalties, overriding royalties, production payments,
and other payments and settlements of whatsoever kind and nature due with
respect to production delivered hereunder or the failure to deliver, and shall
hold Buyer harmless against all claims, losses, damages and expenses on account
of such settlements. Seller further agrees to indemnify Buyer against any and
all royalty owner claims arising prior to July 1, 1994 or subsequently as a
result of any actions taken under a certain stipulation and agreement dated
October 31, 1994 in Arkansas Public Service Commission Docket No. 92-028-U or
this Amended and Restated Contract 59.
Seller will from time to time on request furnish to Buyer reasonable
evidence of title, including abstracts and division orders covering all
interests in gas subject to this agreement, but no examination, reliance, or
action of Buyer thereon or pursuant thereto shall impair Seller's warranties and
other agreements in this section contained. Buyer agrees to deduct from sums
owing by it hereunder the amounts due to the respective holders of royalty and
any overriding royalty interests and to holders of undivided leasehold or
mineral interests controlled but not
7
<PAGE>
owned by Seller and to pay such amounts direct to the persons entitled thereto
according to the applicable division orders, accounting to Seller only for the
remainder. It is understood that Buyer may from time to time deduct from any
monies payable hereunder on account of gas purchased, pro rata, and pay over to
governmental authorities, the amount of any and all taxes or other proper
charges due to governmental authorities on account of the production or sale of
natural gas purchased by Buyer hereunder, if required or permitted by applicable
law or regulation to be deducted from the purchase price of gas for purposes of
such payment over.
In the event that any of Seller's leasehold or mineral interests in any
well designated as a Point of Delivery or its right to sell gas hereunder or any
royalty, overriding royalty or other interest in subject gas shall be called in
question at any time by pending litigation, in law or in equity, or by formal
notice from one or more adverse claimants directed to Buyer, Buyer may withhold
without interest sums accruing hereunder on account of the interest or interests
so called in question until the question shall be finally adjudicated or
compromised or until there shall be furnished to Buyer a corporate surety bond
in form and amount satisfactory to Buyer protecting it from all loss or expense
it may suffer or incur by reason of the controversy; provided that no provision
of this section and no action taken pursuant thereto shall be construed to
relieve Seller of its warranties and other agreements in this section contained.
Section 10. GENERAL TERMS AND CONDITIONS.
----------------------------
Additional terms and conditions are set forth in the "General Terms and
Conditions Supplement" which is attached hereto, identified herewith, and hereby
made part hereof by this reference, and said terms and conditions constitute
part of this contract.
Section 11. CONDENSATE.
----------
8
<PAGE>
Seller shall have the right to operate standard type oil field separators
or low temperature separation equipment to separate condensate from the gas
prior to delivery hereunder, and the condensate thus separated shall be disposed
of by Seller free of this contract. No accounting shall be due Seller by Buyer
in respect of any liquefied or liquefiable hydrocarbons carried by or
recoverable from the gas delivered hereunder.
IN WITNESS WHEREOF, this contract has been executed in duplicate original
counterparts by the parties on the date first above written.
ARKANSAS WESTERN GAS COMPANY SEECO, INC.
By:_____________________________ By:________________________________
ATTEST: ATTEST:
________________________________ ___________________________________
9
<PAGE>
GENERAL TERMS AND CONDITIONS SUPPLEMENT
---------------------------------------
This supplement is attached to and constitutes part of the Amended and
Restated Contract 59 between ARKANSAS WESTERN GAS COMPANY, as Buyer, and SEECO,
INC., as Seller, dated February 3, 1995.
(A) MEASUREMENT
-----------
(1) Except as may be otherwise specifically provided elsewhere herein,
the measurement of gas delivered and received hereunder shall be in accordance
with the following.
(a) The unit of volume hereunder shall be 1,000 cubic feet of gas
(sometimes herein referred to as Mcf) as the standard temperature base and
standard pressure base specified in the Standard Gas Measurement Law of the
State in which the gas is delivered. Whenever the actual conditions of pressure
and temperature of the particular gas stream being measured differ from the
above standard bases, conversion of the volume from such actual conditions to
the above standard conditions shall be made in accordance with the Ideal Gas
Laws, corrected for supercompressibility as required under Standard Gas
Measurement Law of the State in which the gas is delivered in accordance with
the method customarily used by Buyer in that State. Buyer may use any
applicable findings and field rules of regulatory authorities with jurisdiction
for purposes of computations hereunder.
(b) Measurements of gas hereunder shall always be in accordance
with the requirements of law, and if the procedures, bases, or standards which
this contract contemplates will be used in the determination of gas volumes are
changed by law or regulatory action, then the price of gas hereunder and any
other provisions of this contract directly or indirectly affected by such change
shall be appropriately modified and adjusted to the extent necessary to the end
that calculations to determine sums of money due by either party to the other
under this contract after any such change or changes will reach the same end
result in dollars and cents as would have been reached hereunder in the absence
of such change.
(c) The volume of gas shall be measured at each Point of Delivery
by meters installed and operated and computations made as prescribed in the
latest accepted edition of The American Gas Association Gas Measurement
Committee Report No. 3, except as the parties may otherwise agree or may
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).
(d) The temperature of the gas at each Point of Delivery shall be
assumed to be 60 degrees Fahrenheit; however, either party may install a
recording thermometer to record the actual temperature.
(e) The specific gravity of the gas shall be determined for each
Point of Delivery in accordance with good engineering practice as often as found
necessary in actual
1
<PAGE>
operation.
(f) Buyer shall install, own, operate and maintain standard type
measuring and testing equipment necessary hereunder and shall keep same accurate
and in repair. Readings, calibrations, tests, repairs and adjustments of said
equipment, and changing of charts, shall be done only by employees or agents of
Buyer and in accordance with sound engineering practice as often as found
necessary in actual operation. Any other party hereto shall have access to
Buyer's measuring and testing equipment at any reasonable time, and shall have
the right to have a representative present at tests, calibrations and
adjustments thereof. All tests shall be preceded by reasonable notice to the
operator of the well or wells affected or to such other party or parties hereto
as Buyer may be requested in writing to notify and shall be conducted at least
annually. Upon request by another party hereto for a special test of any meter
or auxiliary equipment, Buyer shall promptly verify the accuracy of same,
provided that the cost of such special test shall be borne by the requesting
party unless the percentage of inaccuracy is found to be more than two percent
(2%). If upon any test the total inaccuracy resulting from meter errors and
auxiliary equipment errors exceeds two percent (2%), then previous readings
shall be corrected to zero error for the period of time during which the
equipment was inaccurate, but not beyond the close of the preceding accounting
month; if said total inaccuracy is not more than two percent (2%), then previous
readings shall be considered correct but the equipment shall be adjusted to read
correctly.
(g) If any meter or auxiliary equipment is out of service or out
of repair for a period of time so that the amount of gas delivered cannot be
ascertained or computed from the reading thereof, then the gas delivered during
such period shall be estimated upon the basis of the best data available, using
the first of the following methods which is feasible: (i) by correcting the
error if the percentage of error is ascertainable by calibration, test, or
mathematical calculations; (ii) by using the registration of any check equipment
installed and accurately registering; or (iii) by estimating the volume on the
basis of deliveries during preceding periods under similar conditions when the
equipment was registering accurately.
(h) Upon request, Buyer shall submit its measurement charts and
records to any other party to this contract for examination, the same to be
returned within 20 days. Buyer's measurement charts and records for a given
accounting month shall be conclusively presumed correct if no written objection
thereto is served on Buyer within the 36-month period following the given
accounting month, and at the end of such 36-month period the same may be
destroyed.
(i) Any other party or parties hereto may install, operate and
maintain, at their own cost, risk, and expense, but in the same manner as is
required for Buyer's equipment hereunder, check measuring and testing equipment
of standard type, provided that the same does not interfere with the operation
of Buyer's equipment, but the measurement and testing of gas for purposes of
this contract shall only be by Buyer's equipment. Buyer shall have the same
rights with respect to check equipment as are granted the other party or parties
hereto with respect to Buyer's equipment.
2
<PAGE>
(B) QUALITY
-------
Gas delivered hereunder shall be clean, merchantable natural gas containing
not more than five grains of sulphur per hundred cubic feet of gas and not more
than one-fourth grain of hydrogen sulfide per hundred cubic feet of gas, and
shall be free of objectionable liquids and solids, oxygen and other deleterious
substances. The gas shall have an average Btu content of at least 975 Btu per
cubic foot. Buyer shall not be obligated to accept delivery of gas which either
does not conform to the standards of quality and heat content herein set forth
or contains corrosive products in quantities sufficient to impair the useful
life of Buyer's pipeline facilities or of any gasoline or other processing plant
processing the gas delivered, provided that, at Buyer's option, Buyer may from
time to time accept deliveries of any or all such gas and bring it up to
specification for Seller's account deducting the reasonable expense thereby
incurred from remittances otherwise due hereunder.
(C) ADDRESSES AND NOTICES
---------------------
Except as otherwise herein expressly provided, the parties may be addressed
for all purposes of this contract at the addresses set forth after their
respective signatures hereto, subject to change from time to time by written
notice to the other party. Written notices shall be deemed given to a party
when delivered to such party's address; written responses to such notices shall
be deemed given to a party when delivered to such party's address, or if sent by
United States mail, when deposited in the mail, properly addressed, with
sufficient postage affixed.
(D) SUCCESSORS AND ASSIGNS
----------------------
This contract shall extend to and be binding upon the successors, heirs,
legal representatives, and assigns of the parties. No transfer, assignment,
conveyance, or encumbrance, of any kind, of any interest whatsoever in respect
of which production is delivered to Buyer hereunder shall be binding upon Buyer
until Buyer shall have been given written notice thereof and furnished with a
duly certified copy of records evidencing same.
(E) MULTIPLE COMPLETIONS
--------------------
In the case of multiple completions, each separately completed and
producing zone shall be considered a separate well under this contract, and the
term "well" as used herein refers to each such separate completion except as may
otherwise appear clearly intended in context.
(F) EASEMENTS
---------
To the full extent that Seller is able to convey such rights, Buyer is
hereby granted and assigned an easement and servitude on the premises from which
gas is delivered hereunder for installing, operating, and maintaining pipelines
and equipment and for any other purposes connected herewith, with the right to
remove such lines and equipment before, or within a
3
<PAGE>
reasonable time after, the expiration of this contract. For any purpose
connected herewith, Buyer shall have free access to any part of Seller's leases
from which gas is delivered hereunder.
(G) GOVERNMENT REGULATIONS
----------------------
This contract shall be subject to all relevant present and future local,
state and federal laws, and all rules, regulations, and orders of any regulatory
authority having jurisdiction. Neither party shall be held in default for
failure to perform hereunder if such failure is due to good faith compliance
with such party's best understanding of the requirements of any such laws,
orders, rules or regulations. Seller warrants that production sold and
delivered hereunder has been and will be produced and handled in compliance with
the requirements of the Fair Labor Standards Act of 1938, and amendments
thereto, and any other applicable laws, orders, rules and regulations.
(H) FORCE MAJEURE
-------------
In the event either party hereto is rendered unable wholly or in part by
force majeure to carry out its obligations under this agreement, other than to
make payments due hereunder, then on such party's giving notice and full
particulars of such force majeure in writing or by facsimile to the other party
(notice by Buyer to the operator of a well delivering gas hereunder shall
constitute notice to all parties hereunder owning interests in the production
from that well for purposes of this paragraph) as soon as possible after the
occurrence of the cause relied upon, the obligations of the party giving such
notice, so far as they are affected by such force majeure, shall be suspended
during the continuance of any inability so caused, and such cause shall, as far
as possible, be remedied with all reasonable dispatch. The term "force
majeure," as used herein, shall mean acts of God, strikes, lockouts, or
industrial disturbances, acts of the public enemy, wars, blockades,
insurrections, riots, epidemics, landslides, lightning, earthquakes, fires,
storms, floods, washouts, arrests and restraints of rulers and people, civil
disturbances, explosions, breakage of or accident to machinery, equipment, or
lines of pipe, the making of repairs, alterations or tests on machinery,
equipment or lines of pipe, the freezing of wells or lines of pipe, the partial
or entire failure of gas wells, the inability to acquire, or the delays in
acquiring, at reasonable cost and after the exercise of reasonable diligence,
such servitudes, right of way grants, permits, licenses, approvals and
authorizations by regulatory bodies, supplies and materials (or permission from
regulatory bodies to use supplies and materials on hand) as may be necessary in
order that obligations assumed hereunder may be lawfully performed in the manner
herein contemplated, any act or omission on the part of any purchaser or
purchasers of gas from Buyer by reason of force majeure affecting such purchaser
or purchasers, and any other causes, whether of the kind herein enumerated or
otherwise, which are not within the control of the party claiming suspension,
and which by the exercise of due diligence such party is unable to overcome,
provided that the exercise of due diligence shall never require the settlement
of labor disputes against the better judgment of the party having the dispute.
4
<PAGE>
(I) WARRANTY
--------
Seller warrants, and agrees to defend, title to production delivered
hereunder and the right of Seller to sell same. Seller further warrants that
all such production is delivered free and clear of all liens, encumbrances, and
adverse claims, including liens to secure payment of taxes. Seller shall bear
the economic burdens of, and except as may be otherwise herein provided shall
pay, all royalties, overriding royalties, production payments and other payments
and settlements of whatsoever kind and nature due in respect of production
delivered hereunder or the proceeds from the sale thereof under Seller's leases
and other contracts of record or otherwise binding on Seller, as well as
settlements with all other persons having any interest in production delivered
hereunder, and Seller agrees to indemnify Buyer and save it harmless from all
claims, suits, actions, debts, accounts, damages, costs, losses, and expenses
arising out of adverse claims of any and all persons to or against said
production. In the event any adverse claim is asserted, Buyer may retain
without interest, as security for the performance of Seller's obligations
hereunder with respect to such claim, any amount out of monies then or
thereafter payable to Seller hereunder up to the amount of such claim, until
such claim has been finally determined or until Seller shall have furnished bond
to Buyer in an amount and with sureties satisfactory to Buyer and conditioned
for the protection of Buyer with respect to such claim.
(J) TERMINATION ON DEFAULT
----------------------
If either party shall fail to perform any of the covenants or obligations
imposed upon it under this contract (except where such failure shall be excused
under the provisions hereof), the other party may, at its option, terminate this
contract by proceeding as follows: the party not in default shall cause a
written notice to be served on the party in default, stating specifically the
cause for terminating this contract and declaring it to be the intention of the
party giving the notice to terminate the same; thereupon the party in default
shall have thirty (30) days after the service of the notice in which to remedy
or remove the cause or causes stated in the notice for terminating the
contract,and, if within said period of thirty (30) days, the party in default
does so remedy and remove said cause or causes and fully indemnify the party not
in default for any and all consequences of such breach, then such notice shall
be withdrawn and this agreement shall continue in full force and effect. In
case the party in default does not so remedy and remove the cause or causes and
does not indemnify the party giving the notice for any and all consequences of
such breach, within said period of thirty (30) days, then this agreement shall
become null and void from and after the expiration of said period. Any
cancellation of this agreement pursuant to the provisions of this section shall
be without prejudice to the right of the party not in default to collect any
amounts then due it and without waiver of any other remedy to which the party
not in default may be entitled for violation of this contract.
(K) ARBITRATION
-----------
Where specific provision, if any, is made in this contract for arbitration,
the following procedures shall be followed except as may be otherwise expressly
provided for the arbitration of a particular matter: Upon written notice from
either party to the other party, representatives
5
<PAGE>
of both parties shall meet and attempt to settle the matter first by mutual
agreement. If they are unable to do so, then the matter shall be submitted to
an impartial, qualified arbitrator whose decision shall be final and binding on
the parties and whose fee and expenses shall be borne equally by the parties.
If the parties have not settled the matter or agreed on an arbitrator within 30
days after the aforesaid written notice, then upon the application of either
party the arbitrator shall be designated by the then senior Federal judge for
the Western District of Arkansas.
(L) COMMINGLED STREAM
-----------------
If at any time gas from two or more wells from which gas is delivered
hereunder is commingled before delivery to Buyer, or if any gas subject to this
contract is commingled with gas not subject to this contract, whether from the
same well or other wells, before delivery to Buyer, then Buyer's take obligation
in either or both such situations shall be to receive from all sources at the
common point of delivery where Buyer receives the commingled stream a total
volume which can be allocated as among the wells or interests delivering at the
common point in such manner as to result in Buyer's receiving the volume Buyer
is obligated to receive from each under the contract or contracts covering same.
Under such circumstances, as between the parties Seller assumes responsibility
for allocating the volume received by Buyer at the common point as among the
various wells and interests delivering to Buyer at the common point and for
furnishing Buyer with such information as may be necessary to permit settlements
to be properly made hereunder.
(M) OPERATION OF WELLS
------------------
(1) Seller, at Seller's expense shall:
(a) Complete, control, manage, operate and maintain any wells from
which gas is delivered hereunder in a workmanlike manner; and
(b) Conduct with Buyer's cooperation, or at Buyer's option,
cooperate with Buyer who shall conduct, such well tests as Buyer may require
from time to time, but not more often than once each six months, to determine
the open flow and rock pressure of the wells subject hereto, provided that in no
event shall any liability attach to Buyer in connection with the making of any
such tests except through the negligence of Buyer's agents.
(2) Buyer, at Buyer's expense shall:
(a) Install, operate and maintain such separators, heaters, and
other equipment as may be necessary to deliver gas under the terms and
conditions of this contract, and such testing connections as may be required;
(b) Equip, operate and regulate the pressures on, each of the
wells from which gas is delivered hereunder in such manner that the pressure and
the volume of gas delivered hereunder can be regulated in a safe and
satisfactory manner;
6
<PAGE>
(c) Regulate the volume of gas deliveries hereunder in accordance
with the needs of Buyer's gas system; and
(d) Keep as many attendants stationed in the area of the wells
from which gas is delivered hereunder as may be necessary in order that the
obligations assumed by Buyer hereunder may be efficiently performed at all
times.
7
<PAGE>
EXHIBIT 10.11
EXECUTIVE SEVERANCE AGREEMENT
-----------------------------
This agreement (this "Agreement") is made as of the 14th day of
December, 1994, 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 Gregory D. Kerley
(hereinafter called the "Employee"), residing at 3409 Fredricksburg Circle,
Fayetteville, Arkansas 72703.
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 Fayetteville, Arkansas, 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
19
<PAGE>
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:
Mr. Gregory D. Kerley
3409 Fredricksburg Circle
Fayetteville, Arkansas 72703
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.
20
<PAGE>
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.
21
<PAGE>
IN WITNESS WHEREOF, the parties have executed this Agreement as of the
date first written above.
Southwestern Energy Company
By:____________________________
Chairman of the Compensation
Committee
Southwestern Energy Company
By:____________________________
Chairman of the Board of
Southwestern Energy Company
By:____________________________
Gregory D. Kerley
22
<PAGE>
EXHIBIT 10.12
EMPLOYMENT AGREEMENT
--------------------
THIS EMPLOYMENT AGREEMENT (Agreement) is made and entered into on this
-------------------------
December 7, 1994, at Fayetteville, Washington County, Arkansas, by and between
SOUTHWESTERN ENERGY COMPANY, an Arkansas business corporation, designated herein
---------------------------
as SWEN, and CHARLES E. SCHARLAU, designated herein as EMPLOYEE.
------------------- --------
WHEREAS, the parties hereto are subject to an Employment Agreement
dated December 18, 1990, and desire to amend such agreement by extending
its term, and
WHEREAS, at its meeting held on October 5, 1994, the Board of
Directors by a motion duly made and passed authorized the extension of the
Employment Agreement dated December 18, 1990, for an additional two (2)
years, and
WHEREAS, Employee has advised SWEN of his desire to extend the term of
employment as provided in the Employment Agreement.
Agreement: For and in Consideration of the foregoing recitals and of the
--------- ------------------------
mutual and interdependent promises SWEN and EMPLOYEE agree that Section C(1)(a)
---- --------
and Section C(2) are hereby amended to read as follows:
C(1)(a) The EMPLOYEE'S employment under this Agreement shall commence
with January 1, 1991, and shall continue until the expiration of seven (7)
years from and after the said date. During such period 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 Executive Officer of all of the
business activities of SWEN.
C(2) Termination of Employment of the Employee: If SWEN shall
-----------------------------------------
terminate the employment of the EMPLOYEE at any time during the seven (7)
year period commencing January 1, 1991, and ending on December 31, 1997,
then the termination rights of the EMPLOYEE hereunder shall be determined
pursuant to and under that certain Executive Severance Agreement dated
August 4, 1989, between SWEN and the EMPLOYEE. The Contract dated August
4, 1989, and identified hereinabove is hereby referred to for a full
recital of the terms and provisions thereof and by this reference is made a
part hereof.
All other terms and conditions of the Employment Agreement dated December
18, 1990 between SWEN and EMPLOYEE remain in effect as written.
<PAGE>
IN WITNESS WHEREOF, the parties hereto have executed this Agreement in
original triplicates on this December 7, 1994, effective as of the date first
hereinabove written.
SOUTHWESTERN ENERGY COMPANY
ATTEST: By__________________________________
John Paul Hammerschmidt
_______________________________
Greg D. Kerley, Secretary
_____________________________________
Charles E. Sanders
COMPENSATION COMMITTEE OF THE
BOARD OF DIRECTORS
_______________________________________
Charles E. Scharlau
EMPLOYEE
<PAGE>
ACKNOWLEDGEMENT
---------------
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, John
Paul Hammerschmidt and Charles Sanders, to me well known as the members of the
compensation committee and Greg D. Kerley as the secretary of the committee of
the Board of Directors 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 December,
1994.
______________________________________
Notary Public
My Commission Expires:
_________________________
ACKNOWLEDGEMENT
---------------
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, 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 7th day of December,
1994.
_______________________________________
Notary Public
My Commission Expires:
_________________________
<PAGE>
Management's Discussion and Analysis of Financial Condition and
Results of Operations
RESULTS OF OPERATIONS
Net income in 1994 decreased by 7% to $25.1 million, or $.98 per share,
down from $27.1 million, or $1.05 per share, in 1993. Net income in 1992 was
$22.3 million, or $.87 per share. The comparison of 1994 to 1993 excludes the
cumulative effect of a change in accounting for income taxes which was recorded
in the first quarter of 1993. Operating results for 1993 also included an
adjustment of $1.7 million, or $.07 per share, to decrease net income and record
the effect on accumulated deferred income taxes of a legislated increase in the
federal corporate income tax rate. There were no accounting changes or
extraordinary items recorded in either 1994 or 1992.
The decline in 1994 earnings resulted as lower gas prices and much warmer
heating weather offset the favorable effect of the Company's seventh consecutive
increase in natural gas production. The low gas prices also magnified the effect
on earnings of a settlement reached to resolve certain gas cost issues before
the Arkansas Public Service Commission (APSC). The settlement, which involved
the price of gas sold under a contract between one of the Company's exploration
and production subsidiaries and its utility subsidiary, is hereafter referred to
as "the gas cost settlement" and is discussed below under Regulatory Matters.
The earnings growth in 1993 was primarily the result of increased sales of the
Company's gas production. Revenues and operating income for the Company's major
business segments are shown in the following table.
<TABLE>
<CAPTION>
1994 1993 1992
-------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
REVENUES
Exploration and production $ 80,123 $ 79,374 $ 60,554
Gas distribution 127,060 131,892 117,495
Other 308 262 256
Eliminations (37,305) (36,684) (34,475)
-------------------------------------------------------------------------------
$170,186 $174,844 $143,830
===============================================================================
OPERATING INCOME
Exploration and production $ 38,883 $ 42,608 $ 33,071
Gas distribution 13,391 15,261 13,094
Corporate expenses (192) (305) (177)
-------------------------------------------------------------------------------
$ 52,082 $ 57,564 $ 45,988
===============================================================================
</TABLE>
EXPLORATION AND PRODUCTION REVENUES
The Company's exploration and production revenues increased 1% in 1994 and
31% in 1993. The slight increase in 1994 was due to increases in natural gas and
oil production, offset by lower average product prices. The increase in 1993 was
due to increased natural gas production. Gas production increased by 6% to 37.7
billion cubic feet (Bcf) in 1994 from 35.7 Bcf in 1993. Gas production in 1993
increased by 38% from 25.8 Bcf in 1992. Increased sales to unaffiliated
purchasers have accounted for approximately 80% of the increase in gas
production since 1992.
Gas sales to unaffiliated purchasers increased to 23.8 Bcf in 1994, from
22.9 Bcf in 1993, and 14.4 Bcf in 1992. The increases in sales to unaffiliated
purchasers were primarily the result of higher sales from the Company's
properties in both Arkansas and the Gulf Coast areas of Texas and Louisiana. The
Company sold 15.1 Bcf of its Arkansas production to unaffiliated purchasers
during both 1994 and 1993, compared to 10.6 Bcf in 1992. The increase from the
1992 level was the result of the Company's development drilling program in the
Arkoma Basin which made additional gas available for sale during the late spring
and summer months. Much of this incremental production was sold into interstate
markets as a result of improved access to those markets made possible by the
NOARK Pipeline System (NOARK). NOARK became operational in late 1992 and extends
across northern Arkansas, crossing three major interstate pipelines. The
Company, through a subsidiary, holds a general partnership interest in NOARK of
approximately 48% and is the pipeline's operator. Sales from the Company's Gulf
Coast properties were 6.8 Bcf in 1994, compared to 6.3 Bcf in 1993, and 2.0 Bcf
in 1992. The increase in 1994 was primarily the result of the completion of a
production platform at the Galveston Block 283 gas field late in 1993 and first
production from the Earl Chauvin No. 1 well, a 1993 discovery in southeast
Louisiana. The increase in 1993 was primarily the result of the completion of a
production platform at Brazos Block 397 and the start of production in November,
1993, from Galveston Block 283.
<TABLE>
<CAPTION>
1994 1993 1992
-------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS PRODUCTION
Affiliated sales (Bcf) 13.9 12.8 11.4
Unaffiliated sales (Bcf) 23.8 22.9 14.4
-------------------------------------------------------------------------------
37.7 35.7 25.8
-------------------------------------------------------------------------------
Average price per Mcf $2.04 $2.18 $2.26
===============================================================================
OIL PRODUCTION
Unaffiliated sales (MBbls) 200 97 120
-------------------------------------------------------------------------------
Average price per Bbl $15.89 $17.20 $19.75
===============================================================================
</TABLE>
Sales to unaffiliated purchasers are made under contracts which reflect
current short-term prices and which are subject to seasonal price swings. The
Company curtailed part of its gas production during 1992 when sales prices were
deemed below acceptable levels. The Company also uses gas price hedges on a
limited basis to reduce the Company's exposure to the risk of changing prices.
Deliveries for injection into storage and the gas cost settlement increased
the demand of the Company's utility distribution systems for affiliated gas
supply in 1994. Gas production sold to Arkansas Western Gas Company (AWG), the
utility subsidiary which operates the Company's northwest Arkansas utility
system, was 8.8 Bcf in 1994, up from 7.1 Bcf in 1993, and 7.2 Bcf in 1992. The
increase in gas sold to AWG in 1994 was due largely to increased storage
injections and higher volumes resulting from the gas cost settlement, as
discussed below. The decrease in gas sold to AWG in 1993 resulted from the lack
of summer injections by AWG into its gas storage facilities, partially offset by
an increase in sales due to weather related requirements of the utility
14
<PAGE>
system and an increase in sales to a spot market purchasing program available to
the larger business customers of AWG. The Company's gas production provided
approximately 64% of AWG's requirements in 1994, and approximately 50% in 1993
and 1992. Additionally, in 1994, 1993, and 1992, the Company sold .5 Bcf, .7
Bcf, and .4 Bcf, respectively, of gas to AWG for its spot market purchasing
program.
The Company's sales to AWG under the spot market purchasing program are
based upon competitive bids and generally reflect current spot market prices.
Most of the remaining sales to AWG's system are subject to a long-term contract
entered into in 1978, under which the price had been frozen since the end of
1984. As mentioned above and discussed more fully under Regulatory Matters, this
contract was amended in 1994 as a result of the settlement of certain gas cost
issues with the APSC. The 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 an additional premium. The settlement results in a lower
contract price based on current market conditions. That effect is offset in part
by provisions which allow additional volumes to be sold under the contract.
Other sales to AWG are made under long-term contracts with flexible pricing
provisions and under short-term spot arrangements.
The Company's deliveries 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 5.1 Bcf in 1994, 5.7 Bcf in 1993,
and 4.3 Bcf in 1992. Deliveries to Associated decreased in 1994 due to warmer
weather and increased in 1993 due to colder heating weather and storage
requirements during the summer months. Effective October, 1990, one of the
Company's exploration and production subsidiaries entered into a ten-year
contract with Associated to supply its base load system requirements at a price
to be redetermined annually. Deliveries under this contract were made at $1.90
per thousand cubic feet (Mcf) from inception of the contract through the first
nine months of 1993, increased to $2.385 per Mcf for the contract period ending
September 30, 1994, and are currently being made at $2.20 per Mcf.
The average price received at the wellhead for the Company's total gas
production was $2.04 per Mcf in 1994, $2.18 per Mcf in 1993, and $2.26 per Mcf
in 1992. The decline in the average price received since 1992 reflects the
recent decline in spot market prices, 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, and the effect of the gas cost
settlement. Natural gas prices declined during the last half of 1994, and with
the abnormally warm winter recently experienced across the country, average
prices are generally expected to remain lower in 1995 as compared to 1994. As
described above, a significant portion of the Company's gas production is sold
under long-term contracts to its gas distribution subsidiary. In the past, the
fixed prices received under these sales arrangements helped reduce the effects
of fluctuations in the spot market price for natural gas. Going forward, the
Company expects increased volatility and seasonality in its operating results as
the majority of its gas sales will be tied to a spot market index. In the
future, the Company expects the overall average price it receives for its total
production to be generally higher than average spot market prices due to the
premiums over spot that it receives. 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. While the Company expects over
the long term to experience a trend toward increasing volumes of gas production,
it 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 block of undeveloped leasehold acreage
and producing acreage which will continue to be developed in the future. The
Company's exploration programs have been directed almost exclusively 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.
GAS DISTRIBUTION REVENUES
Gas distribution revenues fluctuate due to the pass-through of cost of gas
increases and decreases, 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.
<TABLE>
<CAPTION>
1994 1993 1992
-------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS DISTRIBUTION SYSTEMS
Deliveries (Bcf)
Sales volumes 26.3 26.8 23.5
Transportation volumes
End-use 4.8 5.6 5.2
Off-system 10.7 11.7 2.5
-------------------------------------------------------------------------------
41.8 44.1 31.2
-------------------------------------------------------------------------------
Average number of sales customers 159,897 155,944 151,592
-------------------------------------------------------------------------------
Heating weather--degree days 4,161 4,929 4,104
-------------------------------------------------------------------------------
Average sales rate per Mcf $4.57 $4.65 $4.75
===============================================================================
</TABLE>
Gas distribution revenues decreased by 4% in 1994 and increased by 12% in
1993. The decrease in 1994 reflected the net effects of strong customer growth,
weather which was 16% warmer than the prior year, and lower purchased gas costs
caused in part by the gas cost settlement. The increase in 1993 was primarily
due to additional deliveries to residential and commercial customers resulting
from weather which was 20% colder than in 1992 and from customer growth.
Additional revenues related to the transportation of gas behind AWG's system to
NOARK also contributed to the increase in 1993.
15
<PAGE>
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
In 1994, AWG sold 16.3 Bcf to its customers at an average rate of $4.25 per
Mcf, compared to 17.1 Bcf at $4.40 per Mcf in 1993, and 15.0 Bcf at $4.62 per
Mcf in 1992. Additionally, AWG transported 4.0 Bcf for its end-use customers in
1994, 3.9 Bcf in 1993, and 3.2 Bcf in 1992. Associated sold 10.0 Bcf to its
customers in 1994 at an average rate of $5.10 per Mcf, compared to 9.7 Bcf in
1993 at $5.08 per Mcf, and 8.4 Bcf at $4.99 per Mcf in 1992. The increase in
1994 was due to the conversion of an industrial customer from transportation to
sales service. While the conversion of this customer to sales service raised the
Company's gas distribution revenues, there was no resulting impact on operating
income as the rate charged this customer for transportation service was equal to
the rate charged for sales service, exclusive of gas costs. Associated
transported .8 Bcf for its end-use customers in 1994, compared to 1.7 Bcf in
1993, and 2.0 Bcf in 1992.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, increased to 12.3 Bcf in 1994, from 11.7 Bcf in 1993,
and 11.3 Bcf in 1992. The steady increase reflects both the success of the
Company's industrial marketing efforts and the continued economic strength of
its service territory.
AWG also transported 10.7 Bcf of gas through its gathering system in 1994
for off-system deliveries, all through NOARK, compared to 11.7 Bcf in 1993, and
2.5 Bcf in 1992. The average transportation rate was $.13 per Mcf, exclusive of
fuel, in all years.
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 3.5% to 4.0% annually,
while Associated has experienced customer growth of 1% to 2% annually. Based on
current economic conditions in the Company's service territories, the Company
expects this trend in customer growth to continue. Rate increase requests which
may be filed in the future will depend upon customer growth, increases in
operating expenses, and additional investments in property, plant and equipment.
AWG is precluded from filing an application for a rate increase with the APSC
prior to January 1, 1996, as a result of the gas cost settlement. The Company
anticipates filing a rate increase request for AWG in early 1996 and will
continue to monitor the status of returns on the systems operated by Associated
and file rate cases as the need arises.
REGULATORY MATTERS
During 1994, the Company reached a settlement with the Staff of the APSC
and the Office of the Attorney General of the State of Arkansas concerning
certain gas cost issues which had been outstanding before the APSC for the past
four years. The gas cost issues were first raised by the APSC in December, 1990,
in connection with its approval of an AWG rate increase. The issues in question
involved the price of gas sold under a long-term contract between AWG and one of
the Company's gas producing subsidiaries. The terms of the settlement became
effective as of July 1, 1994, and were approved by the APSC on January 5, 1995.
Under the settlement, the price paid by AWG is tied to a monthly spot market
index plus an additional premium. Given current market conditions, the new
pricing provision results in a reduced sales price. That effect is offset in
part by provisions which allow additional volumes to be sold under the contract.
The amended contract provides for volumes equal to the historical level of sales
under the contract to be sold at the spot market index plus a premium of $.95
per Mcf, while any incremental sales volumes will receive a premium of $.50 per
Mcf. In 1994, approximately 8.1 Bcf (net to the Company's interest) was sold
under the contract, compared to approximately 6.0 Bcf in 1993. Other significant
terms of the settlement prevent any of the parties thereto from asking for
refunds, transfers certain of AWG's natural gas storage facilities to another
subsidiary of the Company, and prohibits AWG from filing a rate case for its
northwest Arkansas system before January, 1996, as mentioned above.
As discussed earlier, Associated also purchases a portion of its gas supply
at the wellhead from one of the Company's gas producing subsidiaries under a
long-term firm contract entered into in October, 1990. As a result of recent gas
cost audits for the two-year period ended August 31, 1992, the Staff of the
Missouri Public Service Commission (Staff) recommended the disallowance of
approximately $3.1 million in gas costs. This amount represents the difference
between the price paid by Associated and a spot market index price for gas
delivered into an interstate pipeline operating in the Arkoma Basin. The price
paid by Associated under the contract was $1.90 per Mcf during the period in
question. In making its recommendation, the Staff acknowledged that Associated
had lowered its gas cost and saved its ratepayers money by purchasing gas from
its affiliate. The Staff also acknowledged that the appropriate price for
purchases made under this long-term firm contract should include a premium over
the spot market price. However, a Staff consultant testified that there was
insufficient data upon which to determine an appropriate premium over a spot
market index for pricing purchases under this contract and that he was unable to
determine what the appropriate premium should be. A hearing was held on January
31, 1995. The Company presented testimony to demonstrate that the price paid
under the contract was at or below the market price for contracts with similar
terms during the period in which the purchases were made. The APSC previously
reviewed the costs charged to Arkansas rate-payers under this contract and found
them to be proper and allowable for recovery. The Missouri Public Service
Commission (Missouri Commission) has not yet issued an order in this proceeding.
The Staff has also audited Associated's gas purchases for the period from
September, 1992, through August, 1993, and recommended no changes to the gas
costs for that period. The Company does not expect any outcome of the proceeding
to have a material adverse effect on the results of operations or the financial
position of the Company.
In April, 1992, the Federal Energy Regulatory Commission issued Order No.
636, a comprehensive set of regulations designed to encourage competition and
continue the significant restructuring of the interstate natural gas pipeline
industry. Prior to Order No. 636, Associated purchased portions of its gas
supply from interstate pipelines under firm long-term supply contracts. The
Company has paid approximately $3.2 million in contract reformation costs and
16
<PAGE>
take-or-pay costs and $1.9 million in transition costs which these interstate
pipelines incurred and were allowed to recover. The Company anticipates full
recovery of the $1.9 million in transition costs incurred. Additionally, the
Company has recovered, subject to refund, approximately $1.6 million of the
contract reformation costs and take-or-pay costs from its utility sales
customers in the state of Missouri. Of the unrecovered $1.6 million related to
contract reformation costs and take-or-pay costs, $.7 million is applicable to
Associated's transportation customers in the state of Missouri and $.9 million
is applicable to all customers in the state of Arkansas. The Staff of the
Missouri Commission has reviewed these payments and made a recommendation that
the unrecovered $.7 million related to Associated's transportation customers
should be disallowed on the grounds of retroactive rate-making. The Company
disagreed with this recommendation and a hearing was held on January 31, 1995.
The Company is awaiting the Missouri Commission's order.
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 producers or other suppliers 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 Associated in Arkansas
and began to obtain their own gas supplies directly from other sources.
Associated has offered such a service to its customers in Missouri for several
years and AWG's spot market purchasing program has provided customers in
northwest Arkansas with many of the benefits of transportation service. 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 increased by 1% in 1994 and by
20% in 1993. The slight increase in 1994 resulted from increased depreciation,
depletion and amortization expense (DD&A) primarily related to the Company's
exploration and production segment and increased utility operating expenses,
offset by lower purchased gas costs related to lower prices paid for gas
supplies. The increase in 1993 was due primarily to increased purchased gas
costs related to increased utility deliveries, and increased production costs
and DD&A resulting from increased gas sales in the exploration and production
segment. Purchased gas costs are one of the largest expense items in each year,
typically representing 30% to 40% of the Company's total operating costs and
expenses. Purchased gas costs are influenced primarily by changes in
requirements for gas sales of the gas distribution segment, the price and mix of
gas purchased, and the timing of recoveries of deferred purchased gas costs. As
previously mentioned, increases and decreases in purchased gas costs are
automatically passed through to the Company's utility customers.
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. DD&A increased 15% in 1994 due both to an increase in gas and oil
production and an increase in the amortization rate. The 30% increase in DD&A in
1993 was primarily due to increased levels of natural gas production. The margin
between the Company's full cost ceiling and the financial statement carrying
value of the Company's gas and oil properties was eroded substantially during
1994 as a result of very low average gas prices in effect at December 31, 1994.
Product prices, production rates, levels of reserves, and the evaluation of
unamortized costs all influence the calculation of the ceiling. A significant
decline in gas prices from year-end 1994, without other mitigating factors,
could cause a future write-down and a noncash charge against earnings.
Delays inherent in the rate-making process prevent the Company from
obtaining immediate recovery of increased operating costs of its gas
distribution segment. Inflation impacts the Company by generally increasing its
operating costs and the costs of its capital additions. In recent years the
impacts of inflation have been mitigated by conditions in the industries in
which the Company operates. While some of the gas distribution subsidiary's gas
purchase contracts include inflation-based price escalations, these clauses have
generally not been operating as gas market conditions have led producers to
accept prices below the contract maximum price. Continuing depressed conditions
in the gas and oil industry have resulted in lower costs of drilling and
leasehold acquisition.
OTHER COSTS AND EXPENSES
Interest costs were down slightly in 1994, as compared to 1993, due to
lower average borrowings on the Company's revolving credit facilities throughout
most of the year, partially offset by higher average interest rates. Borrowings
under these facilities were higher at year-end 1994, as compared to 1993,
primarily as a result of increased capital spending activity during the fourth
quarter of 1994. Interest costs decreased in 1993 due to the redemption in late
1992 of the Company's 12.75% Debentures and 9.38% First Mortgage Bonds, and due
to both lower average borrowings and lower average interest rates on the
Company's revolving credit facilities.
The change in other income during 1994 and 1993 relates primarily to the
Company's share of operating losses incurred by NOARK. The Company accounts for
its 47.93% interest in the NOARK partnership under the equity method of
accounting (see Note 7 to the financial statements for additional discussion).
NOARK has been operating below capacity and generating losses since it was
placed in service. The Company's share of the pretax loss for NOARK included in
other income was $2.8 million in 1994, $1.8 million in 1993, and $.6 million in
1992. 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 1994, NOARK had
17
<PAGE>
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
an average daily throughput of 82 million cubic feet of gas per day (MMcfd),
compared to 79 MMcfd in 1993, its first full year of operation. NOARK has a
total transportation capacity of 141 MMcfd. AWG has contracted for 41 MMcfd of
firm capacity on NOARK under a ten-year transportation contract. NOARK also has
a five-year transportation contract with Vesta Energy Company (Vesta) covering
the marketer's commitment for 50 MMcfd of firm transportation. The Company's
exploration and production segment was supplying 25 MMcfd of the volumes
transported by Vesta under that agreement. In late 1993, Vesta filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its contract with NOARK. The
complaint and subsequent filings seek rescission of both the transportation
contract and a contract to purchase gas from the Company's affiliates, along
with actual and punitive damages. The Company and NOARK believe the suit is
without merit and have filed counterclaims seeking enforcement of the contracts
and damages.
The APSC has established a maximum transportation rate of approximately
$.285 per dekatherm for NOARK 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 competes primarily with two
interstate pipelines in its gathering area. One of those elected to become an
open access transporter subsequent to NOARK's start of construction. That
pipeline, which was recently sold, has not offered firm transportation, but the
increased availability of interruptible transportation service has intensified
the competitive environment within which NOARK operates. The Company expects
further losses from its equity investment in NOARK until the pipeline is able to
increase its level of throughput and until improvement occurs in the competitive
conditions which determine the transportation rates NOARK can charge. The
Company and the other partners of NOARK are currently investigating several
options which would improve NOARK's future financial prospects. However, the
Company believes that no write-down of its investment in NOARK is appropriate at
this time and that it will realize its investment in NOARK over the life of the
system.
The Company's effective income tax rate was 38.5% in 1994, 42.3% in 1993,
and 37.4% in 1992. The rate increased in 1993 because the Company's deferred tax
provision included $1.7 million of expense for the legislated increase in the
maximum federal corporate income tax rate.
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 1994, 1993, and
1992, net cash provided from operating activities totaled $66.6 million, $70.2
million, and $49.7 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 92% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1994, in excess of 100% in 1993, and 94% in 1992.
Dividends paid to common shareholders in 1994 were $6.2 million, compared
to $5.7 million in 1993, and $5.1 million in 1992. In July, 1993, the Board of
Directors increased the quarterly dividend on the Company's common stock by 20%
to $.06 per share from $.05 per share. On an annual basis, the rate is
equivalent to $.24 per share, compared to an annual dividend rate of $.20 per
share paid in 1992. The dividend rates reflect the effect of a three-for-one
stock split distributed in 1993.
On February 22, 1995, the Board of Directors authorized the repurchase of
up to $30 million of the Company's common shares. The shares will be purchased
from time to time, depending on market conditions, in the open market or in
private negotiated transactions. The Company plans to utilize available capacity
of its revolving credit facilities to fund the share repurchase. Shares
repurchased will be held in treasury and may be used for general corporate
purposes, including issuance under option plans. The repurchase program will
continue until terminated by the Company's Board of Directors.
Changes in the Company's liquidity in future years are expected to be
related primarily to changes in cash flow generated from its operations. Factors
affecting operating results were discussed under Results of Operations.
CAPITAL EXPENDITURES
Capital expenditures totaled $76.9 million in 1994, $59.2 million in 1993,
and $44.9 million in 1992. In 1994, expenditures for the exploration and
production segment included $13.9 million for acquisitions of reserves in place.
In 1992, the Company also made a $7.6 million equity contribution to the
partnership formed to construct NOARK.
<TABLE>
<CAPTION>
1994 1993 1992
-------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
CAPITAL EXPENDITURES
Exploration and production $55,449 $37,411 $30,823
Gas distribution 17,577 19,892 12,188
Other 3,828 1,916 1,898
-------------------------------------------------------------------------------
$76,854 $59,219 $44,909
===============================================================================
</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, finance improvements necessary due to normal customer growth in
its gas distribution segment, and explore and develop existing gas and oil
properties as well as generate new drilling prospects.
Routine capital expenditures expected to be incurred in 1995 are
18
<PAGE>
$71.7 million, consisting of $55.2 million for gas and oil exploration, $14.1
million for gas distribution system expenditures, and $2.4 million for general
purposes. The Company's capital expenditure plans also include approximately
$6.7 million of nonroutine spending, including $3.3 million for the construction
and renovation of office and operations facilities in the utility division and
$3.4 million for improvements to the utility's gas storage facilities. The gas
and oil expenditures include $12.0 million for exploratory drilling and $18.2
million to continue the development of the Company's acreage in the Arkoma
Basin.
During 1994, the Company increased its emphasis on acquisitions of
producing properties and expects that effort to continue as a supplement to its
exploration and development drilling programs. Such acquisitions may require
capital spending beyond that planned for routine purposes. The Company plans to
manage the debt portion of its capital structure over time through its policy of
adjusting its routine capital spending, but expects to continue to use
additional debt to address extraordinary needs or opportunities, such as
attractive acquisitions of gas and oil properties. Additionally, the Company may
use its existing revolving credit facilities to meet seasonal or short-term
requirements related to its capital expenditures.
FINANCING REQUIREMENTS
Two floating rate revolving credit facilities provide the Company access to
$80.0 million of variable rate long-term capital. Borrowings outstanding under
these credit facilities totaled $52.3 million at the end of 1994 and $31.0
million at the end of 1993. The Company also had available short-term lines of
credit totaling $3.5 million at the end of 1994 and 1993. The Company plans to
evaluate options for converting a significant portion of the amount outstanding
on its floating rate revolving credit facilities to another form of long-term
debt during 1995.
The Company and an affiliate of the other general partner of NOARK are
required to severally guarantee the availability of certain minimum cash
balances to service NOARK's 9.7375% Senior Secured Notes. These notes are held
by a major insurance company which also has a 20% limited partnership interest
in NOARK. The notes had a balance of $59.9 million at December 31, 1994, with
final maturity in 2009. The Company's share of the several guarantee of
available cash balances is 60%. NOARK also has an unsecured long-term revolving
credit agreement with a group of banks which provides the partnership access to
$30.0 million of additional funds. Amounts outstanding under this credit
arrangement were $29.6 million at December 31, 1994, and $25.2 million at
December 31, 1993. Amounts borrowed under the long-term revolving credit
agreement are severally guaranteed by the Company and an affiliate of the other
general partner. The Company's share of this several guarantee is also 60%. In
1994, the Company advanced $2.3 million to NOARK to fund its share of debt
service payments and to make the final payment of construction retainage to the
pipeline's main line contractor. The Company expects to advance funds to NOARK
totaling $4.5 million to $5.0 million during 1995 in connection with its
guarantees.
In July, 1992, the Company entered into a two-year reverse interest rate
swap agreement with a notional amount of $30.0 million. Under the terms of the
swap, which expired in 1994, the Company received interest semiannually at a
fixed rate of 5.11% and paid interest semiannually at the London Interbank
Offered Rate. Over the two-year period the swap was in effect, the Company
received $.7 million in excess of its required payments. This amount was
recorded as a net reduction of interest expense.
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 1.50 or higher. At the end of 1994, the
capital structure consisted of 40.1% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
59.9% equity, with a ratio of earnings to fixed charges of 3.3.
WORKING CAPITAL
The Company maintains access to funds which may be needed to meet seasonal
requirements through the revolving and short-term lines of credit explained
above. The Company had net working capital of $8.9 million at the end of 1994,
and $8.1 million at the end of 1993. Current assets increased by 3% to $48.0
million in 1994, while current liabilities increased 1% to $39.1 million. The
increase in current assets was due primarily to an increase in the current
portion of gas stored underground, reflecting the value of stored gas expected
to be utilized on an annual basis, offset by a decrease in accounts receivable
due to lower weather related sales at year-end 1994. The increase in current
liabilities resulted primarily from an increase in the current portion of long-
term debt and an increase in accounts payable, offset by a decrease in taxes
payable. The increase in accounts payable resulted primarily from the timing of
payments of amounts due. The decrease in taxes payable was due primarily to
lower taxable income and increased deductions for intangible drilling costs.
Intangible drilling costs are deductible currently for tax purposes, but are
capitalized and amortized over future periods for financial reporting purposes.
19
<PAGE>
REPORT OF INDEPENDENT AUDITORS
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, 1994 and
1993, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1994.
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, 1994 and 1993, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1994, in conformity with generally accepted accounting principles.
As discussed in Notes 3 and 4 to the consolidated financial statements,
effective January 1, 1993, the Company changed its methods of accounting for
income taxes and for postretirement benefits other than pensions.
ARTHUR ANDERSEN LLP
Tulsa, Oklahoma
February 7, 1995
20
<PAGE>
Statements of Income
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1994 1993 1992
-----------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
<S> <C> <C> <C>
OPERATING REVENUES
Gas sales $ 160,463 $ 166,164 $ 135,765
Oil sales 3,178 1,662 2,379
Gas transportation 4,721 5,177 3,597
Other 1,824 1,841 2,089
-----------------------------------------------------------------------------------------------------------------------
170,186 174,844 143,830
-----------------------------------------------------------------------------------------------------------------------
OPERATING COSTS AND EXPENSES
Purchased gas costs 36,395 42,962 35,848
Operating and general 42,506 40,093 34,970
Depreciation, depletion and amortization 35,546 30,944 23,880
Taxes, other than income taxes 3,657 3,281 3,144
-----------------------------------------------------------------------------------------------------------------------
118,104 117,280 97,842
-----------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 52,082 57,564 45,988
-----------------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE
Interest on long-term debt 9,962 10,090 10,932
Other interest charges 504 483 547
Interest capitalized (1,599) (1,548) (1,496)
-----------------------------------------------------------------------------------------------------------------------
8,867 9,025 9,983
-----------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE) (2,362) (1,657) (421)
-----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE PROVISION FOR INCOME TAXES AND
CUMULATIVE EFFECT OF ACCOUNTING CHANGE 40,853 46,882 35,584
-----------------------------------------------------------------------------------------------------------------------
PROVISION FOR INCOME TAXES
Current 9,288 13,704 7,403
Deferred 6,441 6,128 5,916
-----------------------------------------------------------------------------------------------------------------------
15,729 19,832 13,319
-----------------------------------------------------------------------------------------------------------------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE 25,124 27,050 22,265
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- 10,126 --
-----------------------------------------------------------------------------------------------------------------------
NET INCOME $ 25,124 $ 37,176 $ 22,265
=======================================================================================================================
EARNINGS PER SHARE
Income Before Cumulative Effect of Accounting Change $.98 $1.05 $.87
Cumulative Effect of Change in Accounting for Income Taxes -- .39 --
-----------------------------------------------------------------------------------------------------------------------
NET INCOME $.98 $1.44 $.87
=======================================================================================================================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 25,684,110 25,684,110 25,683,963
=======================================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
21
<PAGE>
Balance Sheets
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
December 31 1994 1993
-------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
ASSETS
CURRENT ASSETS
Cash $ 1,152 $ 834
Accounts receivable 32,325 34,894
Inventories, at average cost 12,199 9,580
Other 2,353 1,489
-------------------------------------------------------------------------------------------------------------------
Total current assets 48,029 46,797
-------------------------------------------------------------------------------------------------------------------
Investments 4,877 5,661
-------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $20,751,000 in 1994 and
$16,769,000 in 1993 excluded from amortization 435,570 375,281
Gas distribution systems 176,728 165,443
Gas in underground storage 36,629 37,171
Other 18,541 14,684
-------------------------------------------------------------------------------------------------------------------
667,468 592,579
Less: Accumulated depreciation, depletion and amortization 242,008 205,949
-------------------------------------------------------------------------------------------------------------------
425,460 386,630
-------------------------------------------------------------------------------------------------------------------
Other Assets 6,216 6,366
-------------------------------------------------------------------------------------------------------------------
$484,582 $445,454
===================================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt $ 6,071 $ 3,000
Accounts payable 18,670 16,114
Taxes payable 716 6,449
Customer deposits 4,232 3,927
Current portion of deferred income taxes 1,482 1,426
Over-recovered purchased gas costs, net 3,627 4,187
Other 4,345 3,594
-------------------------------------------------------------------------------------------------------------------
Total current liabilities 39,143 38,697
-------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 136,229 124,000
-------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 100,288 93,593
Deferred investment tax credits 2,416 2,617
Other 3,050 2,017
-------------------------------------------------------------------------------------------------------------------
105,754 98,227
-------------------------------------------------------------------------------------------------------------------
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 21,231 21,231
Retained earnings, per accompanying statements 199,430 180,470
-------------------------------------------------------------------------------------------------------------------
223,435 204,475
Less: Unamortized cost of restricted shares issued under stock incentive plan,
21,499 shares in 1994 and 17,447 shares in 1993 262 228
Common stock in treasury, at cost, 2,053,974 shares 19,717 19,717
-------------------------------------------------------------------------------------------------------------------
203,456 184,530
-------------------------------------------------------------------------------------------------------------------
$484,582 $445,454
===================================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
22
<PAGE>
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 25,124 $ 37,176 $ 22,265
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 35,825 31,223 24,160
Deferred income taxes 6,441 6,128 5,916
Equity in loss of partnership 2,818 1,788 531
Cumulative effect of change in accounting for income taxes -- (10,126) --
Change in assets and liabilities:
(Increase) decrease in accounts receivable 2,569 (589) (5,002)
(Increase) decrease in inventories (2,619) (1,544) 440
Increase in accounts payable 2,556 2,298 876
Increase (decrease) in taxes payable (5,733) 3,111 1,848
Increase in customer deposits 305 417 347
Decrease in over-recovered purchased gas costs (560) (286) (1,335)
Net change in other current assets and liabilities (113) 603 (316)
--------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 66,613 70,199 49,730
--------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (76,854) (59,219) (44,909)
Investment in partnership (2,319) -- (7,573)
(Increase) decrease in gas stored underground 542 9,119 (4,432)
Other items 3,200 1,599 1,997
--------------------------------------------------------------------------------------------------------
Net cash used in investing activities (75,431) (48,501) (54,917)
--------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net increase (decrease) in revolving long-term debt 21,300 (15,500) 22,000
Payments on other long-term debt (6,000) (835) (12,769)
Dividends paid (6,164) (5,651) (5,137)
--------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities 9,136 (21,986) 4,094
--------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 318 (288) (1,093)
Cash at beginning of year 834 1,122 2,215
--------------------------------------------------------------------------------------------------------
Cash at end of year $ 1,152 $ 834 $ 1,122
========================================================================================================
</TABLE>
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1994 1993 1992
--------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Retained Earnings, beginning of year $180,470 $148,945 $131,817
Net income 25,124 37,176 22,265
Cash dividends declared ($.24 per share in 1994, $.22
per share in 1993 and $.20 per share in 1992) (6,164) (5,651) (5,137)
--------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $199,430 $180,470 $148,945
========================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
23
<PAGE>
Notes to Financial Statements
December 31, 1994, 1993 and 1992
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
CONSOLIDATION
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 Pipeline
Company, Arkansas Western Pipeline Company, and A.W. Realty Company. All
significant intercompany accounts and transactions have been eliminated. The
Company accounts for a general partnership interest of approximately 48% 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 1994 presentation.
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) 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.
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 6.9%. Gas in
underground storage is stated at average cost.
Other property, plant and equipment is depreciated using the straight-line
method over estimated useful lives ranging from 5 to 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 97,000 of these customers are served in
northwest Arkansas and approximately 67,000 are served in northeast Arkansas
and Missouri.
The Company records gas distribution revenues on an accrual basis, as gas
volumes are used, in order to provide a proper matching of revenues with
expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual costs of purchased gas above or below
the levels included in the base rates are permitted to be billed or are
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.
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 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, 1994 and 1993 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.
INVESTMENT TAX CREDITS
Investment tax credits have been deferred for financial reporting purposes
and are being amortized over the estimated useful lives of the related
properties.
24
<PAGE>
DERIVATIVES
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. They are used to
manage defined interest rate and commodity price risks.
Interest rate swap agreements involve the exchange of fixed rate and
floating rate interest payments without the exchange of the underlying principal
amounts. The differential to be paid or received is recognized as an adjustment
to interest expense. See Note 2 for a discussion of the Company's interest rate
swap agreement which expired in 1994. The Company had no outstanding interest
rate swap agreements at December 31, 1994.
The Company uses natural gas swap agreements on a limited basis to hedge
sales of natural gas. Under the natural gas swap agreements, the Company
makes payments or receives the differential between a specified price and the
actual selling price of natural gas. Gains and losses resulting from hedging
activities have not had a material impact on the Company's results of
operations. The Company had no outstanding natural gas swap agreements at
December 31, 1994.
EARNINGS PER SHARE AND SHAREHOLDERS' EQUITY
Earnings per common share are based on the weighted average number of
common shares outstanding during each year. All share and per share information
for 1992 has been restated to reflect the effects of a three-for-one stock split
distributed on August 5, 1993.
(2) LONG-TERM DEBT
Long-term debt as of December 31, 1994 and 1993 consisted of the following:
<TABLE>
<CAPTION>
1994 1993
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
SENIOR NOTES
8.69% Series due December 4, 1997 $ 22,500 $ 22,500
8.86% Series due in annual installments of $3.1 million beginning December 4, 1995 21,500 21,500
9.36% Series due in annual installments of $2.0 million beginning December 4, 2001 22,000 22,000
10.63% Series due in annual installments of $3.0 million through September 30, 2002 24,000 30,000
---------------------------------------------------------------------------------------------------------------------------------
90,000 96,000
OTHER
Variable rate (6.62% at December 31, 1994) unsecured revolving credit arrangements with two banks 52,300 31,000
---------------------------------------------------------------------------------------------------------------------------------
Total long-term debt 142,300 127,000
Less: Current portion of long-term debt 6,071 3,000
---------------------------------------------------------------------------------------------------------------------------------
$136,229 $124,000
=================================================================================================================================
</TABLE>
The Company has several prepayment options under the terms 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.
At December 31, 1994, the Company had two variable rate facilities which
make available $80.0 million of long-term revolving credit, of which $52.3
million was outstanding. 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 1998. The
Company intends to renew or replace the facilities prior to expiration.
At December 31, 1994, the Company had available other lines of credit
totaling $3.5 million. These lines either expire within one year or are
cancellable by the banks involved at any time. All bear interest at or below
the banks' prime rates. There were no outstanding borrowings under these
lines at December 31, 1994.
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, 1994, approximately $121.8 million of retained earnings was
available for payment as dividends.
In 1992, the Company entered into a two-year interest rate swap agreement
with a notional amount of $30.0 million to take advantage of low variable
rates in relation to existing fixed rates on the Company's long-term debt.
This interest rate swap agreement expired in 1994.
Aggregate maturities of long-term debt for each of the years ending
December 31, 1995 through 1999, are $6.1 million, $6.1 million, $28.6 million,
$58.4 million, and $6.1 million. Total interest payments of $10.2 million, $10.3
million, and $11.7 million were made in 1994, 1993, and 1992, respectively.
25
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(3) INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes." The liability method specified by SFAS No. 109 requires the
calculation of accumulated deferred income taxes by application of the tax rate
expected to be in effect when the taxes will actually be paid or refunds will be
received. Under the liability method, the effect on deferred taxes of a change
in tax rates is recognized in income in the period of enactment of the rate
change. Under generally accepted accounting principles previously in effect,
deferred income taxes were not adjusted to reflect changes in tax rates. The
recognition of the cumulative effect, through December 31, 1992, of this change
in accounting increased net income in the first quarter of 1993 by $10.1
million, or $.39 per share. SFAS No. 109 also required an adjustment in the
third quarter of 1993 to record the effects of a legislated increase in tax
rates. This adjustment decreased income before the cumulative effect of the
accounting change by $1.7 million, or $.07 per share.
The provision for income taxes included the following components:
<TABLE>
<CAPTION>
1994 1993 1992
----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Federal:
Current $ 7,758 $11,514 $ 6,190
Deferred 5,588 3,827 5,096
Deferred tax adjustment for tax rate increase -- 1,743 --
State:
Current 1,530 2,190 1,213
Deferred 1,054 752 1,004
Investment tax credit amortization (201) (194) (184)
----------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes $15,729 $19,832 $13,319
==================================================================================================================================
</TABLE>
The provision for income taxes was an effective rate of 38.5% in 1994,
42.3% in 1993, and 37.4% in 1992. 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>
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Expected provision at federal statutory rate of 35% in 1994 and 1993 and 34% in 1992 $14,299 $16,409 $12,098
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,682 1,914 1,463
Percentage depletion on gas and oil production (96) (117) (106)
Adjustment to deferred taxes for tax rate increase -- 1,743 --
Investment tax credit amortization (201) (194) (184)
Other 45 77 48
---------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes $15,729 $19,832 $13,319
=================================================================================================================================
</TABLE>
The components of the Company's net deferred tax liability as of December
31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Deferred tax liabilities:
Differences between book and tax basis of property $ 89,289 $83,875
Stored gas differences 5,736 5,132
Deferred purchased gas costs 1,557 1,232
Prepaid pension costs 1,628 1,731
Book over tax basis in partnerships 3,535 2,675
Gas imbalances 410 644
Other 685 876
---------------------------------------------------------------------------------------------------------------------------------
102,840 96,165
---------------------------------------------------------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 700 770
Other 370 376
---------------------------------------------------------------------------------------------------------------------------------
1,070 1,146
---------------------------------------------------------------------------------------------------------------------------------
Net deferred tax liability $101,770 $95,019
=================================================================================================================================
</TABLE>
26
<PAGE>
Prior to the change in accounting for income taxes, the sources of deferred
tax items, and the corresponding tax effects during 1992 were as follows (in
thousands):
<TABLE>
------------------------------------------------------------------------------
<S> <C>
Intangible and other exploration and development costs $1,581
Investment tax credits amortized (184)
Stored gas differences 972
Excess of tax over book depreciation 1,987
Deferred purchased gas costs 355
Excess of tax over book partnership loss 953
Other 252
------------------------------------------------------------------------------
Deferred provision for income taxes $5,916
==============================================================================
</TABLE>
Total income tax payments of $14.6 million, $10.2 million, and $6.4 million
were made in 1994, 1993, and 1992, 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 1994 and 1993 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 7.5% in 1994
and 8.5% in 1993 for the net pension cost computation, and a salary
progression rate of 5%. The reconciliation of prepaid pension cost at
December 31, 1994 utilizes a discount rate of 8.5% for future settlements.
The following table sets forth the plan's funded status and amounts
recognized in the Company's balance sheets at December 31, 1994 and 1993:
<TABLE>
<CAPTION>
1994 1993
-----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits $(20,643) $(20,746)
Nonvested benefits (1,635) (1,685)
-----------------------------------------------------------------------------------------------
Accumulated benefit obligation (22,278) (22,431)
Effect of projected future compensation levels (6,368) (7,463)
-----------------------------------------------------------------------------------------------
Projected benefit obligation (28,646) (29,894)
Plan assets at fair value, primarily common stocks and bonds 36,675 36,601
-----------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 8,029 6,707
Unrecognized net gain (3,617) (1,869)
Unrecognized net asset (1,135) (1,318)
Unrecognized prior service cost 454 274
-----------------------------------------------------------------------------------------------
Prepaid pension cost $ 3,731 $ 3,794
===============================================================================================
</TABLE>
Net pension cost for 1994, 1993 and 1992 included the following components:
<TABLE>
<CAPTION>
1994 1993 1992
-----------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Service costs (benefits earned during the period) $ 1,217 $ 897 $ 805
Interest cost on projected benefit obligation 2,280 1,999 1,768
Actual return on plan assets (791) (2,819) (4,914)
Net amortization and deferral (2,643) (673) 1,860
-----------------------------------------------------------------------------------------------
Net pension cost (credit) $ 63 $ (596) $ (481)
===============================================================================================
</TABLE>
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $201,000,
$628,000, and $241,000 in 1994, 1993, and 1992, respectively. In 1993, this plan
was funded with $1.2 million. At December 31, 1994, the supplemental retirement
plan had a prepaid pension cost of $130,000.
Effective January 1, 1993, the Company adopted SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions." Under SFAS No.
106, the cost of those benefits is accrued over the period the employee
provides services to the Company. Prior to 1993, postretirement benefit
expenses were recognized on a pay-as-you-go basis and were not material. The
Company currently funds postretirement benefits as claims are incurred.
27
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
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.
A significant portion of the postretirement benefit cost relates to the
Company's utility operations and has been deferred as a regulatory asset. Net
postretirement benefit cost for 1994 and 1993 included the following
components:
<TABLE>
<CAPTION>
1994 1993
-------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Service cost of benefits earned during the year $ 79 $ 61
Amortization of transition amount 178 103
Amortization of unrecognized gain 17 --
Interest cost on accumulated postretirement benefit obligation (APBO) 164 158
-------------------------------------------------------------------------------------------------------
Net postretirement benefit cost $438 $322
=======================================================================================================
</TABLE>
The APBO as of December 31, 1994 and 1993 was comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Retirees $ 766 $ 655
Active participants, fully eligible 442 543
Other participants 804 835
-------------------------------------------------------------------------------------------------------
Total APBO $2,012 $2,033
=======================================================================================================
</TABLE>
In determining the APBO, assumed weighted average discount rates of 8.5%
and 7.5% were used for 1994 and 1993, respectively. An increase of 8.0% in the
cost of covered health care benefits was assumed for 1995. This rate is assumed
to decrease ratably to 6.0% over 7 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 1994
by $254,000 and the 1994 net postretirement benefit cost by $31,000.
(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>
1994 1993 1992
-------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Sales $ 80,123 $ 79,374 $ 60,554
Production (lifting) costs (6,771) (6,341) (4,271)
Depreciation, depletion and amortization (29,743) (25,686) (19,128)
-------------------------------------------------------------------------------------------------------
43,609 47,347 37,155
Income tax expense (16,684) (18,081) (13,787)
-------------------------------------------------------------------------------------------------------
Results of operations $ 26,925 $ 29,266 $ 23,368
=======================================================================================================
</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 1994, 1993
and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
-------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Property acquisition costs $21,972 $ 5,920 $ 4,768
Exploration costs 12,419 11,695 6,441
Development costs 20,943 19,722 19,563
-------------------------------------------------------------------------------------------------------
Capitalized costs incurred $55,334 $37,337 $30,772
=======================================================================================================
Amortization per Mcf equivalent $.759 $.710 $.723
=======================================================================================================
</TABLE>
28
<PAGE>
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at
December 31, 1994 and 1993:
<TABLE>
<CAPTION>
1994 1993
---------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Proved properties $405,081 $350,854
Unproved properties 30,489 24,427
---------------------------------------------------------------------------------------------
Total capitalized costs 435,570 375,281
Less: Accumulated depreciation, depletion and amortization 176,764 146,471
---------------------------------------------------------------------------------------------
Net capitalized costs $258,806 $228,810
=============================================================================================
</TABLE>
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1994. Included in property
acquisition costs is $7.3 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 five years as this acreage is further
explored and developed. 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>
1994 1993 1992 Prior Total
------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs $3,655 $1,441 $286 $7,199 $12,581
Exploration costs 3,230 1,200 128 579 5,137
Capitalized interest 1,178 452 71 1,332 3,033
------------------------------------------------------------------------------------------------------------------
$8,063 $3,093 $485 $9,110 $20,751
==================================================================================================================
</TABLE>
(6) NATURAL GAS AND OIL RESERVES (UNAUDITED)
The following table summarizes the changes in the Company's proved natural
gas and oil reserves for 1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
----------------------------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year 318,776 479 312,291 359 307,484 505
Revisions of previous estimates (16,551) (258) (4,110) (25) 704 (30)
Extensions, discoveries and other additions 30,932 189 46,069 250 29,627 4
Production (37,706) (200) (35,693) (97) (25,755) (120)
Acquisition of reserves in place 20,647 1,038 222 -- 231 --
Disposition of reserves in place -- (17) (3) (8) -- --
----------------------------------------------------------------------------------------------------------------------------
Proved reserves, end of year 316,098 1,231 318,776 479 312,291 359
============================================================================================================================
Proved, developed reserves:
Beginning of year 260,240 469 246,904 337 226,767 467
End of year 261,690 1,116 260,240 469 246,904 337
============================================================================================================================
</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 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, 1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
---------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Future cash inflows $ 683,438 $ 745,967 $ 681,033
Future production and development costs (96,813) (85,609) (84,483)
Future income tax expense (207,359) (236,170) (207,249)
---------------------------------------------------------------------------------------------------------
Future net cash flows 379,266 424,188 389,301
10% annual discount for estimated timing of cash flows (189,774) (196,913) (179,331)
---------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 189,492 $ 227,275 $ 209,970
=========================================================================================================
</TABLE>
29
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
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 and enacted tax legislation, 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
1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
---------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $227,275 $209,970 $198,274
Sales and transfers of gas and oil produced, net of production costs (73,352) (73,017) (56,283)
Net changes in prices and production costs (29,344) 22,392 9,446
Extensions, discoveries, and other additions, net of future production and development costs 43,458 74,511 52,917
Revisions of previous quantity estimates (19,225) (5,217) 318
Accretion of discount 34,968 31,885 30,253
Net change in income taxes 24,564 (13,524) (4,623)
Changes in production rates (timing) and other (18,852) (19,725) (20,332)
---------------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $189,492 $227,275 $209,970
=================================================================================================================================
</TABLE>
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company held a general partnership interest in NOARK of 47.93% at
December 31, 1994 and 47.33% at December 31, 1993, and is the pipeline's
operator. NOARK is a 258 mile long intrastate gas transmission system which
extends across northern Arkansas and was placed in service in September,
1992. NOARK's total construction cost was approximately $103.0 million, with
$16.0 million provided by equity contributions of the partners and the
remainder provided by long-term debt. NOARK's transportation capacity is 141
million cubic feet of gas per day (MMcfd).
The Company's investment in NOARK totaled $4.8 million at December 31, 1994
and $5.3 million at December 31, 1993. The Company's investment in NOARK
includes advances of $2.3 million made during 1994 to make the final payment of
construction retainage and to provide certain minimum cash balances to service
NOARK's long-term debt. Subsequent to December 31, 1994, the Company advanced an
additional $1.1 million to NOARK. 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, 1994 and 1993 is summarized
below:
<TABLE>
<CAPTION>
1994 1993
-----------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Current assets $ 1,078 $ 1,551
Noncurrent assets 100,662 102,322
-----------------------------------------------------------------------------------------
$101,740 $103,873
=========================================================================================
Current liabilities $ 6,009 $ 7,290
Long-term debt 86,250 85,050
Loans from general partners 3,225 --
Partners' capital 6,256 11,533
-----------------------------------------------------------------------------------------
$101,740 $103,873
=========================================================================================
</TABLE>
The Company's share of NOARK's 1994, 1993 and 1992 pretax loss included in
other income (expense) on the statements of income was $2.8 million, $1.8
million, and $.6 million, respectively.
NOARK's results of operations for 1994, 1993 and 1992 are summarized below:
<TABLE>
<CAPTION>
1994 1993 1992
---------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating revenues $10,111 $ 8,301 $ 1,466
Pretax loss $(5,917) $(3,778) $(1,348)
===========================================================================
</TABLE>
(8) DISCLOSURES ABOUT THE 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.
30
<PAGE>
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.
The estimated fair values of the Company's financial instruments as of
December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
-------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
----------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Cash $1,152 $1,152 $834 $834
Customer deposits $4,232 $4,232 $3,927 $3,927
Long-term debt $142,300 $144,245 $127,000 $134,661
========================================================================================
</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 in fact 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.
At December 31, 1993, the Company also had an interest rate swap with a
notional amount of $30.0 million, as discussed in Note 2, with terms that
approximate fair market value.
(9) SEGMENT INFORMATION
The Company operates principally in the exploration and production segment
and the gas distribution segment of the natural gas industry. Exploration and
production activities consist of ownership of mineral interests in productive
and undeveloped leases located entirely in the United States. The gas
distribution activities consist of the operation of integrated natural gas
transmission and distribution utility systems in the states of Arkansas and
Missouri.
Intersegment sales by the exploration and production segment to the gas
distribution segment are priced in accordance with terms of existing gas
contracts and current market conditions. Following is industry segment data
for the years ended December 31, 1994, 1993 and 1992:
<TABLE>
<CAPTION>
1994 1993 1992
------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
REVENUES
Exploration and production $ 80,123 $ 79,374 $ 60,554
Gas distribution 127,060 131,892 117,495
Other 308 262 256
Eliminations (37,305) (36,684) (34,475)
------------------------------------------------------------------------------
$170,186 $174,844 $143,830
------------------------------------------------------------------------------
INTERSEGMENT REVENUES
Exploration and production $ 36,465 $ 36,091 $ 33,994
Gas distribution 584 337 225
Other 256 256 256
------------------------------------------------------------------------------
$ 37,305 $ 36,684 $ 34,475
------------------------------------------------------------------------------
OPERATING INCOME
Exploration and production $ 38,883 $ 42,608 $ 33,071
Gas distribution 13,391 15,261 13,094
Corporate expenses (192) (305) (177)
------------------------------------------------------------------------------
$ 52,082 $ 57,564 $ 45,988
------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Exploration and production $286,887 $236,968 $224,302
Gas distribution 171,470 186,704 179,998
Other 26,225 21,782 22,875
------------------------------------------------------------------------------
$484,582 $445,454 $427,175
------------------------------------------------------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION
Exploration and production $ 29,743 $ 25,686 $ 19,128
Gas distribution 4,976 4,564 4,213
Other 827 694 539
------------------------------------------------------------------------------
$ 35,546 $ 30,944 $ 23,880
------------------------------------------------------------------------------
CAPITAL ADDITIONS
Exploration and production $ 55,449 $ 37,411 $ 30,823
Gas distribution 17,577 19,892 12,188
Other 3,828 1,916 1,898
------------------------------------------------------------------------------
$ 76,854 $ 59,219 $ 44,909
==============================================================================
</TABLE>
31
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(10) STOCK OPTIONS
In 1993, the Board of Directors adopted, and the shareholders approved, the
Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan) for the
compensation of officers and key employees of the Company and its subsidiaries.
The 1993 Plan replaced both the Company's 1985 Non-Qualified Stock Option Plan
(1985 Plan) and the long-term component of the Company's then existing cash-
based incentive compensation plan. 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 ten-year term of the plan.
At December 31, 1994, there were options for 886,108 shares outstanding
under the 1993 Plan at option prices of $14 5/8 and $17 1/8, representing the
fair market values at the dates of grant. Of the total, 783,704 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 remaining
options, granted in 1993, vest to employees over a three-year period from the
date of grant. Options for 14,387 shares are currently exercisable. All options
expire ten years from the date of grant. Additionally, 5,573 shares in 1994 and
17,447 shares in 1993 of restricted stock have been granted which vest to
employees over a five-year period. The related compensation expense is being
amortized over the vesting period.
Under the 1985 Plan, there were options for 427,050 shares and 84,900 SARs
outstanding at December 31, 1994, at prices ranging from $5.58 to $12.81. All
options are currently exercisable. All options expire ten years from the date
of grant. The number of options, SARs, and option prices have been restated
to reflect the effect of a three-for-one stock split distributed in 1993.
In 1993, the Company also adopted, and the shareholders approved, the
Southwestern Energy Company 1993 Stock Incentive Plan for Outside Directors.
The directors' plan 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. Options are issued at
fair market value on the date of grant and become exercisable in installments
at a rate of 25% per year for each twelve months' service as a director. At
December 31, 1994, there were options for 96,000 shares outstanding at option
prices of $14 3/4 and $17 1/2. Options for 12,000 shares are currently
exercisable.
(11) 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. The
exercise price and the number of rights outstanding have been adjusted to
reflect the effects of the stock split distributed in 1993. 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.
(12) CONTINGENCIES AND COMMITMENTS
The Company and the other general partner of NOARK are required to
severally guarantee the availability of certain minimum cash balances to service
the 9.7375% Senior Secured Notes used to finance a portion of NOARK's total
construction cost. At December 31, 1994, the Senior Secured Notes had a
remaining balance of $59.9 million. The notes have a remaining term of 15 years
and the Company's share of the several guarantee is 60%. At December 31, 1994,
NOARK also had an unsecured long-term revolving credit agreement in the amount
of $30.0 million with a group of banks, of which $29.6 million was outstanding.
Amounts borrowed under the long-term revolving credit facility are severally
guaranteed by the Company and an affiliate of the other general partner. The
Company's share of the several guarantee of the line of credit is also 60%.
Additionally, the Company's gas distribution subsidiary has a ten-year
transportation contract with NOARK for firm capacity of 41 MMcfd.
32
<PAGE>
In late 1993, a transporter of gas on NOARK's pipeline system filed suit
against NOARK, the Company, and certain of its affiliates, and, effective
January 1, 1994, ceased transporting gas under its firm transportation
agreement with NOARK. The complaint seeks rescission of the transportation
contract and rescission of a separate contract to purchase gas from two of
the Company's affiliates, as well as actual and punitive damages in excess of
$1.0 million. The Company and NOARK believe the suit is without merit and
have filed counterclaims seeking enforcement of the contracts and damages.
Until enforcement occurs or replacement transportation contracts are
arranged, the Company will be required to fund its share of any cash flow
deficiencies to the extent they are not funded by the available line of
credit. Management of the Company and the NOARK partners are currently
investigating several options available to NOARK. However, management
believes that no write-down of its investment in NOARK is appropriate at this
time and 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.
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 that has arisen in the ordinary
course of business. In the opinion of management, the results of such
litigation 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, 1994 and 1993:
<TABLE>
<CAPTION>
Quarter Ended March 31 June 30 September 30 December 31
---------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
1994
----
Operating revenues $65,430 $34,605 $27,808 $42,343
Operating income $23,525 $10,471 $6,327 $11,759
Net income $12,994 $4,834 $2,128 $5,168
Earnings per share $.51 $.18 $.09 $.20
1993
----
Operating revenues $59,208 $33,990 $28,466 $53,180
Operating income $21,259 $8,738 $7,789 $19,778
Income before cumulative effect
of accounting change $11,372 $3,696 $1,439 $10,543
Net income $21,498 $3,696 $1,439 $10,543
Earnings per share before cumulative
effect of accounting change $.44 $.15 $.05 $.41
Earnings per share $.83 $.15 $.05 $.41
===============================================================================================================
</TABLE>
33
<PAGE>
Financial and Operating Statistics
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990 1989
----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
FINANCIAL REVIEW (in thousands)
Operating revenues:
Exploration and production $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489 $ 40,499
Gas distribution 127,060 131,892 117,495 121,302 108,911 117,514
Other 308 262 256 256 256 256
Intersegment revenues (37,305) (36,684) (34,475) (34,511) (33,586) (33,670)
----------------------------------------------------------------------------------------------------------------------------------
170,186 174,844 143,830 136,439 117,070 124,599
----------------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 36,395 42,962 35,848 40,423 37,678 46,850
Operating and general 42,506 40,093 34,970 32,609 28,134 26,132
Depreciation, depletion and amortization 35,546 30,944 23,880 18,248 14,756 16,055
Taxes, other than income taxes 3,657 3,281 3,144 3,017 2,885 2,844
----------------------------------------------------------------------------------------------------------------------------------
118,104 117,280 97,842 94,297 83,453 91,881
----------------------------------------------------------------------------------------------------------------------------------
Operating income 52,082 57,564 45,988 42,142 33,617 32,718
Interest expense, net (8,867) (9,025) (9,983) (9,813) (10,530) (10,662)
Other income (expense) (2,362) (1,657) (421) (107) (17) 180
----------------------------------------------------------------------------------------------------------------------------------
Income before provision for income taxes 40,853 46,882 35,584 32,222 23,070 22,236
----------------------------------------------------------------------------------------------------------------------------------
Provision for income taxes:
Current 9,288 13,704 7,403 7,158 4,994 6,671
Deferred 6,441 6,128 5,916 4,999 3,568 1,586
----------------------------------------------------------------------------------------------------------------------------------
15,729 19,832 13,319 12,157 8,562 8,257
----------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative
effect of accounting change 25,124 27,050 22,265 20,065 14,508 13,979
Extraordinary loss due to redemption of convertible
debentures (net of $257 tax benefit) -- -- -- -- (433) --
Cumulative effect of change in accounting for income taxes -- 10,126 -- -- -- --
----------------------------------------------------------------------------------------------------------------------------------
Net income $ 25,124 $ 37,176 $ 22,265 $ 20,065 $ 14,075 $ 13,979
==================================================================================================================================
Cash flow from operations (in thousands) $66,613 $70,191 $49,730 $34,986 $36,495 $29,306
Return on equity 12.35% 14.66%/(1)/ 14.53% 14.75% 11.66% 13.51%
Gross profit margin 30.60% 32.92% 31.97% 30.89% 28.72% 26.26%
Net profit margin 14.76% 15.47%/(1)/ 15.48% 14.71% 12.02% 11.22%
==================================================================================================================================
COMMON STOCK STATISTICS/(2)/
Earnings per share before extraordinary item and
cumulative effect of accounting change $.98 $1.05 $.87 $.78 $.57 $.56
Earnings per share $.98 $1.44 $.87 $.78 $.56 $.56
Cash dividends declared and paid per share $.24 $.22 $.20 $.19 $.19 $.19
Book value per share $7.92 $7.18 $5.97 $5.30 $4.70 $4.15
Market price at year end $14.88 $18.00 $12.96 $10.50 $10.42 $10.75
Number of shareholders of record at year end 2,875 3,005 2,930 2,989 3,136 3,298
Average shares outstanding 25,684,110 25,684,110 25,683,963 25,678,011 25,270,674 24,940,488
==================================================================================================================================
CAPITALIZATION (in thousands)
Long-term debt, including current portion $142,300 $127,000 $143,335 $134,104 $125,535 $128,449
Common shareholders' equity 203,456 184,530 153,233 136,041 120,709 103,455
----------------------------------------------------------------------------------------------------------------------------------
Total capitalization $345,756 $311,530 $296,568 $270,145 $246,244 $231,904
----------------------------------------------------------------------------------------------------------------------------------
Total assets $484,582 $445,454 $427,175 $392,208 $366,313 $347,212
----------------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 40.10% 40.19% 48.31% 49.08% 50.39% 54.82%
Equity 59.90% 59.81% 51.69% 50.92% 49.61% 45.18%
==================================================================================================================================
CAPITAL EXPENDITURES (in millions)
Exploration and production $55.4 $37.4 $30.8 $30.3 $23.4 $26.6
Gas distribution 17.6 19.9 12.2 7.9 9.3 8.9
Other 3.9 1.9 1.9 .7 .7 3.5
----------------------------------------------------------------------------------------------------------------------------------
$76.9 $59.2 $44.9 $38.9 $33.4 $39.0
==================================================================================================================================
</TABLE>
/(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.
34
<PAGE>
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990 1989
-----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
NATURAL GAS AND OIL WELLS COMPLETED
Producers:
Gross 78.0 57.0 69.0 25.0 25.0 38.0
Net 50.2 40.7 54.6 11.8 9.1 16.4
Dry holes:
Gross 30.0 28.0 29.0 12.0 10.0 22.0
Net 16.5 14.5 19.5 4.1 2.1 7.3
-----------------------------------------------------------------------------------------------------------------------------------
Total:
Gross 108.0 85.0 98.0 37.0 35.0 60.0
Net 66.7 55.2 74.1 15.9 11.2 23.7
At the end of 1994, the Company was a participant in 8.0 (2.1 net) wells in process.
===================================================================================================================================
NATURAL GAS AND OIL PRODUCED
Natural gas:
Production, Bcf 37.7 35.7 25.8 20.3 16.7 15.6
Average price per Mcf $2.04 $2.18 $2.26 $2.25 $2.33 $2.43
Oil:
Production, MBbls 200 97 120 176 112 149
Average price per barrel $15.89 $17.20 $19.75 $20.67 $22.89 $17.89
Average production (lifting) cost per Mcf equivalent $.17 $.18 $.16 $.19 $.16 $.14
Proved reserves at year end:
Natural gas, Bcf 316.1 318.8 312.3 307.5 304.5 252.9
Oil, MBbls 1,231 479 359 505 773 745
===================================================================================================================================
UTILITY OPERATING DATA
Sales volumes, Bcf:
Residential 11.6 12.9 10.8 10.9 10.1 11.6
Commercial 7.2 7.8 6.6 6.7 6.3 7.1
Industrial 7.5 6.1 6.1 9.5 10.2 9.8
Transportation volumes, Bcf
End-use 4.8 5.6 5.2 1.3 .1 .5
Off-system 10.7 11.7 2.5 .2 .3 .1
-----------------------------------------------------------------------------------------------------------------------------------
41.8 44.1 31.2 28.6 27.0 29.1
-----------------------------------------------------------------------------------------------------------------------------------
Average sales customers:
Residential 140,684 137,087 133,103 129,379 127,142 125,581
Commercial 18,872 18,511 18,141 17,880 17,680 17,437
Industrial 341 346 348 370 366 372
-----------------------------------------------------------------------------------------------------------------------------------
159,897 155,944 151,592 147,629 145,188 143,390
-----------------------------------------------------------------------------------------------------------------------------------
Sales and transportation revenues (in thousands):
Residential $ 62,565 $ 67,502 $ 59,747 $ 58,372 $ 48,407 $ 54,181
Commercial 32,252 35,311 31,425 30,718 27,535 30,522
Industrial 25,191 21,757 20,502 29,187 30,463 29,982
Transportation 4,721 5,177 3,597 857 179 368
-----------------------------------------------------------------------------------------------------------------------------------
$124,729 $129,747 $115,271 $119,134 $106,584 $115,053
-----------------------------------------------------------------------------------------------------------------------------------
Miles of pipe:
Gathering 405 398 383 375 371 364
Transmission 1,346 1,335 1,328 1,326 1,326 1,309
Distribution 4,246 4,160 4,090 4,002 3,931 3,859
-----------------------------------------------------------------------------------------------------------------------------------
5,997 5,893 5,801 5,703 5,628 5,532
-----------------------------------------------------------------------------------------------------------------------------------
Degree days 4,161 4,929 4,104 4,095 3,972 4,961
Percent of normal 95% 113% 92% 93% 90% 112%
===================================================================================================================================
</TABLE>
35
<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
Wednesday, May 31, 1995, 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 AUDITORS
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
This annual report and the statements contained herein are submitted for the
general information of shareholders of the Company and are not intended to
induce any sale or purchase of securities or to be used in connection
therewith.
The 1994 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
------------------------------------------------ -------------------
1994 1993 1994 1993
---------------------------------------------------------------------------------------------
HIGH LOW High Low
<S> <C> <C> <C> <C> <C> <C>
March 31 $18.88 $15.13 $15.25 $12.13 $.06 $.05
June 30 $17.75 $15.50 $16.83 $14.13 $.06 $.05
September 30 $17.88 $15.50 $21.75 $16.04 $.06 $.06
December 31 $17.75 $14.00 $21.88 $15.13 $.06 $.06
============================================================================================
</TABLE>
Market prices represent transactions on the New York Stock Exchange.
36
<PAGE>
Southwestern Energy Company and Subsidiaries
APPENDIX TO 1994 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in three
areas; the Arkoma Basin, the Anadarko Basin and the Gulf Coast. 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. 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 they also provide
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 47.93% general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Claimant's distribution
and gathering pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Fort 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.
Operating Properties:
ACREAGE AND PRODUCING WELLS
<TABLE>
<CAPTION>
Undeveloped Developed Wells
Gross Net Gross Net Gross Net
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Arkansas 184,008 95,486 289,387 138,269 736 380.6
Louisiana 15,874 8,938 10,748 3,214 10 5.2
Oklahoma 23,746 15,946 69,835 36,214 465 241.6
Texas 25,121 13,292 51,024 11,247 29 6.7
Other areas 8,361 7,992 5,490 1,313 14 3.8
--------------------------------------------------------------------------------
257,110 141,654 426,484 190,257 1,254 637.9
================================================================================
</TABLE>
<TABLE>
<CAPTION>
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
--------------------------------------------------------------------------------
<S> <C> <C> <C>
Gathering 405 -- 405
Transmission 744 602 1,346
Distribution 2,691 1,555 4,246
--------------------------------------------------------------------------------
3,840 2,157 5,997
================================================================================
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 1,152
<SECURITIES> 0
<RECEIVABLES> 32,325
<ALLOWANCES> 0
<INVENTORY> 12,199
<CURRENT-ASSETS> 48,029
<PP&E> 667,468
<DEPRECIATION> (242,008)
<TOTAL-ASSETS> 484,582
<CURRENT-LIABILITIES> 39,143
<BONDS> 136,229
<COMMON> 2,774
0
0
<OTHER-SE> 200,682
<TOTAL-LIABILITY-AND-EQUITY> 484,582
<SALES> 163,641
<TOTAL-REVENUES> 170,186
<CGS> 0
<TOTAL-COSTS> 118,104
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,867
<INCOME-PRETAX> 40,853
<INCOME-TAX> 15,729
<INCOME-CONTINUING> 25,124
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 25,124
<EPS-PRIMARY> .98
<EPS-DILUTED> 0
</TABLE>
