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SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
(Mark one)
[x] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 (Fee required)
For the fiscal year ended December 31, 1995
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K._____
The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $287,525,532 based on the New York Stock Exchange - Composite
Transactions closing price on March 25, 1996 of $11.75.
The number of shares outstanding as of March 25, 1996, of the
Registrant's Common Stock, par value $.10, was 24,701,349.
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, 1995 - 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 13, 1996 - PART III.
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SOUTHWESTERN ENERGY COMPANY
FORM 10-K
ANNUAL REPORT
For the Year Ended December 31, 1995
TABLE OF CONTENTS
<TABLE>
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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................................................................ 13
Item 12. Security Ownership of Certain Beneficial Owners and Management........................ 13
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. Through its wholly-owned subsidiaries, the Company is engaged in gas
and oil exploration and production, natural gas gathering and transmission as
well as natural gas distribution. The principal sites for the Company's
exploration and production program are the Arkoma Basin of Arkansas, the Gulf
Coast (both onshore and shallow waters offshore) and the Anadarko Basin of
Oklahoma. The Company's natural gas gathering transmission and distribution
properties are located in Arkansas and Missouri. The Company was incorporated
under the laws of the state of Arkansas and is an exempt holding company under
the Public Utility Holding Company Act of 1935.
The Company was organized in 1929 as a local distribution company in
northwest Arkansas. 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.
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,
including the Gulf Coast areas of Louisiana and Texas, the Anadarko Basin of
Oklahoma, and the Delaware Basin of New Mexico. 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
serving approximately 168,000 customers. Arkansas Western is the largest single
purchaser of SEECO's gas production. Southwestern Energy Pipeline Company (SWPL)
owns a 47.93% general partnership interest in the NOARK Pipeline System, Limited
Partnership (NOARK), a 258 mile long intrastate natural gas transmission system
that extends across northern Arkansas. SWPL also serves as operator of the
pipeline.
This document may contain "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. See "Management's Discussion and Analysis of Financial
Condition and Results of Operation" in Part II, Item 7 of this Report for a
discussion of important factors that could affect the validity of any such
forward-looking statements. 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 Arkansas, the Gulf Coast areas of Louisiana and
Texas, Oklahoma, and New Mexico. At December 31, 1995, the Company had proved
natural gas reserves of 294.9 billion cubic feet (Bcf) and proved oil reserves
of 2,152 thousand barrels (MBbls). Revenues of the exploration and production
subsidiaries are
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predominately generated from production of natural gas. The Company's gas
production was 34.5 Bcf in 1995, down 8% from 37.7 Bcf in 1994. Sales of gas
production accounted for 93% of total operating revenues for this segment in
1995, 96% in 1994, and 98% in 1993. SEECO's largest customer for sales of its
gas production was the Company's utility subsidiary. However, sales to
unaffiliated purchasers, as a percentage of total sales made by both SEECO and
SEPCO, have generally increased during the last three years as compared to
periods prior to 1993. This increased percentage is due primarily to higher
production from Arkansas properties, from producing property acquisitions, and
from properties developed in the Gulf Coast areas. Sales to unaffiliated
purchasers accounted for 60% of total gas volumes sold by the exploration and
production segment in 1995, 63% in 1994, and 64% in 1993.
Gas volumes sold by SEECO to Arkansas Western for its northwest Arkansas
division (AWG) were 8.5 Bcf in 1995, 8.8 Bcf in 1994, and 7.1 Bcf in 1993.
Through these sales, SEECO furnished 65% of the northwest Arkansas system's
requirements in 1995, 64% in 1994, and 57% in 1993. The increase in 1994
compared to 1993 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 1.4 Bcf in 1995, 1.5 Bcf in
1994, and 2.2 Bcf in 1993 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 that became effective July 1, 1994, and calls for sales
under the contract to take place at a price which is equal to a spot market
index plus a premium. The Gas Cost Settlement has resulted in a lower contract
price based on market conditions since the settlement. That effect has been
offset in part by provisions of the Gas Cost Settlement which allow additional
volumes to be sold under the amended 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 incremental sales
volumes receive a premium of $.50 per Mcf. In 1995, 7.7 Bcf (net to the
Company's interest) was sold under the contract, compared to 8.1 Bcf in 1994 and
6.0 Bcf in 1993. Other significant terms of the Gas Cost Settlement preclude the
parties thereto from asking for refunds, transfer certain of AWG's natural gas
storage facilities to SEECO, and prohibited AWG from filing an application for a
rate increase 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
have accounted for approximately 31% of total exploration and production
revenues each of the last three years.
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 5.4 Bcf in 1995, 5.1 Bcf in 1994, and 5.7
Bcf in 1993. These deliveries accounted for approximately 59% of Associated's
total requirements in 1995, 58% in 1994, and 67% in 1993. These sales
represented 16% of total exploration and production revenues in 1995, 14% in
1994, and 15% in 1993. Deliveries to Associated increased in 1995 due to colder
weather in the heating season and decreased in 1994 due to warmer weather.
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, decreased to $2.20 per Mcf for the contract period ended
September 30, 1995, and are currently being made at a price of $1.785 per Mcf.
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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, 1995, after transfers and
revisions, the remaining proved undeveloped reserves identified by the study
were 40.1 Bcf. The data base developed is periodically updated by drilling
activity and provides guidance in the Company's development drilling program.
The development drilling program added 17.1 Bcf in 1995, 22.2 Bcf in 1994, and
27.0 Bcf in 1993 of new natural gas reserve additions and resulted in the
transfer of .7 Bcf in 1995, 3.0 Bcf in 1994, and 2.6 Bcf in 1993 from the proved
undeveloped category to the proved developed category. SEECO participated in a
total of 80 development wells during 1995 with a completion rate of 68%. SEECO's
sales to unaffiliated purchasers were 10.3 Bcf in 1995, 10.7 Bcf in 1994, and
10.0 Bcf in 1993. 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 of NOARK in September,
1992, as explained more fully below under "Natural gas gathering, transmission
and distribution." SEECO's sales to unaffiliated purchasers have accounted for
approximately 22% of total exploration and production revenues for the last
three years.
At December 31, 1995, the gas and oil reserves of SEPCO were located
primarily in Oklahoma and the Gulf Coast areas of Louisiana and Texas. SEPCO
also owns gas reserves in Arkansas, primarily related to its properties on the
Fort Chaffee military reservation. SEPCO holds about 27% of the Company's
natural gas reserves and all of its oil reserves. SEPCO's gas sales were 10.3
Bcf in 1995, down from 13.1 Bcf in 1994 and 12.9 Bcf in 1993. The decrease in
1995 was primarily due to declining production in the Company's offshore Gulf of
Mexico properties. SEPCO's production is sold under contracts which reflect
current short-term prices and which are subject to seasonal price swings.
Oil production was 229 MBbls in 1995, compared to 200 MBbls in 1994 and 97
MBbls in 1993. The increase in oil production in 1995 and 1994 primarily
resulted from acquisitions of producing properties during those years. 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 31% of total
exploration and production operating revenues in 1995 and 33% in both 1994 and
1993.
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 nine wells at Fort Chaffee that
have discovered an estimated 47.1 Bcf of new gas reserves, net to the Company's
interest. Sales of gas production from Fort Chaffee totaled 3.0 Bcf in 1995, 4.3
Bcf in 1994, and 5.1 Bcf in 1993. 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. Fort Chaffee has been closed as an active military base, but is presently
planned to be a
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training facility for the National Guard and other governmental agencies. The
Company is not able to predict whether this change in activities conducted at
Fort Chaffee will result in less restrictive operating conditions. As a result,
Fort Chaffee will play a lesser role in the Company's plans.
Outside Arkansas, the Company added 18.0 Bcf of new reserves in 1995 and
8.7 Bcf in 1994 from drilling. Of that total, 11.3 Bcf in 1995 and 8.5 Bcf in
1994 were from discoveries in the coastal areas of Texas and Louisiana. The Gulf
Coast region continues to be the primary focus of most of the Company's
exploration activity. The Company currently is participating in several 3-D
seismic programs in south Louisiana and spent approximately $5.0 million in 1995
on the largest of these programs, a 130 square mile 3-D seismic data acquisition
joint venture in the east Atchafalaya Basin of south Louisiana, primarily in St.
Martin Parish. The Company has a 50% working interest in the venture. About
100,000 acres is under option, convertible to leasehold acreage as the seismic
data is interpreted. While the options carry rights to all depths, the Company's
interest is primarily in those objectives deeper than the historically
productive zones. The Company expects this venture to generate a significant
number of well-defined exploration prospects. Drilling will not commence any
earlier than the fourth quarter of 1996. The Company is also participating in a
development drilling program in the Delaware Basin of New Mexico, keyed off
three 1995 discovery wells. The Company will participate with up to a 50%
working interest in 10 or more development wells during 1996 and more in 1997.
The Company also has two more exploratory wells to drill in the area.
During 1995 and 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 4.5 Bcf of gas and 851 MBbls of oil during 1995, and 20.6 Bcf of
gas and 1,038 MBbls of oil during 1994. The 1995 acquisitions were primarily in
the Gulf Coast areas of Louisiana and Texas and the 1994 acquisitions were
primarily in the Anadarko Basin of Oklahoma.
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 1996 capital expenditures for gas and oil
exploration and development to total $71.0 million, down from $82.2 million
incurred in 1995. Expenditures in 1996 for this segment are expected to be $24.5
million for development drilling, including $14.5 million for the Company's
Arkansas program, $20.0 million for producing property acquisitions, and a total
of $12.4 million for exploratory drilling and seismic. Most of the Company's
risk-oriented spending will be directed toward its 3-D seismic joint ventures.
The Company will review this budget periodically during the year for possible
adjustment depending upon cash flow projections related to fluctuating prices
for natural gas and oil.
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 168,000 retail customers and obtains a substantial portion of the
gas they consume through its Arkoma Basin gathering facilities. The Company is
also a
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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.
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 101,000 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. Curtailment of large industrial
customers of AWG and Associated occurs only infrequently when extremely cold
weather requires that systems be dedicated exclusively to human needs customers.
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 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 cost of service included in AWG's present tariff for large business
customers and agree to reimburse AWG for any take-or-pay liability caused by
spot market purchases on the customer's behalf. In an effort to more fully meet
the service needs of larger business customers, both AWG and Associated
instituted a
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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 transportation service, including three of
AWG's four largest customers in northwest Arkansas and Associated's two largest
customers in northeast Arkansas. Associated's 13 largest Missouri customers are
currently using transportation service.
AWG purchases its system gas supply directly at the wellhead under
long-term contracts. Purchases are made from approximately 290 working interest
owners in 484 producing wells. As previously indicated, SEECO furnished
approximately 65% of AWG's system requirements in 1995, 64% in 1994, and 57% in
1993. A significant portion of AWG's unaffiliated supply comes from market
responsive, long-term contracts which take advantage of the lower prices that
have generally been available from gas suppliers.
At December 31, 1995, AWG had a gas supply available to its northwest
Arkansas system of approximately 213 Bcf of proved developed reserves, equal to
15 times current annual usage. Of this total, approximately 109 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.
Associated purchases gas for its system supply from unaffiliated suppliers
accessed by interstate pipelines and from SEECO. Purchases from SEECO are under
a ten-year contract with annual price redeterminations. Purchases from
unaffiliated suppliers are under firm contracts with terms between one and three
years. The rates charged by these suppliers include demand components to ensure
availability of gas supply, administrative fees, and a commodity component which
is based on spot market gas prices. Associated's gas purchases are transported
through eight pipelines. The pipeline transportation rates include demand
charges to reserve pipeline capacity and commodity charges based on volumes
transported. Associated has also contracted with five 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. In 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.
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 changed a major
portion of the gas acquisition merchant function provided to gas distributors by
interstate pipelines. AWG already obtains its supply at the wellhead directly
from producers and has not been directly impacted by Order No. 636. Associated
has acquired the bulk of its gas supply at the wellhead since its acquisition by
Arkansas Western, but continued until Order No. 636 to purchase a portion of
both its peak and base requirements from interstate suppliers. The changes
mandated by Order No. 636 have placed the
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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, net of refunds
received, approximately $2.6 million in contract reformation costs and
take-or-pay costs, and $2.5 million in transition costs which its interstate
pipeline suppliers incurred and were allowed to recover. The Company anticipates
full recovery of the $2.5 million in transition costs incurred. To date, the
Company has recovered approximately $1.5 million of the contract reformation
costs and take-or-pay costs from its utility sales customers in the state of
Missouri. Of the unrecovered $1.1 million related to contract reformation costs
and take-or-pay costs, $.5 million is applicable to Associated's transportation
customers in the state of Missouri and $.6 million is applicable to all
customers in the state of Arkansas. As discussed below, the Missouri Commission
has disallowed recovery of the $.5 million from Associated's Missouri
transportation customers.
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 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. On July 14, 1995,
Associated received an order from the Missouri Commission disallowing the
recovery of approximately $2.0 million of gas costs. The order was the result of
gas cost audits covering the five-year period ending August 31, 1993. Of the
total disallowed, $1.5 million represented a portion of the difference between
the price paid by Associated under its long-term firm contract with SEECO and a
spot market index price for gas delivered into an interstate pipeline operating
in the Arkoma Basin. The balance of $.5 million disallowed represented
take-or-pay charges passed through to Associated by its interstate suppliers and
allocable to transportation customers of Associated, as discussed above. The
APSC had previously reviewed the costs charged to Arkansas ratepayers under this
contract and found them to be proper and allowable for recovery. Associated has
appealed the Missouri Commission's decision to the Circuit Court of Cole County,
Missouri and that court has stayed the Missouri Commission's order and has
directed Associated to pay the money to be refunded under the Missouri
Commission's order into the registry of the court while the appeal is pending.
The Staff of the Missouri Commission has also recommended the disallowance of an
additional $.7 million of gas costs as a result of an audit for the year ended
August, 1994. The Missouri Commission has not yet issued an order in connection
with that recommendation. The Company will continue to defend its pricing
policies and seek recovery of these costs from Associated's customers. The
Company does not expect the ultimate outcome of these matters to have a material
impact on the results of operations or the financial position of the Company.
The gas heating load is one of the most significant uses of natural gas and
is sensitive to outside temperatures. Sales, therefore, vary throughout the
year. Profits, however, have become less sensitive to fluctuations in
temperature 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 approximately
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1% annually. Based on current economic conditions in the Company's service
territories, the Company expects this trend in customer growth to continue. AWG
and Associated pass along to customers through an automatic cost of gas
adjustment clause any increase or decrease experienced in purchased gas costs.
As previously mentioned, the APSC and the Missouri Commission regulate the
Company's utility rates and operations. AWG filed an application with the APSC
on January 30, 1996, for a rate increase of $7.2 million annually. The APSC has
ten months in which to reach a decision on the amount of the rate increase to be
approved. As a result, any increase granted will likely not become effective
until late 1996. The Company anticipates filing a rate increase request for
Associated's operations in late 1996. Rate increase requests which may be filed
in the future will depend on customer growth, increases in operating expenses,
and additional investments in property, plant and equipment. AWG's rates for gas
delivered to its retail customers are not regulated by the FERC, but its
transmission and gathering pipeline systems are subject to the FERC's
regulations concerning open access transportation since AWG accepted a blanket
transportation certificate in connection with its merger with Associated.
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 approximately 141 MMcfd. In 1995, NOARK had an
average daily throughput of 86 MMcfd, compared to 82 MMcfd in 1994, and 79 MMcfd
in 1993. Arkansas Western has contracted for 41 MMcfd of firm capacity on NOARK
under a transportation contract with an original term of ten years. The
remaining term of that contract is seven years and the contract is renewable
year to year until terminated by 180 days notice. NOARK also had 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. In late 1995, the suit was
settled prior to trial. In exchange for a $6.0 million payment to NOARK, the
marketer was released from its obligations under its firm transportation
agreement and its contract with the Company's affiliates. The Company is
currently making its own sales arrangements and transporting production through
NOARK which was previously purchased by the marketer.
NOARK has been operating below capacity and generating losses since it was
placed in service. 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. The increased availability of interruptible transportation service
has intensified the competitive environment within which
8
<PAGE>
NOARK operates. The Company and the other partners of NOARK are currently
investigating several options which would 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 noncapital 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, 1995. 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.
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, 1995, the Company had 667 employees, 88 of whom are
represented under a collective bargaining agreement.
INDUSTRY SEGMENT AND STATISTICAL INFORMATION
The following portions of the 1995 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 page 27 (Note 9
to the financial statements) for information about industry segments and pages
30 and 31 ("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 Registrant's 1995 Annual Report to Shareholders (filed
as Exhibit 13 to this filing) listed below are hereby incorporated by reference
for the purpose of describing its properties.
Refer to the Appendix (filed as part of Exhibit 13 to this filing) for
information concerning areas of operation of the Company's 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 pages 24 through 26 (Notes 5 and 6
to the financial statements) for additional information about the Company's gas
and oil operations. For information concerning capital expenditures, refer to
page 14 ("Capital Expenditures" section of "Management's Discussion and Analysis
of Financial Condition and Results of Operations"). Also refer to page 31
("Financial and Operating Statistics") for information concerning gas and oil
wells drilled and gas and oil produced.
9
<PAGE>
The following information is provided to supplement that presented in the
1995 Annual Report to Shareholders:
NET WELLS DRILLED DURING THE YEAR
Exploratory
Productive
Year Wells Dry Holes Total
---- ---------- --------- -----
1995 . . . . . . . . . 6.3 7.1 13.4
1994 . . . . . . . . . 4.7 1.8 6.5
1993 . . . . . . . . . 2.8 4.0 6.8
Development
Productive
Year Wells Dry Holes Total
---- ---------- --------- -----
1995 . . . . . . . . . 37.5 19.4 56.9
1994 . . . . . . . . . 45.5 14.7 60.2
1993 . . . . . . . . . 37.9 10.5 48.4
WELLS IN PROGRESS AS OF DECEMBER 31, 1995
Type of Well Gross Net
------------ ----- ----
Exploratory........................ 8.0 5.1
Development........................ 9.0 7.3
----- ----
Total.............................. 17.0 12.4
===== ====
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, 1995.
During 1995, 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 1995 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 has been advised of a potential claim against it involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties and related matters. The Company has begun discussions with the
claimant and has engaged special counsel to assist it in a preliminary
investigation of the claim's merits. The Company is unable to predict at this
time whether litigation will be commenced in respect of this claim or how the
claim will ultimately be resolved. While the amount of the potential claim is
significant in the aggregate, management believes, based on its preliminary
investigation, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations.
10
<PAGE>
The Company and its subsidiaries are involved in various other legal
proceedings arising in the ordinary course of business. While the outcome of
lawsuits or other proceedings cannot be predicted with certainty, management
expects these matters will not have a material adverse effect on the
consolidated financial position or results of operations of the Company.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year
ended December 31, 1995, 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
---- ---------------- ---
<S> <C> <C>
Charles E. Scharlau..... Chairman of the Board (since 1979), Southwestern 68
Energy Company and Subsidiaries,
and Chief Executive Officer (since
1968), Southwestern Energy Company.
Dan B. Grubb............ President and Chief Operating Officer (since 1992), 60
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 and Corporate 42
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 Operating Officer 65
(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 Secretary (since 1992), 40
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
11
<PAGE>
Statement dated March 27, 1996, under the section entitled "Security Ownership
of Directors, Nominees, and Executive Officers" and is incorporated herein by
reference.
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Shareholder Information on page 32 and "Common Stock Statistics" included
in the Company's Financial and Operating Statistics on page 30 of the 1995
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, 1995, $103.0
million of retained earnings was available for payment as cash dividends. These
covenants generally limit the payment of dividends in a fiscal year to the total
of net income plus $20.0 million less dividends paid and purchases, redemptions
or retirements of capital stock during the period since January 1, 1990.
The Company paid dividends at an annual rate of $.24 per share in 1995 and
1994. 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 1995 Annual Report to Shareholders (filed as
Exhibit 13 to this filing) are hereby incorporated by reference.
Refer to page 30 ("Financial and Operating Statistics") for selected
financial data of the Company.
Refer to the text on pages 10 through 15 for "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
Refer to pages 17 through 29 for financial statements and supplementary
data.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no changes in or disagreements with accountants on
accounting and financial disclosure.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The definitive Proxy Statement to holders of the Company's Common Stock in
connection with the solicitation of proxies to be used in voting at the Annual
Meeting of Shareholders on May 13, 1996 (the 1996 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.
12
<PAGE>
Item 11. EXECUTIVE COMPENSATION
The 1996 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 1996 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 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 1996 Proxy Statement is hereby incorporated by reference for the
purpose of providing information about related transactions. Refer to the
section "Security Ownership of Directors, Nominees, and Executive Officers" for
information about transactions with members of the Company's Board of Directors.
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a)(1) The following consolidated financial statements of the Company and
its subsidiaries, included on pages 17 through 29 of its 1995 Annual Report to
Shareholders (filed as Exhibit 13 to this filing) and the report of independent
auditors on page 16 of such report are hereby incorporated by reference:
Report of Independent Auditors.
Consolidated Balance Sheets as of December 31, 1995 and 1994.
Consolidated Statements of Income for the years ended December 31,
1995, 1994, and 1993.
Consolidated Statements of Cash Flows for the years ended December
31, 1995, 1994, and 1993.
Consolidated Statements of Retained Earnings for the years ended
December 31, 1995, 1994, and 1993.
Notes to Consolidated Financial Statements, December 31, 1995, 1994,
and 1993.
(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 December 21, 1995,
referencing the opinions of Cleary, Gottlieb, Steen and Hamilton and
Jeffrey L. Dangeau, as to the validity of the Company's 6.70% Senior
Notes due 2005, issued on December 5, 1995.
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 25, 1996 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 25, 1996.
/s/ CHARLES E. SCHARLAU Director, Chairman, and
- --------------------------- Chief Executive Officer
Charles E. Scharlau
/s/ STANLEY D. GREEN Executive Vice President -
- --------------------------- Finance and Corporate Development,
Stanley D. Green and Chief Financial Officer
/s/ GREGORY D. KERLEY Vice President - Treasurer
- --------------------------- and Secretary, and
Gregory D. Kerley Chief Accounting Officer
/s/ JOHN PAUL HAMMERSCHMIDT Director
- ---------------------------
John Paul Hammerschmidt
/s/ ROBERT L. HOWARD Director
- ---------------------------
Robert L. Howard
/s/ KENNETH R. MOURTON Director
- ---------------------------
Kenneth R. Mourton
/s/ CHARLES E. SANDERS Director
- ---------------------------
Charles E. Sanders
Supplemental Information to be Furnished With Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered Securities
Pursuant to Section 12 of the Act.
Not Applicable
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 (amended Bylaws of the Company incorporated by
reference to Exhibit 3 to Annual Report on Form 10-K for the year ended
December 31, 1994).
4.1 Shareholder Rights Agreement, dated May 5, 1989 (incorporated by
reference to Exhibit 1 filed with the Company's Form 8-K on May 10,
1989).
4.2 Prospectus, Registration Statement, and Indenture on 6.70% Senior Notes
due December 1, 2005 and issued December 5, 1995 (incorporated by
reference to the Company's Forms S-3 and S-3/A filed on November 1,
1995, and November 17, 1995, respectively, and also to the Company's
filings of a Prospectus and Prospectus Supplement on November 22, 1995,
and December 4, 1995, respectively).
MATERIAL CONTRACTS:
10.1 Gas Purchase Contract between SEECO, Inc., and Arkansas Western Gas
Company, dated July 24, 1978, as amended May 21, 1979, and Amended and
Restated as of July 1, 1994 (incorporated by reference to Exhibit 10.1
to Annual Report on Form 10-K for the year ended December 31, 1994).
10.2 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).
15
<PAGE>
Exhibit
No. Description
- ------- -----------
(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).
(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, and as
further amended February 1, 1996 (amended and restated plan incorporated
by reference to Exhibit 10.5 to Annual Report on Form 10-K for the year
ended December 31, 1993; amendment dated February 1, 1996, filed
herewith).
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 Southwestern Energy Company Nonqualified Retirement Plan, effective
October 4, 1995 (filed herewith).
10.8 Split-Dollar Life Insurance agreement for Stanley D. Green, effective
February 1, 1996 (filed herewith).
10.9 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).
10.10 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).
10.11 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).
10.12 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).
10.13 Executive Severance Agreement for Gregory D. Kerley, effective December
14, 1994 (incorporated by reference to Exhibit 10.11 to Annual Report on
Form 10-K for the year ended December 31, 1994).
16
<PAGE>
Exhibit
No. Description
- ------- -----------
10.14 Employment Agreement for Charles E. Scharlau, dated December 18, 1990,
effective January 1, 1991, as amended December 7, 1994 (original
agreement incorporated by reference to Exhibit 10 to Annual Report on
Form 10-K for the year ended December 31, 1990; amended agreement
incorporated by reference to Exhibit 10.12 to Annual Report on Form 10-K
for the year ended December 31, 1994).
10.15 Employment Agreement for 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).
10.16 Form of Indemnity Agreement, between the Company and each officer and
director of the Company (Incorporated by reference to Exhibit 10.20 to
Annual Report on Form 10-K for the year ended December 31, 1991).
10.17 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. 1995 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
AMENDMENT NUMBER 1
TO THE
SOUTHWESTERN ENERGY COMPANY
SUPPLEMENTAL RETIREMENT PLAN
WHEREAS, the Southwestern Energy Company (the "Company") maintains the
Southwestern Energy Company Supplemental Retirement Plan (the "SERP"); and
WHEREAS, it is desirable to amend the SERP to provide an offset to benefits
payable to a participant or a participant's beneficiary under the SERP for any
benefits provided under any split-dollar life insurance agreement between such
participant and the Company and to change the timing of the benefit payments
under the SERP.
NOW, THEREFORE, effective February 1, 1996, the SERP is amended as follows:
ARTICLE III
UNFUNDED BENEFITS
1. Section B.1 is amended in its entirety to read as follows:
"The Actuarial Equivalent of a Participant's or
Beneficiary's Unfunded Benefit under the Plan shall be paid to
the Participant or Beneficiary in a single lump sum on the
later of (a) the first day of the month following the one-year
anniversary of the Participant's termination of employment
with the Company or (b) the date that benefit payments under
the Pension Plan to such Participant or Beneficiary commence;
provided, however, that a Participant may elect that the
Actuarial Equivalent of his (or, in the event of the
Participant's death, his Beneficiary's) Unfunded Benefit under
the Plan be paid in the form of an annuity, beginning at the
same time and in the same form as the Participant's or
Beneficiary's benefit under the Pension Plan is paid, by
filing a written election with the Committee, on a form
provided by the Committee, at least one year before such
Participant's termination of employment with the Company. No
election or revocation of an election shall be effective if it
is received by the Committee less than one year prior to the
Participant's termination of employment."
1
<PAGE>
2. A new Section D is added to read as follows:
"D. Offset for Certain Benefits Payable Under Split-Dollar
Life Insurance Agreements.
1. Offset Value.
Some of the Participants under this Plan own life
insurance policies (the "Policies") purchased on their behalf
by the Corporation. The exercise of ownership rights under
these Policies by each Participant is, however, subject to
certain conditions (set forth in a "Split-Dollar Insurance
Agreement" between the Participant and the Corporation,
pursuant to which the Corporation holds a security interest on
the Policy) and, if the Participant fails to meet the
conditions set forth in the Split-Dollar Life Insurance
Agreement, the Corporation may exercise its security interest
in the Policy and cause the Participant to lose certain
benefits under the Policy. In the event that a Participant
satisfies the condition specified in Section 4 or 5 of the
Split-Dollar Life Insurance Agreement, so that the Participant
or his or her beneficiary becomes entitled to exercise rights
free from the Corporation's security interest under one of
those sections, or the Corporation's security interest is
otherwise released, the value of those benefits shall
constitute an offset to the Participant's Unfunded Benefits
otherwise payable under this Plan. As the case may be, this
offset (the "Offset Value") shall be equal to the cash
surrender value of the Policy at the time the Participant
becomes entitled to exercise rights free from the Company's
security interest, or in the case of the Participant's death,
the death benefits payable to the beneficiary under the
Policy. The Actuarial Equivalent of the Offset Value shall be
compared to the Actuarial Equivalent of the Unfunded Benefits
payable under this Plan (the "Plan Value"), and the Plan Value
shall be reduced by the Actuarial Equivalent of the Offset
Value at the time and in the manner described in Section D.2
or Section D.3 of this Article III.
2. Manner and Calculation of Payment.
If, at the time the Participant terminates
employment, the Plan Value exceeds the Actuarial Equivalent of
the Offset Value, the excess of the Plan Value over the
Actuarial Equivalent of the Offset Value shall be paid to the
Participant or Beneficiary at the time and in the manner
provided under Section B.1 of this Article III; provided,
however, that if such excess is less than $10,000, such excess
shall be paid immediately to the Participant or Beneficiary in
a cash lump sum. For this purpose, the Plan Value shall be
calculated by assuming that the Participant or Beneficiary
receives or commences receiving benefits under this Plan and
the Pension Plan on the earliest date that such benefits
become payable.
2
<PAGE>
3. Payment of Certain Benefits.
If the policy described in Section D.1 of this
Article III insures the life of an individual other than the
Participant (the "Insured party"), and if such Insured Party
dies prior to the Participant's becoming eligible for benefits
under the Plan, and if the Participant or Beneficiary
subsequently becomes eligible for benefits hereunder, the Plan
Value (as defined in Section D.1 of this Article III) shall
then be offset by the Actuarial Equivalent of the amount equal
to the death benefit previously paid to the Participant or the
Participant's beneficiary pursuant to the Split-Dollar Life
Insurance Agreement divided by the Tax Adjustment Factor (as
defined below). Any remaining Plan Value shall thereupon be
paid to the Participant or Beneficiary in a cash lump sum.
4. Tax Adjustment Factor.
For purposes of this Section D of Article III, Tax
Adjustment Factor shall mean a number, determined by the
Committee, which is equal to one minus the sum of (a) the
highest marginal federal personal income tax rate then in
effect and (b) the effective highest marginal state income tax
rate in the state in which the Participant resides, net after
the effect of the deduction for such state income tax for
federal income tax purposes."
IN WITNESS WHEREOF, the Company has caused this instrument to be executed
by its duly authorized officers this 1st day of February, 1996.
SOUTHWESTERN ENERGY COMPANY
By __________________________
Its__________________________
3
SOUTHWESTERN ENERGY COMPANY
NONQUALIFIED RETIREMENT PLAN
PLAN DOCUMENT
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TABLE OF CONTENTS
<TABLE>
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Page
<S> <C> <C>
ARTICLE I PURPOSE OF PLAN.................................. 1
1.1 Purpose of Plan.................................. 1
ARTICLE II DEFINITIONS...................................... 1
2.1 Account.......................................... 1
2.2 Basic Plan....................................... 1
2.3 Beneficiary...................................... 1
2.4 Board............................................ 1
2.5 Code............................................. 1
2.6 Committee........................................ 1
2.7 Company.......................................... 1
2.8 Company Contribution............................. 2
2.9 Compensation..................................... 2
2.10 Deferral Contribution............................ 2
2.11 Effective Date................................... 2
2.12 Eligible Employee................................ 2
2.13 Entry Date....................................... 2
2.14 Matching Contribution............................ 2
2.15 Nonqualified Deferral Contribution .............. 2
2.16 Nonqualified Matching Contribution .............. 2
2.17 Participant ..................................... 2
2.18 Participant Enrollment and Election Form......... 3
2.19 Plan............................................. 3
2.20 Plan Year........................................ 3
2.21 Transfer Date.................................... 3
2.22 Trust............................................ 3
2.23 Trustee.......................................... 3
2.24 Valuation Date................................... 3
ARTICLE III ELIGIBILITY AND PARTICIPATION.................... 3
3.1 Requirements..................................... 3
3.2 Re-employment.................................... 3
3.3 Change of Employment Category.................... 3
ARTICLE IV NONQUALIFIED DEFERRAL CONTRIBUTIONS.............. 4
4.1 Nonqualified Deferral Elections.................. 4
4.2 Payroll Deductions............................... 4
4.3 Timing of Contribution........................... 4
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Page
ARTICLE V NONQUALIFIED MATCHING CONTRIBUTIONS.............. 4
5.1 Nonqualified Matching Percentage................. 4
5.2 Timing of Match.................................. 4
ARTICLE VI COMPANY CONTRIBUTION............................. 4
6.1 Company Contribution............................. 4
6.2 Timing of Contribution........................... 5
ARTICLE VII PLAN ACCOUNTS.................................... 5
7.1 Establishment of Accounts........................ 5
7.2 Nonqualified Deferral Account.................... 5
7.3 Nonqualified Matching Account.................... 5
7.4 Company Contribution Account..................... 5
7.5 Allocation of Income............................. 5
ARTICLE VIII TRANSFERS TO BASIC PLAN.......................... 5
8.1 In General....................................... 5
8.2 Nonqualified Deferral Account Transfers.......... 5
8.3 Nonqualified Matching Account Transfers.......... 6
8.4 Frequency of Transfers........................... 6
8.5 Restriction...................................... 6
8.6 Employee Election................................ 6
ARTICLE IX ALLOCATION OF FUNDS.............................. 6
9.1 Allocation of Earnings or Losses on Accounts..... 6
9.2 Accounting for Distributions..................... 6
9.3 Interim Valuations............................... 6
ARTICLE X VESTING.......................................... 7
10.1 Nonqualified Deferral Contributions.............. 7
10.2 Nonqualified Matching Contributions.............. 7
10.3 Company Contributions............................ 7
ARTICLE XI PAYMENTS OF BENEFITS............................. 7
11.1 Payments of Benefits............................. 7
11.2 Payments Upon Hardship........................... 7
11.3 Payments Upon Change in Control.................. 8
ARTICLE XII COMMITTEE ADMINISTRATION......................... 8
12.1 Committee........................................ 8
ARTICLE XIII THE TRUST........................................ 9
13.1 Establishment of Trust........................... 9
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Page
ARTICLE XIV ADMINISTRATION................................... 9
14.1 Administrative Authority......................... 9
14.2 Mutual Exclusion of Responsibility............... 10
14.3 Uniformity of Discretionary Acts................. 10
14.4 Litigation....................................... 10
14.5 Payment of Administration Expenses............... 10
14.6 Claims Procedure................................. 10
14.7 Liability of Committee, Indemnification.......... 11
14.8 Expenses......................................... 12
14.9 Taxes............................................ 12
14.10 Attorney's Fees.................................. 12
</TABLE>
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ARTICLE I - PURPOSE OF PLAN
1.1 PURPOSE OF PLAN. The Company intends and desires by the adoption of this
Plan to recognize the value to the Company of the past and present services of
Eligible Employees covered by the Plan and to encourage and assure their
continued service with the Company by making more adequate provisions for their
future retirement security.
This Plan has been adopted to provide certain select management and highly
compensated employees of Southwestern Energy Company covered under the
Southwestern Energy Company 401(k) Savings Plan (the "Basic Plan") the
opportunity to accumulate deferred compensation which cannot be accumulated
under the Basic Plan because of the limitations on deferrals under Code Section
402(g) (the "Deferral Limit"), the limitations on annual additions under Code
Section 415 (the "415 Limit"), the limitations on tax-qualified pension plan
benefits under Code Section 401(a)(17) (the "Pay Cap"), and because Deferral
Contributions and Matching Contributions have been required to be returned under
the Basic Plan because of the nondiscrimination rules under Code Sections
401(k)(3) ("ADP Restrictions") or 401(m)(2) ("ACP Restrictions").
This Plan is intended to be "a plan which is unfunded and maintained by an
employer primarily for the purpose of providing deferred compensation for a
select group of management or highly compensated employees" within the meaning
of Sections 201(2) and 301(a)(3) of the Employee Retirement Income Security Act
of 1974 ("ERISA") and shall be interpreted and administered in a manner
consistent with that intent.
ARTICLE II - DEFINITIONS
2.1 ACCOUNT means those separate accounts established and maintained under the
Plan in the name of each Participant as required pursuant to the provisions of
Article VII.
2.2 BASIC PLAN means the Southwestern Energy Company 401(k) Savings Plan.
2.3 BENEFICIARY means a Participant's beneficiary or beneficiaries identified on
the Participant Enrollment and Election Form.
2.4 BOARD means the Board of Directors of Southwestern Energy Company.
2.5 CODE means the Internal Revenue Code of 1986 and the regulations thereunder,
as amended from time to time.
2.6 COMMITTEE means the Retirement Committee appointed by the Board.
2.7 COMPANY means Southwestern Energy Company or any company which is a
successor as a result of merger, consolidation, liquidation, transfer of assets,
or other reorganization.
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2.8 COMPANY CONTRIBUTION means an amount contributed by the Company pursuant to
the provisions of Article VI.
2.9 COMPENSATION means base salary or wages, plus overtime, bonuses,
commissions, etc., which is paid the employee by the Company for the performance
of duties during the Plan Year.
2.10 DEFERRAL CONTRIBUTION means those contributions by the Company to the Basic
Plan for a Plan Year on behalf of and on account of the qualified cash or
deferral elections within the meaning of Code Section 401(k) made by the
participants in the Basic Plan.
2.11 EFFECTIVE DATE means the date on which the Company adopts the Plan.
2.12 ELIGIBLE EMPLOYEE means, for any Plan Year (or applicable portion thereof),
a person employed by the Company who is determined by the Committee to be a
member of a select group of management or highly compensated employees, who is
designated by the Committee to be eligible under the Plan, and who is a
participant in the Basic Plan. By fifteen days prior to the beginning of a Plan
Year, the Company shall notify those individuals, if any, who will be Eligible
Employees for the next Plan Year. If the Company determines that an employee
first becomes an Eligible Employee during a Plan Year, the Company shall notify
such employee of its determination and of the date during the Plan Year on which
the employee shall first become an Eligible Employee.
2.13 ENTRY DATE means the "Entry Date" as that term is defined in the Basic
Plan.
2.14 MATCHING CONTRIBUTION means those contributions by the Company to the Basic
Plan for a Plan Year on account of the Deferral Contributions made during that
Plan Year by the participants in the Basic Plan.
2.15 NONQUALIFIED DEFERRAL CONTRIBUTION means Compensation that is due to be
earned and which would otherwise be paid to the Participant, which the
Participant elects to defer under the Plan, determined without regard to the
Deferral Limit, the 415 Limit, the Pay Cap or the ADP Restrictions under the
Basic Plan, and which is contributed on behalf of each Participant by the
Company pursuant to the provisions of Article IV.
2.16 NONQUALIFIED MATCHING CONTRIBUTION means an amount contributed by the
Company on account of the Participant's Nonqualified Deferral Contribution,
pursuant to the provisions of Article V.
2.17 PARTICIPANT means any person so designated in accordance with the
provisions of Article III, including, where appropriate according to the context
of the Plan, any former employee who is or may become (or whose Beneficiaries
may become) eligible to receive a benefit under the Plan.
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2.18 PARTICIPANT ENROLLMENT AND ELECTION FORM means the form on which a
Participant elects to defer Compensation hereunder and on which the Participant
makes certain other designations as required thereon.
2.19 PLAN means this Southwestern Energy Company Non-Qualified Retirement Plan.
2.20 PLAN YEAR means the "Plan Year" as that term is defined in the Basic Plan.
2.21 TRANSFER DATE means the date on which amounts credited to each
Participant's Account for the Plan Year are transferred to the Basic Plan.
2.22 TRUST means the trust fund established pursuant to the Plan.
2.23 TRUSTEE means the trustee named in the agreement establishing the Trust and
such successor and/or additional trustees as may be named pursuant to the terms
of the agreement establishing the Trust.
2.24 VALUATION DATE means the last day of each Plan Year and any other date that
the Company, in its sole discretion, designates as a Valuation Date.
ARTICLE III - ELIGIBILITY AND PARTICIPATION
3.1 REQUIREMENTS. Every Eligible Employee as of the Effective Date shall be
eligible to become a Participant on the Effective Date. Every other Eligible
Employee shall be eligible to become a Participant on the first Entry Date
occurring on or after the date on which he or she becomes an Eligible Employee.
No individual shall become a Participant, however, if he or she is not an
Eligible Employee on the date his or her participation is to begin.
Participation in the Plan is voluntary. In order to participate, an otherwise
Eligible Employee must execute a valid Participant Enrollment and Election Form
in such manner as the Company may require and must agree to make Nonqualified
Deferral Contributions as provided in Article IV.
3.2 RE-EMPLOYMENT. If a Participant whose employment with the Company is
terminated is subsequently re-employed, he or she shall become a Participant in
the Plan in accordance with the provisions of Section 3.1 of this Article.
3.3 CHANGE OF EMPLOYMENT CATEGORY. During any period in which a Participant
remains in the employ of the Company, but either ceases to be an Eligible
Employee or a participant in the Basic Plan, he or she shall not be eligible to
make additional Nonqualified Deferral Contributions under this Plan.
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ARTICLE IV - NONQUALIFIED DEFERRAL CONTRIBUTIONS
4.1 NONQUALIFIED DEFERRAL ELECTIONS. In accordance with rules established by the
Company, a Participant may elect to make a Nonqualified Deferral Contribution
with respect to a Plan Year by use of a Participant Enrollment and Election Form
at the same time and in the same manner as the Participant would elect to have a
Deferral Contribution made on his or her behalf under the Basic Plan. In
addition, a participant in the Basic Plan who becomes a Participant during the
Plan Year may elect to make a Nonqualified Deferral Contribution with respect to
the remaining portion of the Plan Year by use of a Participant Enrollment and
Election Form at the same time and in the same manner as if the Participant had
become eligible to elect to have a Deferral Contribution made on his or her
behalf under the Basic Plan.
4.2 PAYROLL DEDUCTIONS. Nonqualified Deferral Contributions shall be made
through payroll deductions. The Participant may change the amount of his or her
Nonqualified Deferral Contribution amount by delivering to the Company at least
fifteen days prior to the beginning of any quarter a new Participant Enrollment
and Election Form, at the same time and in the same manner required for changes
to a Deferral Contribution under the Basic Plan, with such change being first
effective for Compensation to be earned in the first payroll period of the
quarter. Once made, a Nonqualified Deferral Contribution payroll deduction
election shall continue in force indefinitely, until changed by the Participant
on a subsequent Participant Enrollment and Election Form delivered to the
Company.
4.3 TIMING OF CONTRIBUTION. Nonqualified Deferral Contributions shall be made at
the same time and in the same manner as Deferral Contributions.
ARTICLE V - NONQUALIFIED MATCHING CONTRIBUTIONS
5.1 NONQUALIFIED MATCHING PERCENTAGE. The Company shall make a Nonqualified
Matching Contribution on behalf of a Participant, and on account of the
Participant's Nonqualified Deferral Contributions for a Plan Year, at the same
rate as the Matching Contribution for the Plan Year. Nonqualified Matching
Contributions will be made only to the extent they do not exceed three (3)
percent of the Participant's base salary and wages, excluding overtime, bonuses
and commissions for the Plan Year.
5.2 TIMING OF MATCH. Nonqualified Matching Contributions shall be made at the
same time and in the same manner as Matching Contributions.
ARTICLE VI - COMPANY CONTRIBUTIONS
6.1 COMPANY CONTRIBUTION. In its sole discretion, the Company may make a Company
Contribution on behalf of Participant, in addition to any Nonqualified Matching
Contributions, in an amount determined by the Company in accordance with (a)
and/or (b) below:
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(a)A percentage of each Participant's Compensation for the Plan Year;
(b)A percentage of some or all of the Participant's Nonqualified
Deferral Contribution for the Plan Year.
6.2 TIMING OF CONTRIBUTION. Company Contributions shall be made as soon as
administratively feasible after declared by the Board.
ARTICLE VII - PLAN ACCOUNTS
7.1 ESTABLISHMENT OF ACCOUNTS. There shall be established and maintained by the
Company separate Accounts in the name of each Participant, as required and as
described in this Article VII.
7.2 NONQUALIFIED DEFERRAL ACCOUNT. The Company shall establish an Account to
which are credited a Participant's Nonqualified Deferral Contributions, plus
amounts equal to any income, gains, or losses (to the extent realized, based
upon fair market value of the Account's assets) attributable or allocable to the
Participant's Account.
7.3 NONQUALIFIED MATCHING ACCOUNT. The Company shall establish an Account to
which are credited a Participant's Nonqualified Matching Contributions, plus
amounts equal to any income, gains, or losses (to the extent realized, based
upon fair market value of the Account's assets) attributable or allocable to the
Participant's Account.
7.4 COMPANY CONTRIBUTION ACCOUNT. The Company shall establish an Account to
which are credited a Participant's Company Contributions, plus amounts equal to
any income, gains, or losses (to the extent realized, based upon fair market
value of the Account's assets) attributable or allocable to the Participant's
Account.
7.5 ALLOCATION OF INCOME. The Company shall have the discretion to allocate such
income, gains, or losses among Accounts pursuant to such allocation rules as the
Company deems to be reasonable and administratively practicable.
ARTICLE VIII-- TRANSFERS TO BASIC PLAN
8.1 IN GENERAL. A transfer made pursuant to this Article shall not constitute a
Payment of Benefits, as that phrase is referenced in Article XI.
8.2 NONQUALIFIED DEFERRAL ACCOUNT TRANSFERS. As soon as administratively
feasible after the end of a Plan Year, but in no event later than 90 days
following the end of that Plan Year, the Company shall transfer to the Basic
Plan all the Nonqualified Deferral Contributions credited to each Participant's
Nonqualified Deferral Account for that Plan Year,
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but in no event shall an amount be transferred that would cause the Basic Plan
to be negatively impacted by the existing ADP Restrictions for such Plan Year.
8.3 NONQUALIFIED MATCHING ACCOUNT TRANSFERS. As soon as administratively
feasible after the end of a Plan Year, but in no event later than 90 days
following the end of that Plan Year, the Company shall transfer to the Basic
Plan all the Nonqualified Matching Contributions credited to each Participant's
Nonqualified Matching Account for that Plan Year, but in no event shall an
amount be transferred that would cause the Basic Plan to be negatively impacted
by the existing ACP Restrictions for such Plan Year.
8.4 FREQUENCY OF TRANSFERS. In its sole discretion, the Company may make
multiple transfers under Sections 8.2 and 8.3 during the Plan Year.
8.5 RESTRICTION. No transfer shall occur under Sections 8.2 or 8.3 unless the
terms of the Basic Plan specifically provide that such transfers will be
accepted.
8.6 EMPLOYEE ELECTION. An Eligible Employee may make an election prior to the
end of the Plan Year to not make the transfers under Sections 8.2 and 8.3. This
election can be for all or a portion of the transfers.
ARTICLE IX - ALLOCATION OF FUNDS
9.1 ALLOCATION OF EARNINGS OR LOSSES ON ACCOUNTS. Each Participant's Account
shall be invested in such investments as the Trustee shall determine. The
Trustee may (but is not required to) consider the Participant's investment
preferences when investing amounts credited to the Participant's Accounts. Such
investment preferences shall be related to the Trustee at the time and in the
manner prescribed by the Company, in its sole discretion. The Participant's
Accounts will be credited or debited with the increase or decrease in the
realizable net asset value or credited interest, as applicable, of each
investment, as follows. As of each Valuation Date, an amount equal to the net
increase or decrease in realizable net asset value or credited interest, as
applicable (as determined by the Trustee), of each investment option within the
Trust since the preceding Valuation Date shall be allocated among all
Participants' Accounts to be invested in that investment option in accordance
with the ratio which the portion of the Account of each Participant which is to
be invested within that investment option, determined as provided herein, bears
to the aggregate of all amounts to be invested within that investment option.
9.2 ACCOUNTING FOR DISTRIBUTIONS. As of the date of any distribution under the
Plan to a Participant or his or her Beneficiary or Beneficiaries, such
distribution shall be charged to the applicable Participant's Account.
9.3 INTERIM VALUATIONS. If it is determined by the Company that the value of the
Trust as of any date on which distributions are to be made differs materially
from the value of the Trust on the prior Valuation Date upon which the
distribution is to be based, the Company, in its
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discretion, shall have the right to designate any date in the interim as a
Valuation Date for the purpose of revaluing the Trust so that the Account from
which the distribution is being made will, prior to the distribution, reflect
its share of such material difference in value.
ARTICLE X - VESTING
10.1 NONQUALIFIED DEFERRAL CONTRIBUTIONS. A Participant shall always be one
hundred percent (100%) vested in amounts credited to his or her Nonqualified
Deferral Account.
10.2 NONQUALIFIED MATCHING CONTRIBUTIONS. A Participant shall always have the
same vesting percentage in his or her Nonqualified Matching Account as he or she
has in his or her Matching Contribution account under the Basic Plan. However,
in the event of a Change in Control, as defined in Section 11.3, a Participant
shall become 100% vested in his or her Nonqualified Matching Account if the
Participant's employment terminates with the Company during the two year period
prior to or following the Change in Control.
10.3 COMPANY CONTRIBUTIONS. A Participant 's Company Contribution Account will
be subject to the same vesting schedule and forfeiture provisions as his or her
Matching Contribution Account under the Basic Plan. However, in the event of a
Change in Control, as defined in Section 11.3, a Participant shall become 100%
vested in his or her Company Contribution Account if the Participant's
employment terminates with the Company during the two year period prior to or
following the Change in Control.
ARTICLE XI - PAYMENTS OF BENEFITS
11.1 PAYMENTS OF BENEFITS. The benefit payable under this Plan on account of a
Participant's termination of employment, retirement, disability, hardship, or
death shall be distributed in a cash lump sum as soon as practicable and no
later than sixty (60) days after the earlier of such termination of employment,
retirement, incurrence of disability (as determined by the Committee), hardship,
or death. Any death benefit payable under the Plan shall be payable to the
Participant's Beneficiary. In the event of a Change in Control, as defined in
Section 11.3, any additional benefit pursuant to an increase in vesting as
described in Section 10.2 and 10.3 under the Plan shall be distributed in a cash
lump sum as soon as practicable and no later than sixty (60) days after the
Change in Control.
11.2 PAYMENTS UPON HARDSHIP. In the event of a hardship of the Participant, the
Participant may apply to the Company for the distribution of all or any part of
his or her Accounts in the same manner, and under the same terms and conditions,
as under the Basic Plan. Upon a finding of hardship under the Basic Plan, the
Company shall instruct the Trustee to make the appropriate distribution to the
Participant from amounts contributed to the Trust by the Company in respect of
the Participant's Accounts. In no event shall the aggregate amount of the
distribution exceed the value of the Participant's Accounts. For purposes of
this Section, the
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value of the Participant's Accounts shall be determined as of the date of the
distribution. A distribution may be made under this Section only with the
consent of the Company's Committee.
11.3 PAYMENTS UPON CHANGE IN CONTROL. Notwithstanding any other provision of
this Plan, a Participant's Account shall be distributed to the Participant in a
cash lump-sum within sixty (60) days after a Change in Control. For purposes of
this Section, a "Change in Control" shall mean the occurrence of any of the
following:
(i) any "person" (as such term is used in Sections 13(d) and
14(d) of the Exchange Act, an "Acquiring Person") becomes the
"beneficial owner" (as such term is defined in Rule 13d-3 promulgated
under the Exchange Act), directly or indirectly, of securities of the
Company representing 20% or more of the combined voting power of the
Company's then outstanding securities, excluding any employee benefit
plan sponsored or maintained by the Company (or any trustee of such
plan acting as trustee);
(ii) 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);
(iii) 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;
(iv) 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
(v) 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.
ARTICLE XII - COMMITTEE ADMINISTRATION
12.1 COMMITTEE. The Committee shall administer, construe, and interpret this
Plan and shall determine, subject to the provisions of this Plan in a manner
consistent with the administration of the Basic Plan, the Eligible Employees who
become Participants in the Plan from time to time and the amount, if any, due a
Participant (or his or her Beneficiary) under this Plan. No member of the
Committee shall be liable for any act done or determination made in good faith.
No member of the Committee who is a Participant in this Plan may vote on matters
affecting his or her personal benefit under this Plan, but any such member shall
otherwise be fully entitled to act in matters arising out of or affecting this
Plan notwithstanding his or her participation herein. In carrying out its duties
herein, the Committee shall have discretionary authority to exercise all powers
and to make all determinations, consistent with the terms of the Plan, in all
matters
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entrusted to it, and its determinations shall be given deference and shall be
final and binding on all interested parties. In the event of a Change in
Control, as defined in Section 11.3, all investment powers of the Committee
shall be terminated and such investment powers shall be transferred to the
Trustee. Such investment powers will then be exercisable at the sole discretion
of the Trustee, subject to the terms of the Trust.
ARTICLE XIII--THE TRUST
13.1 ESTABLISHMENT OF TRUST. The Company shall establish the Trust with the
Trustee, pursuant to such terms and conditions as are set forth in the Trust
agreement to be entered into between the Company and the Trustee. The Trust is
intended to be treated as a "grantor" trust under the Code, and the
establishment of the Trust is not intended to cause Participants to realize
current income on amounts contributed thereto, and the Trust shall be so
interpreted.
ARTICLE XIV--ADMINISTRATION
14.1 ADMINISTRATIVE AUTHORITY. Except as otherwise specifically provided herein,
the Company shall have the sole responsibility for and the sole control of the
operation and administration of the Plan, and shall have the power and authority
to take all actions including the right to amend or terminate the Plan, and to
make all decisions and interpretations which may be necessary or appropriate in
order to administer and operate the Plan, including, without limiting the
generality of the foregoing, the power, duty, and responsibility to:
(a) Resolve and determine all disputes or questions arising under the Plan,
including the power to determine the rights of Eligible Employees,
Participants, and Beneficiaries, and their respective benefits, and to
remedy any ambiguities, inconsistencies, or omissions in the Plan.
(b) Adopt such rules of procedure and regulations as in its opinion may be
necessary for the proper and efficient administration of the Plan and as
are consistent with the Plan.
(c) Implement the Plan in accordance with its terms and the rules and
regulations adopted as above.
(d) Make determinations with respect to the eligibility of any Eligible
Employee as a Participant and make determinations concerning the
crediting and distribution of Plan Accounts.
(e) Appoint any persons or firms, or otherwise act to secure specialized
advice or assistance, as it deems necessary or desirable in connection
with the administration and operation of the Plan, and the Company shall
be entitled to rely conclusively upon, and shall be fully protected in
any action or omission taken by it in good faith reliance upon the advice
or opinion of such firms or persons. The Company shall have the power and
authority to
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delegate from time to time by written instrument all or any part of its
duties, powers, or responsibilities under the Plan, both ministerial and
discretionary, as it deems appropriate, to any person or committee, and
in the same manner to revoke any such delegation of duties, powers, or
responsibilities. Any action of such person or committee in the exercise
of such delegated duties, powers, or responsibilities shall have the same
force and effect for all purposes hereunder as if such action had been
taken by the Company. Further, the Company may authorize one or more
persons to execute any certificate or document on behalf of the Company,
in which event any person notified by the Company of such authorization
shall be entitled to accept and; conclusively rely upon any such
certificate or document executed by such person as representing action by
the Company until such third person shall have been notified of the
revocation of such authority. In the event of a Change in Control, as
defined in Section 11.3, the Company must notify the Participants prior
to terminating the Trustee pursuant to this Section 14.1(e).
14.2 MUTUAL EXCLUSION OF RESPONSIBILITY. Neither the Trustee nor the Company
shall be obliged to inquire into or be responsible for any act or failure to
act, or the authority therefor, on the part of the other.
14.3 UNIFORMITY OF DISCRETIONARY ACTS. Whenever in the administration or
operation of the Plan discretionary actions by the Company are required or
permitted, such actions shall be consistently and uniformly applied to all
persons similarly situated, and no such action shall be taken which shall
discriminate in favor of any particular person or group of persons.
14.4 LITIGATION. Except as may be otherwise required by law, in any action or
judicial proceeding affecting the Plan, no Participant or Beneficiary shall be
entitled to any notice or service of process, and any final judgment entered in
such action shall be binding on all persons interested in, or claiming under,
the Plan.
14.5 PAYMENT OF ADMINISTRATION EXPENSES. All expenses incurred in the
administration and operation of the Plan and the Trust, including any taxes
payable by the Company in respect of the Plan or Trust or payable by or from the
Trust pursuant to its terms, shall be paid by the Company.
14.6 CLAIMS PROCEDURE.
(a) Notice of Claim. Any Eligible Employee or beneficiary, or the duly
authorized representative of an Eligible Employee or beneficiary, may
file with the Committee a claim for a Plan benefit. Such a claim must
be in writing on a form provided by the Committee and must be
delivered to the Committee, in person or by mail, postage prepaid.
Within ninety (90) days after the receipt of such a claim, the
Committee shall send to the claimant, by mail, postage prepaid, a
notice of the granting or the denying, in whole or in part, of such
claim, unless special circumstances require an extension of time for
processing the claim. In no event may the extension exceed ninety
(90) days from the end of the initial period. If such an extension is
necessary, the claimant will
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be given a written notice to this effect prior to the expiration of
the initial ninety (90) day period. The Committee shall have full
discretion to deny or grant a claim in whole or in part in accordance
with the terms of the plan. If notice of the denial of a claim is not
furnished in accordance with this Section, the claim shall be denied
and the claimant shall be permitted to exercise his or her right to
review pursuant to Sections 14.6(c) and 14.6(d) of the Plan, as
applicable.
(b) Action on Claim. The Committee shall provide to every claimant who is
denied a claim for benefits a written notice setting forth, in a
manner calculated to be understood by the claimant:
(i) The specific reason or reasons for the denial;
(ii) A specific reference to the pertinent Plan provisions on which
the denial is based;
(iii) A description of any additional material or information
necessary of the claimant to perfect the claim and an
explanation of why such material or information is necessary;
and
(iv) An explanation of the Plan's claim review procedure.
(c) Review of Denial. Within sixty (60) days after the receipt by a
claimant of written notification of the denial (in whole or in part)
of a claim, the claimant or the claimant's duly authorized
representative, upon written application to the Committee, delivered
in person or by certified mail, postage prepaid, may review pertinent
documents and may submit to the Committee, in writing, issues and
comments concerning the claim.
(d) Decision on Review. Upon the Committee's receipt of a notice of a
request for review, the Committee shall make a prompt decision on the
review and shall communicate the decision on review in writing to the
claimant. The decision on review shall be written in a manner
calculated to be understood by the claimant and shall include
specific reasons for the decision and specific references to the
pertinent Plan provisions on which the decision is based. The
decision on review shall be made not later than sixty (60) days after
the Committee's receipt of a request for a review, unless special
circumstances require an extension of time for processing, in which
case a decision shall be rendered not later than one hundred twenty
(120) days after receipt of the request for review. If an extension
is necessary, the claimant shall be given written notice of the
extension by the Committee prior to the expiration of the initial
sixty (60) day period. If notice of the decision on review is not
furnished in accordance with this Section, the claim shall be denied
on review.
14.7 LIABILITY OF COMMITTEE, INDEMNIFICATION. To the extent permitted by law,
the Committee or any Company employee shall not be liable to any person for any
action taken or omitted in connection with the interpretation and administration
of this Plan unless attributable to his or her own bad faith or willful
misconduct.
- 11 -
<PAGE>
14.8 EXPENSES. The cost of the establishment of the Plan and the adoption of the
Plan by Company, including but not limited to legal and accounting fees, shall
be borne by the Company.
14.9 TAXES. All amounts payable hereunder shall be reduced by any and all
federal, state, and local taxes imposed upon an Eligible Employee or his or her
beneficiary which are required to be paid or withheld by Company. The
determination of Company regarding applicable income and employment tax
withholding requirements shall be final and binding on the Eligible Employee.
14.10 ATTORNEY'S FEES. Company shall pay the reasonable attorney's fees incurred
by any Eligible Employee in an action brought against Company to enforce
Eligible Employee's rights under the Plan, provided that such fees shall only be
payable in the event that the Eligible Employee prevails in such action.
ATTEST: SOUTHWESTERN ENERGY COMPANY
/s/ GREG D.KERLEY By: /s/ CHARLES E. SCHARLAU
- ----------------- ----------------------------
Greg D. Kerley Charles E. Scharlau
Vice President - Chairman and Chief Executive
Treasurer and Secretary Officer
[SEAL] Date: ____________________________
Effective Date: October 4, 1995
- 12 -
SPLIT-DOLLAR LIFE INSURANCE AGREEMENT
This Agreement is entered into as of February 1, 1996 by and between
Southwestern Energy Company (the "Company") and Stanley D. Green ("Employee")
inreference to the following facts:
1. Employee is a valued employee of the Company.
2. The Company has simultaneously with the execution of this
Agreement caused Pacific Mutual Life Insurance Company (the "Insurance Company")
to issue and deliver to Employee policy number 1A23067760 (the "Policy") on the
life of Employee. The first annual premium has been paid by the Company as of
the date of this Agreement.
3. For purposes of this Agreement, the Company and any
subsidiary of the Company shall constitute the "Employer." For this purpose, a
subsidiary is a corporation which is a member of a controlled group of
corporations (within the meaning of Section 414(b) of the Internal Revenue Code
of 1986, as amended (the "Code")) of which the Company is a member. If Employee
is employed by a corporation which, as a result of a sale or other corporate
reorganization, ceases to be a member of such controlled group, such sale or
other corporate reorganization shall be treated as a termination of Employee by
Employer without Cause (as defined in Section 8) unless immediately following
the event and without any break in employment the Employee remains employed by
the Company or another corporation which is a member of the controlled group of
corporations.
NOW THEREFORE, in consideration of the facts set forth above and the
various promises and covenants set forth below, the parties to this Agreement
agree as follows:
1. Ownership of Policy.
The Company acknowledges that Employee is the owner of the Policy and
that Employee is entitled to exercise all of his or her ownership rights granted
by the terms of the Policy, except to the extent that the power of the Employee
to exercise those rights is specifically limited by this Agreement. Except as so
limited, it is the expressed intention of the parties to reserve to Employee all
rights in and to the Policy granted to its owner by the terms thereof,
including, but not limited to, the right to change the beneficiary of that
portion of the proceeds to which Employee is entitled under Section 4 of this
Agreement and the right to exercise settlement options.
2. The Company's Security Interest.
The Company's security interest in the Policy is conditioned upon its
satisfactorily performing all of the covenants under this Agreement. Each period
covered by any individual premium payment described in Section 3 shall be
considered a discrete extension
<PAGE>
of the Company's security interest in the Policy. The Company shall not have nor
exercise any right in and to the Policy which could, in any way, endanger,
defeat, or impair any of the rights of Employee in the Policy, including by way
of illustration any right to collect the proceeds of the Policy in excess of the
amount due the Company as provided in this Agreement and in the Policy. The only
rights in and to the Policy granted to the Company in this Agreement shall be
limited to the Company's security interest in and to the cash value of the
Policy, as defined herein, and a portion of the death benefit of the Policy as
hereinafter provided (the "Security Interest"). The Company shall not assign any
of its Security Interest in the Policy to anyone other than Employee.
3. Premium payments.
Until (a) Employee files a notice with the Company pursuant to Section
10 electing a Security Release Date (as defined in Section 10 below), (b)
Employee otherwise attains his or her Security Release Date, or (c) Employee's
employment with the Company is terminated for any reason, whichever occurs
earliest, the Company agrees to pay premiums under the Policy in amounts such
that premiums (not including the initial premium) received by each anniversary
date are at least equal to the "cumulative cost of term insurance" (as defined
in the Policy) from the first anniversary date through the period ending twelve
months after the anniversary date in question. The premium payment shall be
transmitted directly by the Company to the Insurance Company. Consistent with
the preceding sentences, prior to the release of the Company's Security Interest
in the Policy, Employee and the Company agree that the Company shall from time
to time designate one or more individuals (the "Designee"), who may be officers
of the Company, who shall be entitled to adjust the death benefit under the
Policy; provided, however, that the Designee may only increase, but not
decrease, the death benefit in effect on the date that the Policy is issued.
During the period of time that this Agreement is in effect, Employee irrevocably
agrees that all dividends paid on the Policy shall be applied to purchase from
the Insurance Company additional paid-up life insurance on the life of Employee.
4. Death of Employee while employed by Employer.
(a) If Employee dies prior to termination of employment with Employer
and prior to his or her Security Release Date (as defined in Section 10 below),
Employee's designated beneficiary shall be entitled to receive as a death
benefit an amount equal to four times Employee's annual base salary at the time
of death. The amount described in the preceding sentence shall be paid from the
proceeds of the Policy. To the extent that the death benefit under the Policy
exceeds such amount, the balance of the death benefit shall be payable to the
Company. The designation of the beneficiaries under the Policy shall be in
accordance with this Section.
(b) Employee agrees that, during the period of this Agreement, Employee
will obtain and provide to the Company and/or the Insurance Company the written
consent of the spouse of the Employee, in the form attached hereto as Exhibit B,
to any designation
2
<PAGE>
by Employee of anyone other than the Employee's spouse as the beneficiary to
receive the benefits under this Section 4.
5. Employee's attaining his or her Security Release Date or termination of
Employee's employment on account of a Qualifying Termination.
(a) By making timely payment of the premiums described in Section 3,
the Company may renew its Security Interest in the Policy for the period
commencing with the due date of such payment until the later of (1) the due date
of the next payment described in Section 3, or (2) the date that Employee
attains his or her Security Release Date or terminates employment with the
Employer on account of a Qualifying Termination (either of which events
described in this clause 2 is referred to herein as a "Qualifying Event"). The
Company may not extend its Security Interest in the Policy under the Collateral
Security Assignment Agreement attached as Exhibit A after the occurrence of a
Qualifying Event. After such Qualifying Event, Employee shall be entitled to
exercise all of his or her ownership rights in the Policy without any
limitation, and this Agreement and its accompanying Collateral Security
Assignment Agreement shall no longer constitute a restriction on Employee's
rights.
(b) Notwithstanding paragraph (a), the Company shall continue to have
its Security Interest in the Policy to the extent required to satisfy its
withholding obligations as described in Section 12.
6. Termination of an Employee for a reason other than a Qualifying
Termination.
If the employment of Employee with Employer is terminated prior to his
or her Security Release Date for a reason other than a Qualifying Termination
(as described below), Employee shall cause, either by withdrawing from or
borrowing against the Policy, on a nonrecourse basis, to be transferred to the
Company an amount equal to the maximum amount that may then be obtained under
the Policy. In the event that the amount that can be withdrawn from or borrowed
against the Policy is less than the cash surrender value of the Policy, the
Company shall withhold from other compensation payable to Employee the amount of
such difference unless Employee has previously transferred to the Company an
amount equal to such difference. In no event shall Employee's voluntary
resignation prior to attaining his or her Security Release Date (as such concept
is further defined below) ever constitute a Qualifying Termination, except in
certain situations following a Change in Control (see Section 9).
7. Definition of a Qualifying Termination.
A Qualifying Termination is either of the following events: the
termination of Employee by Employer for any reason other than "Cause," as
described in Section 8; or the termination of Employee after a Change in Control
under the circumstances described in Section 9(a). Both of these concepts are
further defined below.
3
<PAGE>
8. Qualifying Termination because Employee is terminated for a reason
other than "Cause".
For purposes of this Section, "Cause" shall mean (1) Employee's failure
to render services to the Employer where such failure amounts to gross neglect
or misconduct of Employee's responsibilities and duties; (2) Employee's
commission of an act of fraud or dishonesty against the Employer; or (3)
Employee's conviction of a felony or other crime involving moral turpitude.
9. Qualifying Termination on account of termination after a Change in
Control.
(a) A Qualifying Termination shall be treated as occurring after a
"Change in Control" (as defined below) if there is first a "Change in Control"
and then, within one year following such Change in Control, either (1)
Employee's employment with the Employer is terminated without "Cause" (as
defined in Section 8) or (2) Employee terminates his or her employment with the
Employer for "Good Reason" (as defined in subsection (c) below).
(b) For purposes of this Section, a "Change in Control" shall mean the
occurrence of any of the following:
(1) any "Person" (as such term is used in Sections 13(d)
and 14(d) of the Securities Exchange Act of 1934 (the
"Exchange Act")) (an "Acquiring Person") becomes the
"beneficial owner" (as defined in Rule 13d-3 under
the Exchange Act), directly or indirectly, of
securities of the Company representing 20% or more of
the combined 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);
(2) the stockholders of the Company 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);
(3) any individual who is nominated by the Board of
Directors of the Company for election to the Board of
Directors of the Company 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 of Directors;
(4) 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
(5) a majority of the Board of Directors of the Company
determines in its sole and absolute discretion that
there has been a Change in Control
4
<PAGE>
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 Paragraphs (1) through (4) of this Section 9(b), a
Change in Control shall not occur by reason of any event which would otherwise
constitute a Change in Control if, immediately after the occurrence of such
event, individuals who are Acquiring Persons and who were employees of the
Company immediately prior to the occurrence of such event own, on a fully
diluted basis, securities of the Company representing (a) 5% or more of the
combined voting power of the Company's then outstanding equity securities or (b)
5% or more of the value of the Company's then outstanding equity securities.
(c) For purposes of this Section, "Good Reason" shall mean the
occurrence of one of the following events:
(1) 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 Employer
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 Employer for "Cause"
(as defined in Section 8);
(2) a reduction by the Employer 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 Employer for "Cause"
(as defined in Section 8);
(3) 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 Employer's business to an extent substantially
consistent with the Employee's business travel
obligations immediately prior to a Change in Control;
(4) (A) the failure by the Employer to continue in effect
any employee benefit plan, program or arrangement
(including, without limitation, "employee benefit
plans" within the meaning of Section 3(3) of the
Employee Retirement Income Security Act of 1974) in
which the Employee was participating immediately
prior to a Change in Control (or substitute plans,
programs or arrangements providing the Employee with
substantially similar benefits), (B) the taking of
any action, or the failure to take any action, by the
Employer which could (i) adversely affect the
Employee's participation in, or materially reduce the
Employee's benefits under, any of such plans,
programs or
5
<PAGE>
arrangements, (ii) materially adversely affect the
basis for computing benefits under any of such plans,
programs or arrangements or (iii) deprive the
Employee of any material fringe benefit enjoyed by
the Employee immediately prior to a Change in Control
or (C) the failure by the Employer 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 Employer's
vacation policy applicable to the Employee then in
effect, except in connection with the termination of
the Employee's employment by the Company for "Cause"
(as defined in Section 8);
(5) the failure by the Employer 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 Employer within seven (7) days of the date such
compensation is due;
(6) a material increase in the required working hours of
the Employee from that required prior to a Change in
Control; or
(7) the failure by the Employer to obtain an assumption
of the obligations of the Employer under this
Agreement by any successor to the Employer.
(d) A termination of employment by Employee within the 12-month period
following a Change in Control shall be for Good Reason if one of the occurrences
specified in paragraph (c) shall have occurred, notwithstanding that Employee
may have other reasons for terminating employment, including employment by
another employer which Employee desires to accept.
10. Employee's attaining his or her Security Release Date.
(a) Employee's "Security Release Date" shall mean the date which is at
least two years following the date on which the Company receives from Employee a
completed notice in the form attached hereto as Exhibit C, provided that
Employee continues to be employed by Employer until such date. Employee's
election of a Security Release Date shall be irrevocable.
(b) Employee's "Security Release Date" shall also mean the one-year
anniversary of a Change in Control, provided that Employee continues to be
employed by Employer until such date.
(c) Employee shall attain his or her Security Release Date upon
becoming disabled while employed by the Employer. Employee shall be considered
"disabled" at the time that the Administrator (as defined in Section 13(a)
below) determines, based upon
6
<PAGE>
competent medical advice, that an Employee is incapable of rendering substantial
services to the Employer by reason of mental or physical disability.
(d) The Company's Security Interest in the Policy is contingent upon
the timely payment of the premiums required under Section 3 of this Agreement.
Each period covered by any individual premium payment shall be considered an
independent extension of the Company's Security Interest in the Policy. In the
event that the Company waives its rights by reason of failure to make payments
under Section 3 of this Agreement, Employee shall immediately attain his or her
Security Release Date (provided, however, that the cessation of the Company's
obligations to pay premiums upon Employee's filing of an election of a Security
Release Date shall not result in Employee immediately attaining his or her
Security Release Date.) The Company's failure to extend its rights in no way
affects the Company's duties and obligations under this Agreement.
11. Limitation on Employee's rights prior to a Qualifying Event.
In order to protect the Company's Security Interest and notwithstanding
any other provisions in this Agreement, prior to a Qualifying Event, Employee
agrees that he or she will not modify the death benefit under the Policy, direct
the investment of the cash surrender value of the Policy, borrow against the
Policy, assign the Policy, or obtain any portion of the cash value of the
Policy. Notwithstanding the preceding sentence, if Section 6 applies to a
termination, Employee may borrow or withdraw from the Policy, so long as the
borrowing or withdrawal request is submitted to the Insurance Company along with
a directive that the borrowed or withdrawn amount be transferred directly to the
Company. Prior to the release of the Company's Security Interest in the Policy,
Employee and the Company agree that the Company shall from time to time appoint
one or more individuals (the "Designee"), who may be officers of the Company,
who shall be entitled to direct the investments under the Policy; provided,
however, that, the Designee may only direct the investments under the Policy in
funds offered by the Insurance Company under the Policy.
12. Tax Withholding.
It is recognized by the parties that the rights of Employee in the
Policy (as modified by the Agreement) may cause Employee to be treated under
certain circumstances as in receipt of gross income. These circumstances may
also impose upon the Company an obligation to deduct and withhold federal, state
or local taxes. Unless Employee otherwise provides the Company the amounts it is
required to withhold, Employee shall cause, either by withdrawing from or
borrowing on a nonrecourse basis against the Policy, to be transferred to the
Company that portion of the cash value of the Policy which is equal to the
amount of any federal, state or local taxes required to be withheld.
7
<PAGE>
13. Disputes.
(a) The Compensation Committee of the Board of Directors of the Company
(the "Administrator") shall administer this Agreement. The Administrator (either
directly or through its designees) will have power and authority to interpret,
construe, and administer this Agreement (for the purpose of this section, the
Agreement shall include the Collateral Security Assignment Agreement); provided
that, the Administrator's authority to interpret this Agreement shall not cause
the Administrator's decisions in this regard to be entitled to a deferential
standard of review in the event that Employee or his or her beneficiary seeks
review of the Administrator's decision as described below.
(b) Neither the Administrator, its designee nor its advisors, shall be
liable to any person for any action taken or omitted in connection with the
interpretation and administration of this Agreement.
(c) Because it is agreed that time will be of the essence in
determining whether any payments are due to Employee or his or her beneficiary
under this Agreement, Employee or his or her beneficiary may, if he or she
desires, submit any claim for payment under this Agreement or dispute regarding
the interpretation of this Agreement to arbitration. This right to select
arbitration shall be solely that of Employee or his or her beneficiary and
Employee or his or her beneficiary may decide whether or not to arbitrate in his
or her discretion. The "right to select arbitration" is not mandatory on
Employee or his or her beneficiary and Employee or his or her beneficiary may
choose in lieu thereof to bring an action in an appropriate civil court. Once an
arbitration is commenced, however, it may not be discontinued without the mutual
consent of both parties to the arbitration. During the lifetime of the Employee
only he or she can use the arbitration procedure set forth in this section.
(d) Any claim for arbitration may be submitted as follows: if Employee
or his or her beneficiary disagrees with the Administrator regarding the
interpretation of this Agreement and the claim is finally denied by the
Administrator in whole or in part, such claim may be filed in writing with an
arbitrator of Employee's or beneficiary's choice who is selected by the method
described in the next four sentences. The first step of the selection shall
consist of Employee or his or her beneficiary submitting a list of five
potential arbitrators to the Administrator. Each of the five arbitrators must be
either (1) a member of the National Academy of Arbitrators located in the State
of Arkansas or (2) a retired Arkansas Circuit Court, Court of Appeals or Supreme
Court judge. Within one week after receipt of the list, the Administrator shall
select one of the five arbitrators as the arbitrator for the dispute in
question. If the Administrator fails to select an arbitrator in a timely manner,
Employee or his or her beneficiary shall then designate one of the five
arbitrators as the arbitrator for the dispute in question.
(e) The arbitration hearing shall be held within seven days (or as soon
thereafter as possible) after the picking of the arbitrator. No continuance of
said hearing shall be allowed without the mutual consent of Employee or his or
her beneficiary and the
8
<PAGE>
Administrator. Absence from or nonparticipation at the hearing by either party
shall not prevent the issuance of an award. Hearing procedures which will
expedite the hearing may be ordered at the arbitrator's discretion, and the
arbitrator may close the hearing in his or her sole discretion when he or she
decides he or she has heard sufficient evidence to satisfy issuance of an award.
(f) The arbitrator's award shall be rendered as expeditiously as
possible and in no event later than one week after the close of the hearing. In
the event the arbitrator finds that the Company has breached this Agreement, he
or she shall order the Company to immediately take the necessary steps to remedy
the breach. The award of the arbitrator shall be final and binding upon the
parties. The award may be enforced in any appropriate court as soon as possible
after its rendition. If an action is brought to confirm the award, both the
Company and Employee agree that no appeal shall be taken by either party from
any decision rendered in such action.
(g) Solely for purposes of determining the allocation of the costs
described in this subsection, the Administrator will be considered the
prevailing party in a dispute if the arbitrator determines (1) that the Company
has not breached this Agreement and (2) the claim by Employee or his or her
beneficiary was not made in good faith. Otherwise, Employee or his or her
beneficiary will be considered the prevailing party. In the event that the
Company is the prevailing party, the fee of the arbitrator and all necessary
expenses of the hearing (excluding any attorneys' fees incurred by the Company)
including stenographic reporter, if employed, shall be paid by the other party.
In the event that Employee or his or her beneficiary is the prevailing party,
the fee of the arbitrator and all necessary expenses of the hearing (including
all attorneys' fees incurred by Employee or his or her beneficiary in pursuing
his or her claim), including the fees of a stenographic reporter if employed,
shall be paid by the Company.
14. Collateral Security Assignment of Policy to the Company.
In consideration of the promises contained herein, the Employee has
contemporaneously herewith granted the Security Interest in the Policy to the
Company as collateral, under the form of Collateral Security Assignment attached
hereto as Exhibit A, which Collateral Security Assignment gives the Company the
limited power to enforce its rights to recover the cash value of the Policy, or
a portion of the death benefit thereof, under the circumstances defined herein.
The Company's Security Interest in the Policy shall be specifically limited to
the rights set forth above in this Agreement, notwithstanding the provisions of
any other documents including the Policy. Employee agrees to execute any notice
prepared by the Company requesting a withdrawal or non-recourse loan in an
amount equal to the amount to which the Company is entitled under Sections 5, 6
or 12 of this Agreement.
9
<PAGE>
15. Employee's beneficiary rights and security interest.
(a) The Company and Employee intend that in no event shall the Company
have any power or interest related to the Policy or its proceeds, except as
provided herein and in the Collateral Security Assignment. In the event that the
Company ever receives or may be deemed to have received any right or interest in
the Policy or its proceeds beyond the limited rights described herein and in the
Collateral Security Assignment, such right or interest shall be held in trust
for the benefit of Employee and be held separate from the property of the
Company. The Company hereby agrees to act as trustee for the benefit of Employee
concerning any right to the Policy or its proceeds, except to the extent
expressly provided otherwise in this Agreement.
(b) In order to further protect the rights of the Employee, the Company
agrees that its rights to the Policy and proceeds thereof shall serve as
security for the Company's obligations as provided in this Agreement to
Employee. The Company grants to Employee a security interest in and collaterally
assigns to Employee any and all rights the Company has in the Policy, and
products and proceeds thereof whether now existing or hereafter arising pursuant
to the provisions of the Policy, this Agreement, the Collateral Security
Assignment or otherwise, to secure any and all obligations owed by the Company
to Employee under this Agreement. In no event shall this provision be
interpreted to reduce Employee's rights to the Policy or expand in any way the
rights or benefits of the Company under this Agreement, the Policy or the
Collateral Security Assignment. This security interest granted to Employee from
the Company shall automatically expire and be deemed waived if Employee
terminates employment with Employer prior to a Qualifying Event. Nothing in this
provision shall prevent the Company from receiving its share of the death
benefits under the Policy as provided in Section 4 of this Agreement.
16. Amendment of Agreement.
Except as provided in a written instrument signed by the Company and
Employee, this Agreement may not be cancelled, amended, altered, or modified.
17. Notice under Agreement.
Any notice, consent, or demand required or permitted to be given under
the provisions of this Agreement by one party to another shall be in writing,
signed by the party giving or making it, and may be given either by delivering
it to such other party personally or by mailing it, by United States Certified
mail, postage prepaid, to such party, addressed to its last known address as
shown on the records of the Company. The date of such mailing shall be deemed
the date of such mailed notice, consent, or demand.
18. Binding Agreement.
This Agreement shall bind the parties hereto and their respective
successors, heirs, executor, administrators, and transferees, and any Policy
beneficiary.
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19. Controlling law and characterization of Agreement.
(a) To the extent not governed by federal law, this Agreement and the
right to the parties hereunder shall be controlled by the laws of the State of
Arkansas.
(b) If this Agreement is considered a "plan" under the Employee
Retirement Income Security Act of 1974 (ERISA), both the Company and Employee
acknowledge and agree that for all purposes the Agreement shall be treated as a
"welfare plan" within the meaning of Section 3(1) of ERISA, so that only those
provisions of ERISA applicable to welfare plans shall apply to the Agreement,
and that any rights that might arise under ERISA if this Agreement were treated
as a "pension plan" within the meaning of Section 3(2) of ERISA are hereby
expressly waived. Consistent with the preceding sentence, Employee further
acknowledges that his or her rights to the Policy and the release of the
Company's Security Interest are strictly limited to those rights set forth in
this Agreement. In furtherance of this acknowledgement and in consideration of
the Company's payment of the initial premiums for this Policy, Employee
voluntarily and irrevocably relinquishes and waives any additional rights in the
Policy or any different restrictions on the release of the Company's Security
Interest that he or she might otherwise argue to exist under either state,
federal, or other law. Employee further agrees that he or she will not argue
that any such additional rights or different restrictions exist in any judicial
or arbitration proceeding. Similarly, the Company acknowledges that its Security
Interest is strictly limited as set forth in this Agreement and voluntarily and
irrevocably relinquishes and waives any additional interests or different
interests or advantages that the Company would have or enjoy if the Agreement
were not treated as a "welfare plan" within the meaning of section 3(1) of
ERISA.
20. Execution of Documents.
The Company and Employee agree to execute any and all documents
necessary to effectuate the terms of this Agreement.
SOUTHWESTERN ENERGY COMPANY
By: /s/ CHARLES E. SCHARLAU
-----------------------------
Its: Chairman and CEO
-----------------------------
EMPLOYEE
/s/ STANLEY D. GREEN
---------------------------------
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EXHIBIT A
COLLATERAL SECURITY ASSIGNMENT AGREEMENT
This Collateral Security Assignment is made and entered into effective
as of February 1, 1996, by the undersigned as the owner (the "Owner") of Life
Insurance Policy Number 1A23067760 (the "Policy") issued by Pacific Mutual Life
Insurance Company (the "Insurer") upon the life of Owner and by Southwestern
Energy Company, an Arkansas corporation (the "Assignee").
WHEREAS, the Owner is a valued employee of Assignee or a subsidiary of
Assignee, and the Assignee wishes to retain him or her in its or its
subsidiary's employ; and
WHEREAS, as an inducement to the Owner's continued employment, the
Assignee wishes to pay premiums on the Policy, as more specifically provided for
in that certain Split- Dollar Life Insurance Agreement dated as of February 1,
1996, and entered into between the Owner and the Assignee as such agreement may
be hereafter amended or modified (the "Agreement") (unless otherwise indicated
the terms herein shall have the definitions ascribed thereto in the Agreement);
WHEREAS, in consideration of the Assignee agreeing to make the premium
payments, the Owner agrees to grant the Assignee a security interest in the
Policy as collateral security; and
WHEREAS, the Owner and Assignee intend that the Assignee have no
greater interest in the Policy than that prescribed herein and in the Agreement
and that if the Assignee ever obtains any right or interest in the Policy or the
proceeds thereof, except as provided herein and in the Agreement, such right or
interest shall be held in trust for the Owner to satisfy the obligations of
Assignee to Owner under the Agreement and the Assignee additionally agrees that
its rights to the Policy shall serve as security for its obligations to the
Owner under the Agreement;
NOW, THEREFORE, the Owner hereby assigns, transfers and sets over to
the Assignee for security the following specific rights in the Policy, subject
to the following terms, agreements and conditions:
1. This Collateral Security Assignment is made, and the Policy is to be
held, as collateral security for all liabilities of the Owner to the Assignee
pursuant to the terms of the Agreement, whether now existing or hereafter
arising (the "Secured Obligations"). The Secured Obligations include: (i) the
obligation of the Owner to transfer an amount equal to the entire cash value in
the event that the Owner terminates employment with Employer for a reason other
than a Qualifying Termination and before attaining his or her Security Release
Date; (ii) the obligation of the Owner to pay an amount of cash to the Assignee
or transfer to the Assignee that portion of the cash value which is equal to any
federal, state
1
<PAGE>
or local taxes that Assignee may be required to withhold and collect (as set
forth in Section 12 of the Agreement); and (iii) the obligation of the Owner to
name the Assignee as beneficiary for a portion of the death benefit under the
Policy in the event of the death of Owner prior to Owner's termination of
employment with Employer in accordance with Section 4 of the Agreement.
2. The Owner hereby grants to Assignee a security interest in and
collaterally assigns to Assignee the Policy and the cash value to secure the
Secured Obligations. However, the Assignee's interest in the Policy shall be
strictly limited to:
(a) The right to be paid the Assignee's portion of the death benefit in
the event of the death of Owner prior to Owner's termination of employment with
Employer in accordance with Section 4 of the Agreement;
(b) The right to receive an amount equal to the entire cash value of
the Policy (which right may be realized by Assignee's receiving a portion of the
death benefit under the Policy or by Owner's causing such amount to be
transferred to Assignee (through withdrawing from or borrowing against the
Policy) in accordance with the terms of the Agreement) if the Owner terminates
employment with Employer for a reason other than a Qualifying Termination
(unless he or she has previously attained his or her Security Release Date); and
(c) The right to receive an amount equal to any federal, state or local
taxes that Assignee may be required to withhold and collect (as set forth in
Section 12 of the Agreement).
3.(a) Owner shall retain all incidents of ownership in the Policy, and
may exercise such incidents of ownership except as otherwise limited by the
Agreement and hereunder. The Insurer is only authorized to recognize (and is
fully protected in recognizing) the exercise of any ownership rights by Owner if
the Insurer determines that the Assignee has been given notice of Owner's
purported exercise of ownership rights in compliance with the provisions of
Section 3(b) hereof and as of the date thirty days after such notice is given,
the Insurer has not received written notification from the Assignee of
Assignee's objection to such exercise; provided that, the designation of the
beneficiary to receive the death benefits not otherwise payable to Assignee
pursuant to Section 4 of the Agreement may be changed by the Owner without prior
notification of Assignee. The Insurer shall not be responsible to ensure that
the actions of the Owner conform to the Agreement.
(b) Assignee hereby acknowledges that for purposes of this Collateral
Security Assignment, Assignee shall be conclusively deemed to have been properly
notified of Owner's purported exercise of his or her ownership rights as of the
third business day following either of the following events: (1) Owner mails
written notice of such exercise to Assignee by United States certified mail,
postage paid, at the address below and provides the Insurer with a copy of such
notice and a copy of the certified mail receipt or (2) the
2
<PAGE>
Insurer mails written notice of such exercise to Assignee by regular United
States mail, postage paid, at the address set forth below:
Southwestern Energy Company
P.O. Box 1408
Fayetteville, Arkansas 72702
ATTN: Corporate Secretary
The foregoing address shall be the appropriate address for such notices to be
sent unless and until the receipt by both Owner and the Insurer of a written
notice from Assignee of a change in such address.
(c) Notwithstanding the foregoing, Owner and Assignee hereby agree
that, until Assignee's security interest in the Policy is released, Assignee
shall from time to time designate one or more individuals (the "Designee"), who
may be officers of Assignee, who shall be entitled to adjust the death benefit
under the Policy and to direct the investments under the Policy; provided,
however, that the Designee may only increase, but not decrease, the death
benefit in effect on the date that the Policy is issued; provided, further, that
the Designee may only direct the investments under the Policy in funds offered
by the Insurer under the Policy. Assignee shall notify the Insurer in writing of
the identity of the Designee and any changes in the identity of the Designee.
Until Assignee's security interest in the Policy is released, no other party may
adjust the death benefit or direct the investments under the Policy without the
consent of the Assignee and Owner.
4. If the Policy is in the possession of the Assignee, the Assignee
shall, upon request, forward the Policy to the Insurer without unreasonable
delay for endorsement of any designation or change of beneficiary or the
exercise of any other right reserved by the Owner.
5.(a) Assignee shall be entitled to exercise its rights under the
Agreement by delivering a written notice to Insurer, executed by the Assignee
and the Owner or the Owner's beneficiary, requesting either (1) a withdrawal or
nonrecourse policy loan equal to the amount to which Assignee is entitled under
Sections 5, 6 or 12 of the Agreement and transfer of such withdrawn or borrowed
amount to Assignee or (2) the payment to the Assignee of that portion of the
death benefit under the Policy to which the Assignee is entitled under Section 4
of the Agreement. So long as the notice is also signed by Owner or his or her
beneficiary, Insurer shall pay or loan the specified amounts to Assignee without
the need for any additional documentation.
(b) Upon receipt of a properly executed notice complying with the
requirements of subsection (a) above, the Insurer is hereby authorized to
recognize the Assignee's claims to rights hereunder without the need for any
additional documentation and without investigating (1) the reason for such
action taken by the Assignee; (2) the validity or the amount of any of the
liabilities of the Owner to the Assignee under the Agreement; (3) the
3
<PAGE>
existence of any default therein; (4) the giving of any notice required herein;
or (5) the application to be made by the Assignee of any amounts to be paid to
the Assignee. The receipt of the Assignee for any sums received by it shall be a
full discharge and release therefor to the Insurer.
6. Upon the full payment of the liabilities of the Owner to the
Assignee pursuant to the Agreement, the Assignee shall execute an appropriate
release of this Collateral Security Assignment.
7. The Assignee shall have the right to request of the Insurer and/or
the Owner notice of any action taken with respect to the Policy by the Owner.
8.(a) The Assignee and the Owner intend that in no event shall the
Assignee have any power or interest related to the Policy or its proceeds,
except as provided herein and in the Agreement, notwithstanding the provisions
of any other documents including the Policy. In the event that the Assignee ever
receives or may be deemed to have received any right or interest beyond the
limited rights described herein and in the Agreement, such right or interest
shall be held in trust for the benefit of the Owner and be held separate from
the property of the Assignee. The Assignee hereby agrees to act as trustee for
the benefit of the Owner concerning any right to the Policy or its proceeds,
except to the extent expressly provided otherwise in the Agreement and this
Collateral Security Assignment Agreement.
(b) In order to further protect the rights of the Owner, the Assignee
agrees that its rights to the Policy and proceeds thereof shall serve as
security for the Assignee's obligations to the Owner as provided in the
Agreement. Assignee hereby grants to Owner a security interest in and
collaterally assigns to Owner any and all rights it has in the Policy, and
products and proceeds thereof, whether now existing or hereafter arising
pursuant to the provisions of the Policy, the Agreement, this Collateral
Security Assignment or otherwise, to secure Assignee's obligations ("Assignee
Obligations") to Owner under the Agreement, whether now existing or hereafter
arising. The Assignee Obligations include all obligations owed by the Assignee
to Owner under the Agreement, including without limitation: (i) the obligation
to transfer ownership of the Policy to Owner and to make the premium payments
required under Section 3 of the Agreement and (ii) the obligation to do nothing
which may, in any way, endanger, defeat or impair any of the rights of Owner in
the Policy as provided in the Agreement. In no event shall this provision be
interpreted to reduce Owner's rights in the Policy or expand in any way the
rights or benefits of the Assignee under the Agreement. In the event that Owner
terminates employment with Employer for any reason prior to a Qualifying Event,
this security interest and collateral assignment granted by Assignee to Owner
shall automatically expire and be deemed waived. Nothing in this provision shall
prevent the Assignee from receiving its share of the death benefits under the
Policy as provided in Section 4 of the Agreement.
9. Assignee and Owner agree to execute any documents necessary to
effectuate this Collateral Security Assignment pursuant to the provisions of the
Agreement. All
4
<PAGE>
disputes shall be settled as provided in Section 13 of the Agreement. The rights
under this Collateral Security Assignment may be enforced pursuant to the terms
of the Agreement.
IN WITNESS WHEREOF, the Owner and Assignee have executed this
Collateral Security Assignment effective the day and year first above written.
-----------------------------------
Stanley D. Green, Owner
SOUTHWESTERN ENERGY COMPANY
By:________________________________
Title:_____________________________
5
<PAGE>
EXHIBIT B
SPOUSAL CONSENT TO DESIGNATION OF NONSPOUSAL BENEFICIARY
My spouse is Stanley D. Green. I hereby consent to the
designation made by my spouse of ________________ as the beneficiary (subject to
any rights collaterally assigned to Southwestern Energy Company) under Life
Insurance Policy No. 1A23067760, which Southwestern Energy Company has purchased
from Pacific Mutual Life Insurance Company and transferred to him/her. I
understand that this consent is valid only with respect to the naming of the
beneficiary indicated above and that the designation of any other beneficiary
will not be valid unless I consent in writing to such designation.
This consent is being voluntarily given, and no undue
influence or coercion has been exercised in connection with my consent to the
designation made by my spouse of the beneficiary named above rather than myself
as the beneficiary under the Split-Dollar Life Insurance Policy.
------------------------------
Spouse's Signature
------------------------------
Print Spouse's Name
------------------------------
Date
<PAGE>
EXHIBIT C
SPLIT-DOLLAR LIFE INSURANCE
TWO YEAR SECURITY RELEASE NOTICE
Pursuant to the Split-Dollar Life Insurance Agreement entered into
between Southwestern Energy Company (the "Company") and me dated as of February
1, 1996 (the "Agreement"), I hereby notify the Company that I request to be
released on _____, _____ ("Security Release Date") from the Company's collateral
security in Policy Number 1A23067760 issued by Pacific Mutual Life Insurance
Company. I understand that my Security Release Date must be at least two years
from the date on which the Company receives this Notice. I further understand
that in order for the Company's collateral security interest to be released on
my Security Release Date, I must continue to be employed by the Company or one
of its subsidiaries (as defined in the Agreement) until such date.
-----------------------------
Stanley D. Green
-----------------------------
Date
Received by Southwestern Energy Company
on ________________________________________
By ________________________________________
Management's Discussion and Analysis of Financial Condition and
Results of Operations
RESULTS OF OPERATIONS
Net income in 1995 was $11.2 million, or $.45 per share, down from $25.1
million, or $.98 per share, in 1994. Net income in 1993 was $27.1 million, or
$1.05 per share. Net income in 1995 includes an extraordinary loss (net of tax
benefit) of $.3 million, or $.01 per share, incurred in connection with the
early call of the Company's 10.63% Senior Notes due September 30, 2001. The
comparative 1993 number 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 1994.
The decline in 1995 earnings was caused primarily by the generally low
level of gas prices and a decline in natural gas production. The decrease in
1994 earnings, as compared to 1993, resulted as lower gas prices and much warmer
weather offset the favorable effect of a year-to-year increase in natural gas
production. Lower gas prices in 1995 and 1994 reflected both the general decline
in spot market prices and the effect of a settlement approved by the Arkansas
Public Service Commission (APSC) to resolve a dispute concerning the Company's
pricing of intersegment sales (the Gas Cost Settlement). The Gas Cost
Settlement, which was effective July 1, 1994, increased the volumes which could
be sold by the Company's exploration and production segment to its gas
distribution segment, but made the sales price equal to a spot market index plus
a premium. The index-based pricing has to date resulted in a lower intersegment
sales price. The Gas Cost Settlement and the increases in recent years in sales
of gas production to unaffiliated purchasers have both caused earnings to become
more sensitive to changes in the market price for natural gas. Revenues and
operating income for the Company's major business segments are shown in the
following table.
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
REVENUES
Exploration and production $ 63,523 $ 80,123 $ 79,374
Gas distribution 119,855 127,060 131,892
Other 336 308 262
Eliminations (30,603) (37,305) (36,684)
- --------------------------------------------------------------------------------
$153,111 $170,186 $174,844
================================================================================
OPERATING INCOME
Exploration and production $ 20,523 $ 38,888 $ 42,608
Gas distribution 11,133 13,386 15,261
Corporate expenses (468) (192) (305)
- --------------------------------------------------------------------------------
$ 31,188 $ 52,082 $ 57,564
================================================================================
</TABLE>
EXPLORATION AND PRODUCTION REVENUES
The Company's exploration and production revenues decreased 21% in 1995 and
increased 1% in 1994. The decrease in 1995 was due to lower average gas prices
and a decline in the Company's offshore gas production. The slight increase in
1994 was due to increases in natural gas and oil production, offset by lower
average prices.
Gas production decreased 8% to 34.5 billion cubic feet (Bcf) in 1995 from
37.7 Bcf in 1994. Gas production in 1994 increased by 6% from 35.7 Bcf in 1993.
Sales from the Company's offshore properties were 2.7 Bcf in 1995, compared to
5.6 Bcf in 1994 and 6.3 Bcf in 1993. Sales in 1994 were helped by the start of
production from a new offshore platform which was completed late in 1993. Sales
from the Company's onshore production were 31.8 Bcf in 1995, down slightly from
32.1 Bcf in 1994. Sales from onshore production were 29.4 Bcf in 1993.
Production from producing properties acquired in 1994 and 1995 largely offset
declines in production from the Company's other onshore properties during 1995,
including an unexpected decline from the Earl Chauvin No. 1 well, a 1993
discovery in southeast Louisiana.
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS PRODUCTION
Affiliated sales (Bcf) 13.9 13.9 12.8
Unaffiliated sales (Bcf) 20.6 23.8 22.9
- --------------------------------------------------------------------------------
34.5 37.7 35.7
- --------------------------------------------------------------------------------
Average price per Mcf $1.72 $2.04 $2.18
================================================================================
OIL PRODUCTION
Unaffiliated sales (MBbls) 229 200 97
- --------------------------------------------------------------------------------
Average price per Bbl $17.15 $15.89 $17.20
================================================================================
</TABLE>
Gas sales to unaffiliated purchasers were 20.6 Bcf in 1995, down from 23.8
Bcf in 1994. Gas sales to unaffiliated purchasers were 22.9 Bcf in 1993. The
decrease in 1995 sales to unaffiliated purchasers was primarily the result of
decreased production from the Company's Gulf Coast properties, as discussed
above. Sales to unaffiliated purchasers are made under contracts which reflect
current short-term prices and which are subject to seasonal price swings. The
Company uses natural 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 gas supply in 1995
and 1994, as compared to 1993. Intersegment sales to Arkansas Western Gas
Company (AWG), the utility subsidiary which operates the Company's northwest
Arkansas utility system, were 8.5 Bcf in 1995, 8.8 Bcf in 1994, and 7.1 Bcf in
1993. The Company's gas production provided approximately 65% of AWG's
requirements in 1995, 64% in 1994, and approximately 57% in 1993. Additionally,
in 1995, 1994, and 1993, the Company sold .6 Bcf, .5 Bcf, and .7 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 pursuant to a long-term contract
entered into in 1978 and which was amended and restated in 1994 as a result of
the Gas Cost Settlement, discussed more fully below under "Regulatory Matters."
Other sales to AWG are made under long-term contracts with flexible pricing
provisions.
The Company's intersegment sales to Associated Natural Gas Company
(Associated), a division of AWG which operates the
10
<PAGE>
Company's natural gas distribution systems in northeast Arkansas and parts of
Missouri, were 5.4 Bcf in 1995, 5.1 Bcf in 1994, and 5.7 Bcf in 1993. Deliveries
to Associated increased in 1995 due to colder weather in the heating season and
decreased in 1994 due to warmer weather. 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. The sales price under this contract was $1.90 per
thousand cubic feet (Mcf) from inception of the contract through the first nine
months of 1993, $2.385 per Mcf for the contract period ending September 30,
1994, $2.20 per Mcf for the contract period ending September 30, 1995, and is
currently $1.785 per Mcf.
The overall average price received at the wellhead for the Company's gas
production was $1.72 per Mcf in 1995, $2.04 per Mcf in 1994, and $2.18 per Mcf
in 1993. The decline in the average price received since 1993 reflects declines
in average annual 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 were higher at December 31, 1995, as compared to
the prior year-end, primarily due to colder than normal weather experienced
across the country. The colder weather continued into early 1996 and has had a
positive impact on average prices received to-date in 1996, as compared to 1995.
As described above, a significant portion of the Company's gas pro-duction 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 spot market prices 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 spot market prices. 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 which it receives under the long-term contracts covering
its intersegment sales. 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 experienced a
decline in gas production in 1995, it does expect over the long term to return
to a trend of increasing gas production. However, the Company is unable to
predict changes in the market demand and price for natural gas, including
changes which may be induced by the effects of weather on demand of both
affiliated and unaffiliated customers for the Company's production.
Additionally, the Company holds a large 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>
1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
GAS DISTRIBUTION SYSTEMS
Throughput (Bcf)
Sales volumes 27.4 26.3 26.8
Transportation volumes
End-use 5.2 4.8 5.6
Off-system 9.8 10.7 11.7
- --------------------------------------------------------------------------------
42.4 41.8 44.1
- --------------------------------------------------------------------------------
Average number of sales customers 164,672 159,897 155,944
- --------------------------------------------------------------------------------
Heating weather--degree days 4,376 4,161 4,929
- --------------------------------------------------------------------------------
Average sales rate per Mcf $4.12 $4.57 $4.65
================================================================================
</TABLE>
Gas distribution revenues decreased by 6% in 1995 and by 4% in 1994. The
decrease in 1995 resulted from lower purchased gas costs caused in part by the
Gas Cost Settlement, which more than offset the effects of strong customer
growth and weather which was 5% colder than the prior year. The decrease in 1994
was due to lower purchased gas costs and weather which was 16% warmer than in
1993, partially offset by customer growth.
In 1995, AWG sold 17.1 Bcf to its customers at an average rate of $3.93 per
Mcf, compared to 16.3 Bcf at $4.25 per Mcf in 1994 and 17.1 Bcf at $4.40 per Mcf
in 1993. Additionally, AWG transported 4.3 Bcf in 1995, 4.0 Bcf in 1994, and 3.9
Bcf in 1993 for its end-use customers. Associated sold 10.3 Bcf to its customers
in 1995 at an average rate of $4.45 per Mcf, compared to 10.0 Bcf in 1994 at
$5.10 per Mcf and 9.7 Bcf at $5.08 per Mcf in 1993. Associated transported .9
Bcf for its end-use customers in 1995, compared to .8 Bcf in 1994 and 1.7 Bcf in
1993. The increase in volumes sold and transported in 1995 for both AWG and
Associated resulted from colder weather and from increases in the average number
of customers. The decrease in the average sales rate since 1993 for AWG and the
decrease in 1995 for Associated reflect the decline in the average cost of gas
purchased for delivery to the Company's customers.
Total deliveries to industrial customers of AWG and Associated, including
transportation volumes, increased to 13.0 Bcf in 1995, from 12.3 Bcf in 1994 and
11.7 Bcf in 1993. 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 9.8 Bcf of gas through its gatheringsystem in 1995 for
off-system deliveries, all to the NOARK Pipeline System (NOARK), compared to
10.7 Bcf in 1994 and 11.7 Bcf in 1993. The average transportation rate was
approximately $.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
11
<PAGE>
Management's Discussion and Analysis of Financial Conditon and
Results of Operations continued
has experienced customer growth of approximately 1% annually. Based on current
economic conditions in the Company's service territories, the Company expects
this trend in customer growth to continue. AWG filed an application with the
APSC on January 30, 1996, for a rate increase of $7.2 million annually. The APSC
has ten months in which to reach a decision on the amount of the rate increase
to be approved. As a result, any increase granted will likely not become
effective until late 1996. The Company anticipates filing a rate increase
request for Associated's operations in late 1996. Rate increase requests which
may be filed in the future will depend on customer growth, increases in
operating expenses, and additional investments in property, plant and equipment.
REGULATORY MATTERS
During 1994, the Company entered into the Gas Cost Settlement with the
Staff of the APSC and the Office of the Attorney General of the State of
Arkansas concerning certain issues that had been outstanding before the APSC for
the previous four years. These gas cost issues were first raised by the APSC in
December, 1990, in connection with its approval of an AWG rate increase. The
issues involved the price of gas sold under a long-term contract between AWG and
one of the Company's gas producing subsidiaries. The terms of the Gas Cost
Settlement became effective as of July 1, 1994, and were approved by the APSC on
January 5, 1995. Under the Gas Cost Settlement, the price paid by AWG is tied to
a monthly spot market index plus a premium. Given current market conditions, the
new pricing provision results in a reduced sales price. That effect is offset in
part by provisions of the Gas Cost Settlement which allow additional volumes to
be sold under the amended 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 pre-mium of $.95 per Mcf, while incremental sales volumes
receive a premium of $.50 per Mcf. In 1995, approximately 7.7 Bcf (net to the
Company's interest) was sold under the contract, compared to approximately 8.1
Bcf and 6.0 Bcf in 1994 and 1993, respectively. Other significant terms of the
Gas Cost Settlement preclude the parties thereto from asking for refunds,
transfer certain of AWG's natural gas storage facilities to another subsidiary
of the Company, and precluded AWG from filing an application for a rate increase
for its northwest Arkansas system before January, 1996.
Associated received an order on July 14, 1995, from the Missouri Public
Service Commission (MPSC) disallowing the recovery of approximately $2.0 million
of gas costs, the result of gas cost audits covering the five-year period ending
August 31, 1993. Of the total disallowed, $1.5 million represented a portion of
the difference between the price paid by Associated under its long-term firm
contract with one of the Company's gas producing subsidiaries (described above
under "Exploration and Production Revenues") and a spot market index price for
gas delivered into an interstate pipeline operating in the Arkoma Basin. The
balance of $.5 million disallowed represented take-or-pay charges passed through
to Associated by its interstate suppliers and allocable to transportation
customers of Associated. These take-or-pay charges resulted from pipeline
deregulation pursuant to Order No. 636 of the Federal Energy Regulatory
Commission, issued in April, 1992, which is a comprehensive set of regulations
designed to encourage compe-tition 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 APSC had previously reviewed the costs charged
to Arkansas ratepayers under this contract and found them to be proper and
allowable for recovery. Associated has appealed the MPSC's decision to the
Circuit Court of Cole County, Missouri, and that court has stayed the MPSC's
order and has directed Associated to pay the money to be refunded under the
MPSC's order into the registry of the court while the appeal is pending. The
MPSC Staff has also recommended the disallowance of an additional $.7 million of
gas costs as a result of an audit for the year ended August, 1994. The MPSC has
not yet issued an order in connection with that recommendation. The Company does
not expect the ultimate outcome of these matters to have a material adverse
impact on the results of operations or the financial position of the Company.
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 such exposure
has increased in recent years as a result of a decline in its gas purchase
requirements which has occurred as some of its large business customers
converted to a transportation service offered by AWG and began to obtain their
own gas supplies directly from other sources. The Company expects to be able to
continue to satisfactorily manage its exposure to take-or-pay liabilities.
OPERATING COSTS AND EXPENSES
The Company's operating costs and expenses increased by 3% in 1995 and by
1% in 1994. The increase in 1995 was due primarily to increased purchased gas
costs related to increased utility deliveries, increased general and
administrative expenses, and increased production costs. General and
administrative expenses increased due to inflationary increases in payroll and
other costs and from personnel additions in the Company's exploration and
production segment. Increased production costs in the exploration and production
segment are related to workovers of producing wells and higher operating costs
associated with the Company's expansion into areas outside of Arkansas. 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. 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
12
<PAGE>
purchased, and the timing of recoveries of deferred purchased gas costs.
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 for the exploration and production segment in 1995 decreased
slightly from 1994 as an increase in the amortization rate per unit was offset
by a decline in total units produced. DD&A increased 15% in 1994 due both to an
increase in units produced and an increase in the amortization rate per unit.
The margin between the Company's full cost ceiling and the financial statement
carrying value of the Company's gas and oil properties was slightly higher at
December 31, 1995, as compared to December 31, 1994, due primarily to a higher
level of market prices for gas at year-end 1995. The margin was eroded
substantially during 1994 as a result of very low average gas prices in effect
at December 31, 1994. Market prices, production rates, levels of reserves, and
the evaluation of costs excluded from amortization all influence the calculation
of the full cost ceiling. A 15% to 20% decline in gas prices from year-end 1995
levels or other factors, without other mitigating circumstances, could cause a
future write-down of capitalized costs 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 up 26% in 1995, as compared to 1994, due to both an
increase in long-term debt and higher average interest rates. The increase in
long-term debt is discussed below in "Liquidity and Capital Resources." Interest
capitalized increased by 54% in 1995 due primarily to higher capital
expenditures in the exploration and production segment where interest is
capitalized on costs excluded from amortization. Interest costs were slightly
lower in 1994, as compared to 1993, due to lower average borrowings on the
Company's revolving credit facilities through most of the year, partially offset
by higher average interest rates.
The change in other income in 1995, as compared to 1994, relates to a
decrease in the Company's share of operating losses incurred by NOARK, partially
offset by accruals for potential liabilities relating to certain regulatory gas
cost issues and other legal matters. The change in other income during 1994, as
compared to 1993, relates primarily to the Company's share of operating losses
incurred by NOARK. The Company, through a subsidiary, holds a 47.93% general
partnership interest in NOARK and is the pipeline's operator (See Note 7 of the
financial statements for additional discussion). NOARK became operational in
late 1992 and extends across northern Arkansas, crossing three major interstate
pipelines. NOARK has been operating below capacity and generating losses since
it was placed in service. The Company's share of the pretax loss from operations
for NOARK included in other income was $.7 million in 1995, $2.8 million in
1994, and $1.8 million in 1993. The 1995 pretax loss included $2.9 million of
income for the Company's share of a $6.0 million settlement of contract issues
with one of NOARK's transporters, as discussed below. 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 1995, NOARK had
an average daily throughput of 86 million cubic feet of gas per day (MMcfd),
compared to 82 MMcfd in 1994 and 79 MMcfd in 1993. NOARK has a total
transportation capacity of approximately 141 MMcfd. AWG has contracted for 41
MMcfd of firm capacity on NOARK under a ten-year transportation contract, with
seven years remaining on its original term. The contract is renewable
year-to-year until terminated by 180 days' notice. NOARK also had 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. In late
1995, the suit was settled prior to going to trial. In exchange for a $6.0
million payment to NOARK, Vesta was released from its obligations under its firm
transportation agreement and its contract with the Company's affiliates.
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. 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
13
<PAGE>
Management's Discussion and Analysis of Financial Condition and
Results of Operations continued
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 38.6% in 1995, 38.5% in 1994,
and 42.3% in 1993. The rate was higher 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 1995, 1994, and
1993, net cash provided from operating activities totaled $55.9 million, $66.6
million, and $70.2 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 59% of the Company's capital requirements for
routine capital expenditures, cash dividends, and scheduled debt retirements in
1995, 92% in 1994, and in excess of 100% in 1993.
Dividends paid to common shareholders in 1995 were $6.0 million, compared
to $6.2 million in 1994 and $5.7 million in 1993. 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.
In February, 1995, the Board of Directors authorized the repurchase of up
to $30.0 million of the Company's common shares. The Company repurchased
1,000,000 shares during 1995 at an average cost of $14.26, using 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 Company does not at present have definite plans to
repurchase additional shares, but may purchase additional shares from time to
time, depending on market conditions.
Changes in the Company's liquidity in future years are expected to be
related primarily to changes in cash flow generated from its operations.
CAPITAL EXPENDITURES
Capital expenditures totaled $101.6 million in 1995, $76.9 million in 1994,
and $59.2 million in 1993. In 1995 and 1994, expenditures for the exploration
and production segment included $6.0 million and $13.9 million, respectively,
for acquisitions of reserves in place.
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
CAPITAL EXPENDITURES
Exploration and production $ 82,237 $55,449 $37,411
Gas distribution 18,523 17,577 19,892
Other 866 3,828 1,916
- --------------------------------------------------------------------------------
$101,626 $76,854 $59,219
================================================================================
</TABLE>
The Company generally intends to adjust its level of routine capital
expenditures depending on the expected level of internally generated cash and
the level of debt in its capital structure. The Company expects that its level
of capital spending will be adequate to allow the Company to maintain its
present markets, explore and develop existing gas and oil properties as well as
generate new drilling prospects, and finance improvements necessary due to
normal customer growth in its gas distribution segment.
Capital spending planned for 1996 totals $86.4 million, a decrease of 15%
from 1995, consisting of $71.0 million for gas and oil exploration, $13.5
million for gas distribution system expenditures, and $1.9 million for general
purposes. The gas and oil expenditures consist of $24.5 million for development
drilling, including $14.5 million for the Company's Arkansas program, $20.0
million for producing property acquisitions, and a total of $12.4 million for
exploratory drilling and seismic data acquisition.
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 $22.9 million at the end of 1995 and $52.3
million at the end of 1994.
In November, 1995, the Company filed a shelf registration statement with
the Securities and Exchange Commission for the issuance of up to $250.0 million
of senior unsecured debt securities. Effective December 1, 1995, the Company
issued under the shelf registration statement $125.0 million of 6.70% Senior
Notes due 2005. Proceeds from the issuance of these notes were used primarily to
repay certain borrowings under the Company's revolving credit facilities. The
facilities had been drawn on to prepay the Company's 10.63% Senior Notes, to
repurchase 1,000,000 shares of the Company's common stock, as described above,
and to fund the Company's capital spending program. Additional debt securities
may be issued in the future under the shelf registration statement as
circumstances dictate. The Company's public notes were rated BBB+ by Standard
and Poor's and Baa2 by Moody's Investor Service.
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 $56.7 million at December 31, 1995, with
final maturity in 2009. 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 $23.2 million at December 31, 1995, and $29.6 million at December 31, 1994.
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 the several guarantee of the notes and the line of credit is
60%. In 1995, the Company advanced $5.0 million to NOARK to fund its share of
debt service payments. The Company expects to advance $1.0 to $1.5 million to
NOARK during 1996 in connection with its
14
<PAGE>
guarantees. The anticipated contributions in 1996 are less than the 1995 amount
due to the receipt by NOARK of the $6.0 million settlement payment from Vesta in
December, 1995, as discussed above. The cash received was used by NOARK to pay
down its revolving credit facility. The credit facility will be used in 1996 to
help fund NOARK's long-term debt service payments before additional partner
advances are called for.
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 1995, the
capital structure consisted of 51.6% debt (excluding the current portion of
long-term debt and the Company's several guarantee of NOARK's obligations) and
48.4% equity, with a ratio of earnings to fixed charges of 1.9.
The percentage of debt in the Company's capital structure may in the near
term increase from the current level as the Company funds expenditures which
will not generate cash flow until future periods, such as the acquisition of
seismic data. Over the longer term, the Company expects to lower the debt
portion of its capital structure through its policy of adjusting its routine
capital spending. The Company will 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.
WORKING CAPITAL
The Company maintains access to funds which may be needed to meet seasonal
requirements through the revolving lines of credit explained above. The Company
had net working capital of $18.5 million at the end of 1995, and $8.9 million at
the end of 1994. Current assets increased by 29% to $63.9 million in 1995, while
current liabilities increased 12% to $45.4 million. The increase in current
assets at December 31, 1995, was due primarily to increases in income taxes
receivable, inventories, and accounts receivable. The increase in accounts
receivable was due to higher weather-related sales at year-end 1995. The
increase in income taxes receivable relates to the carryback of a 1995 tax net
operating loss which resulted from lower operating income and higher intangible
drilling costs. Intangible drilling costs are deductible currently for tax
purposes, but are capitalized and amortized over future periods for financial
reporting purposes. The increase in inventories since December 31, 1994, is the
result of injections of purchased gas into the Company' s unregulated
underground storage facility. The Company has been withdrawing and selling this
gas during the first quarter of 1996. The increase in current liabilities
resulted primarily from an increase in accounts payable, an increase in taxes
(other than income) payable, and an increase in over-recovered purchased gas
costs, offset by a decrease in the current portion of long-term debt. The
increase in accounts payable resulted primarily from increased amounts due for
gas purchases which resulted from the higher weather-related sales in the gas
distribution segment, a higher level of exploration and production capital
expenditures, and from the timing of payments. Over-recovered purchased gas
costs will be refunded to the Company's utility customers over future periods
through the automatic cost of gas adjustment clauses in the Company's filed rate
tariffs.
This discussion and analysis of financial condition and results of
operations includes forward-looking statements within the meaning of Section 27A
of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. The Company believes that its expectations are based on reasonable
assumptions. No assurances, however, can be given that its goals will be
achieved. Important factors that could cause actual results to differ materially
from those in the forward-looking statements herein include (1) the timing and
extent of changes in commodity prices for gas and oil, (2) the extent of the
Company's success in discovering, developing, and producing reserves, (3) the
effects of weather and regulation on the Company's gas distribution segment, and
(4) conditions in capital markets, availability of oil field services, drilling
rigs, and other equipment, as well as other competitive factors during the
periods covered by the forward-looking statements.
15
<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, 1995 and
1994, and the related consolidated statements of income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 1995.
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, 1995 and 1994, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1995, 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 5, 1996
16
<PAGE>
Statements of Income
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
($ in thousands, except per share amounts)
<S> <C> <C> <C>
OPERATING REVENUES
Gas sales $142,455 $160,463 $166,164
Oil sales 3,924 3,178 1,662
Gas transportation 4,964 4,721 5,177
Other 1,768 1,824 1,841
- -----------------------------------------------------------------------------------------------------------------------------
153,111 170,186 174,844
- -----------------------------------------------------------------------------------------------------------------------------
OPERATING COSTS AND EXPENSES
Purchased gas costs 37,133 36,395 42,962
Operating and general 44,436 42,506 40,093
Depreciation, depletion and amortization 35,992 35,546 30,944
Taxes, other than income taxes 4,362 3,657 3,281
- -----------------------------------------------------------------------------------------------------------------------------
121,923 118,104 117,280
- -----------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 31,188 52,082 57,564
- -----------------------------------------------------------------------------------------------------------------------------
INTEREST EXPENSE
Interest on long-term debt 12,984 9,962 10,090
Other interest charges 639 504 483
Interest capitalized (2,456) (1,599) (1,548)
- -----------------------------------------------------------------------------------------------------------------------------
11,167 8,867 9,025
- -----------------------------------------------------------------------------------------------------------------------------
OTHER INCOME (EXPENSE) (1,227) (2,362) (1,657)
- -----------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE INCOME TAXES, EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE 18,794 40,853 46,882
- -----------------------------------------------------------------------------------------------------------------------------
INCOME TAXES
Current (4,908) 9,288 13,704
Deferred 12,167 6,441 6,128
- -----------------------------------------------------------------------------------------------------------------------------
7,259 15,729 19,832
- -----------------------------------------------------------------------------------------------------------------------------
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE 11,535 25,124 27,050
EXTRAORDINARY LOSS DUE TO EARLY RETIREMENT OF DEBT (NET OF $185 TAX BENEFIT) (295) -- --
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR INCOME TAXES -- -- 10,126
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME $ 11,240 $ 25,124 $ 37,176
=============================================================================================================================
EARNINGS PER SHARE
Income before extraordinary item and cumulative effect of accounting change $.46 $.98 $1.05
Extraordinary loss due to early retirement of debt (net of $185 tax benefit) (.01) -- --
Cumulative effect of change in accounting for income taxes -- -- .39
- -----------------------------------------------------------------------------------------------------------------------------
NET INCOME $.45 $.98 $1.44
=============================================================================================================================
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 25,130,781 25,684,110 25,684,110
=============================================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
17
<PAGE>
Balance Sheets
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
December 31 1995 1994
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
ASSETS
Current Assets
Cash $ 1,498 $ 1,152
Accounts receivable 35,541 32,325
Income taxes receivable 8,221 1,492
Inventories, at average cost 15,448 12,199
Other 3,188 2,353
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 63,896 49,521
- -----------------------------------------------------------------------------------------------------------------------------
Investments 9,114 4,877
- -----------------------------------------------------------------------------------------------------------------------------
Property, Plant and Equipment, at cost
Gas and oil properties, using the full cost method, including $51,337,000 in 1995 and
$20,751,000 in 1994 excluded from amortization 517,979 435,570
Gas distribution systems 193,258 176,728
Gas in underground storage 32,616 36,629
Other 19,717 18,541
- -----------------------------------------------------------------------------------------------------------------------------
763,570 667,468
Less: Accumulated depreciation, depletion and amortization 277,751 242,008
- -----------------------------------------------------------------------------------------------------------------------------
485,819 425,460
- -----------------------------------------------------------------------------------------------------------------------------
Other Assets 10,264 6,216
- -----------------------------------------------------------------------------------------------------------------------------
$569,093 $486,074
=============================================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Current portion of long-term debt $ 3,071 $ 6,071
Accounts payable 23,989 18,670
Taxes payable 2,422 2,208
Customer deposits 4,619 4,232
Over-recovered purchased gas costs, net 7,327 3,627
Other 3,982 5,827
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 45,410 40,635
- -----------------------------------------------------------------------------------------------------------------------------
Long-Term Debt, less current portion above 207,757 136,229
- -----------------------------------------------------------------------------------------------------------------------------
Other Liabilities
Deferred income taxes 115,461 100,288
Deferred investment tax credits 2,103 2,416
Other 3,858 3,050
- -----------------------------------------------------------------------------------------------------------------------------
121,422 105,754
- -----------------------------------------------------------------------------------------------------------------------------
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 21,272 21,231
Retained earnings, per accompanying statements 204,632 199,430
- -----------------------------------------------------------------------------------------------------------------------------
228,678 223,435
Less: Common stock in treasury, at cost, 3,036,735 shares in 1995 and
2,053,974 shares in 1994 33,795 19,717
Unamortized cost of restricted shares issued under stock incentive plan,
34,807 shares in 1995 and 21,499 shares in 1994 379 262
- -----------------------------------------------------------------------------------------------------------------------------
194,504 203,456
- -----------------------------------------------------------------------------------------------------------------------------
$569,093 $486,074
=============================================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
18
<PAGE>
Statements of Cash Flows
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Cash Flows From Operating Activities
Net income $ 11,240 $ 25,124 $ 37,176
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 36,272 35,825 31,223
Deferred income taxes 12,167 6,441 6,128
Equity in loss of partnership 696 2,818 1,788
Cumulative effect of change in accounting for income taxes -- -- (10,126)
Change in assets and liabilities:
(Increase) decrease in accounts receivable (3,216) 2,569 (589)
(Increase) decrease in income taxes receivable (6,729) (5,354) 3,090
Increase in inventories (3,249) (2,619) (1,544)
Increase in accounts payable 5,319 2,556 2,298
Increase (decrease) in taxes payable 214 (379) 21
Increase in customer deposits 387 305 417
Increase (decrease) in over-recovered purchased gas costs 3,700 (560) (286)
Net change in other current assets and liabilities (940) (113) 603
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 55,861 66,613 70,199
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Investing Activities
Capital expenditures (101,626) (76,854) (59,219)
Investment in partnership (4,968) (2,319) --
Decrease in gas stored underground 4,013 542 9,119
Other items 2,814 3,200 1,599
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (99,767) (75,431) (48,501)
- -----------------------------------------------------------------------------------------------------------------------------
Cash Flows From Financing Activities
Net proceeds from issuance of Senior Notes 121,978 -- --
Net increase (decrease) in revolving long-term debt (29,400) 21,300 (15,500)
Retirement of 10.63% Senior Notes and prepayment premium (24,958) -- --
Payments on other long-term debt (3,071) (6,000) (835)
Purchase of treasury stock (14,259) -- --
Dividends paid (6,038) (6,164) (5,651)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 44,252 9,136 (21,986)
- -----------------------------------------------------------------------------------------------------------------------------
Increase (decrease) in cash 346 318 (288)
Cash at beginning of year 1,152 834 1,122
- -----------------------------------------------------------------------------------------------------------------------------
Cash at end of year $ 1,498 $ 1,152 $ 834
=============================================================================================================================
</TABLE>
Statements of Retained Earnings
Southwestern Energy Company and Subsidiaries
<TABLE>
<CAPTION>
For the Years Ended December 31 1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Retained Earnings, beginning of year $199,430 $180,470 $148,945
Net income 11,240 25,124 37,176
Cash dividends declared ($.24 per share in 1995 and 1994, and $.22 per share in 1993) (6,038) (6,164) (5,651)
- -----------------------------------------------------------------------------------------------------------------------------
Retained Earnings, end of year $204,632 $199,430 $180,470
=============================================================================================================================
</TABLE>
The accompanying notes are an integral part of the financial statements.
19
<PAGE>
Notes to Financial Statements
December 31, 1995, 1994 and 1993
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS AND CONSOLIDATION
Southwestern Energy Company is a diversified natural gas company which
operates principally in the exploration and production segment and the gas
distribution segment of the natural gas industry. Approximately 75% of the
Company's business is derived from the exploration and production segment based
on operating income. The primary areas of operations for the exploration and
production segment are the Arkoma Basin of Arkansas, the Gulf Coast areas of
Louisiana and Texas, the Anadarko Basin of Oklahoma, and the Delaware Basin of
New Mexico. The gas distribution segment operates in northwest and northeast
Arkansas and parts of Missouri, and obtains approximately 60% of its gas supply
from one of the Company's exploration and production subsidiaries. The customers
of the gas distribution segment consist of residential, commercial, and
industrial users of natural gas.
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 its general partnership interest in the NOARK Pipeline
System, Limited Partnership (NOARK) using the equity method of accounting. In
accordance with Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the Company
recognizes profit on intercompany sales of gas delivered to storage by its
utility subsidiary. Certain reclassifications have been made to the prior years'
financial statements to conform with the 1995 presentation.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities, if any, at the date of the
financial statements, and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
Gas and Oil Properties-The Company follows the full cost method of
accounting for the exploration, development, and acquisition of gas and oil
reserves. Under this method, all such costs (productive and nonproductive) 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 6.7%. 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 accor-dance 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 101,000 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, to provide a proper matching of revenues with expenses.
The gas distribution subsidiary's rate schedules include purchased gas
adjustment clauses whereby the actual cost of purchased gas above or below the
level included in the base rates is permitted to be billed or is required to be
credited to customers. Each month, the difference between actual costs of
purchased gas and gas costs recovered from customers is deferred. The deferred
differences are billed or credited, as appropriate, to customers in subsequent
months.
GAS PRODUCTION IMBALANCES
The exploration and production subsidiaries record gas sales using the
entitlement method. The entitlement method requires revenue recognition of the
Company's revenue interest share of gas production from properties in which gas
sales are disproportionately allocated to owners because of marketing or other
contractual arrangements. The Company's net imbalance position at December 31,
1995 and 1994 was not significant.
20
<PAGE>
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.
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. There were no outstanding
interest rate swap agreements at December 31, 1995 or 1994.
The Company uses natural gas swap agreements to hedge sales of natural gas.
Under the natural gas swap agreements, the Company makes or receives payments
based on the differential between a specified price and the indicated market
price of natural gas. Gains and losses resulting from hedging activities are
recognized when the related physical natural gas transactions are recognized.
Gains or losses from natural gas swap agreements that do not qualify for
accounting treatment as hedges are recognized currently as other income or
expense. Gains and losses resulting from natural gas swap agreements and hedging
activities have not had a material impact on the Company's results of
operations.
EARNINGS PER SHARE AND SHAREHOLDERS' EQUITY
Earnings per common share are based on the weighted average number of
common shares outstanding during each year.
During 1995 the Company repurchased 1,000,000 shares of its common stock
for $14.3 million, and issued under a compensatory plan and for stock awards
17,239 treasury shares with a weighted average cost of $.2 million.
(2) LONG-TERM DEBT
Long-term debt as of December 31, 1995 and 1994 consisted of the following:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
SENIOR NOTES
6.70% Series due December 1, 2005 $125,000 $ --
8.69% Series due December 4, 1997 22,500 22,500
8.86% Series due in annual installments of $3.1 million through December 4, 2001 18,428 21,500
9.36% Series due in annual installments of $2.0 million beginning December 4, 2001 22,000 22,000
10.63% Series -- 24,000
- --------------------------------------------------------------------------------------------------------------------------
187,928 90,000
OTHER
Variable rate (6.33% at December 31, 1995)unsecured revolving credit arrangements with two banks 22,900 52,300
- --------------------------------------------------------------------------------------------------------------------------
Total long-term debt 210,828 142,300
Less: Current portion of long-term debt 3,071 6,071
- --------------------------------------------------------------------------------------------------------------------------
$207,757 $136,229
==========================================================================================================================
</TABLE>
In December, 1995, the Company issued $125.0 million of 6.70% fixed rate
Senior Notes. The notes mature with a single payment due after ten years. The
proceeds were used to repay certain borrowings of the Company. The Company
incurred $3.0 million of costs associated with the issuance of this debt. This
amount has been capitalized and will be amortized over the life of the notes.
In November, 1995, the Company exercised its prepayment option on its
10.63% Senior Notes due September 30, 2001. Certain costsof the redemption were
expensed in the fourth quarter of 1995 and are classified as an extraordinary
loss, net of related income tax effects, in the accompanying financial
statements.
The Company has several prepayment options under the terms of its other
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, 1995, the Company had two variable rate facilities which
make available $80.0 million of long-term revolving credit, of which $22.9
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 and 1999.
The Company intends to renew or replace the facilities prior to expiration.
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, 1995, approximately $103.0 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.
21
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
Aggregate maturities of long-term debt for each of the years ending
December 31, 1996 through 2000, are $3.1 million, $25.6 million, $16.1 million,
$13.0 million, and $3.1 million. Total interest payments of $12.9 million, $10.2
million, and $10.3 million were made in 1995, 1994, and 1993, respectively.
(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. 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>
1995 1994 1993
- ----------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Federal:
Current $(5,436) $ 7,758 $11,514
Deferred 11,434 5,588 3,827
Deferred tax adjustment for tax rate increase -- -- 1,743
State:
Current 528 1,530 2,190
Deferred 1,046 1,054 752
Investment tax credit amortization (313) (201) (194)
- ----------------------------------------------------------------------------------------------------
Provision for income taxes $ 7,259 $15,729 $19,832
====================================================================================================
</TABLE>
The provision for income taxes was an effective rate of 38.6% in 1995,
38.5% in 1994, and 42.3% in 1993. 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>
1995 1994 1993
- --------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Expected provision at federal statutory rate of 35% $6,578 $14,299 $16,409
Increase (decrease) resulting from:
State income taxes, net of federal income tax benefit 1,023 1,682 1,914
Percentage depletion on gas and oil production (70) (96) (117)
Adjustment to deferred taxes for tax rate increase -- -- 1,743
Investment tax credit amortization (313) (201) (194)
Other 41 45 77
- --------------------------------------------------------------------------------------------------------------
Provision for income taxes $7,259 $15,729 $19,832
==============================================================================================================
</TABLE>
The components of the Company's net deferred tax liability as of December
31, 1995 and 1994 were as follows:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Deferred tax liabilities:
Differences between book and tax basis of property $103,612 $ 89,289
Stored gas differences 5,435 5,736
Deferred purchased gas costs 236 1,557
Prepaid pension costs 1,561 1,628
Book over tax basis in partnerships 4,712 3,535
Other 971 1,095
- --------------------------------------------------------------------------------
116,527 102,840
- --------------------------------------------------------------------------------
Deferred tax assets:
Accrued compensation 681 700
Other 644 370
- --------------------------------------------------------------------------------
1,325 1,070
- --------------------------------------------------------------------------------
Net deferred tax liability $115,202 $101,770
================================================================================
</TABLE>
Total income tax payments of $.9 million, $14.6 million, and $10.2 million
were made in 1995, 1994, and 1993, respectively.
22
<PAGE>
(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 1995 and 1994 included an expected long-term rate of
return on plan assets of 9%, a weighted average discount rate of 8.5% in 1995
and 7.5% in 1994 for the net pension cost computation, and a salary progression
rate of 5%. The reconciliation of prepaid pension cost at December 31, 1995
utilizes a discount rate of 7.5% 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, 1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
- ------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Actuarial present value of benefit obligations:
Vested benefits $(25,789) $(20,643)
Nonvested benefits (1,860) (1,635)
- ------------------------------------------------------------------------------------------
Accumulated benefit obligation (27,649) (22,278)
Effect of projected future compensation levels (8,623) (6,368)
- ------------------------------------------------------------------------------------------
Projected benefit obligation (36,272) (28,646)
Plan assets at fair value, primarily common stocks and bonds 49,570 36,675
- ------------------------------------------------------------------------------------------
Plan assets in excess of projected benefit obligation 13,298 8,029
Unrecognized net gain (8,956) (3,617)
Unrecognized net asset (952) (1,135)
Unrecognized prior service cost 397 454
- ------------------------------------------------------------------------------------------
Prepaid pension cost $ 3,787 $ 3,731
==========================================================================================
</TABLE>
Net pension cost for 1995, 1994, and 1993 included the following
components:
<TABLE>
<CAPTION>
1995 1994 1993
- ----------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Service costs (benefits earned during the period) $ 1,101 $ 1,217 $ 897
Interest cost on projected benefit obligation 2,316 2,280 1,999
Actual return on plan assets (15,172) (791) (2,819)
Net amortization and deferral 11,699 (2,643) (673)
- ----------------------------------------------------------------------------------------------------
Net pension cost (credit) $ (56) $ 63 $ (596)
====================================================================================================
</TABLE>
The Company also has a supplemental retirement plan which provides for
certain pension benefits. Net pension cost recorded for this plan was $221,000,
$201,000, and $628,000 in 1995, 1994, and 1993, respectively. In 1993, this plan
was funded with $1.2 million. At December 31, 1995, the supplemental retirement
plan had an accrued pension cost of $91,000.
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.
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 1995 and 1994 included the following components:
<TABLE>
<CAPTION>
1995 1994
- ----------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Service cost of benefits earned during the year $110 $ 79
Amortization of transition amount 103 178
Amortization of unrecognized gain 32 17
Interest cost on accumulated postretirement benefit obligation (APBO) 218 164
- ----------------------------------------------------------------------------------------------------
Net postretirement benefit cost $463 $438
====================================================================================================
</TABLE>
23
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
The APBO as of December 31, 1995 and 1994 was comprised of the following:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Retirees $1,109 $ 766
Active participants, fully eligible 303 442
Other participants 805 804
- --------------------------------------------------------------------------------
Total APBO $2,217 $2,012
================================================================================
</TABLE>
In determining the APBO, assumed weighted average discount rates of 7.5%
and 8.5% were used for 1995 and 1994, respectively. An increase of 10% in the
cost of covered health care benefits was assumed for 1996. This rate is assumed
to decrease ratably to 6.0% over 8 years and remain at that level thereafter.
The effect of a one percentage point increase in the assumed health care cost
trend rate for each future year would increase the total APBO at year-end 1995
by $253,000 and the 1995 net postretirement benefit cost by $29,000.
(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>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Sales $ 63,205 $ 80,123 $ 79,374
Production (lifting) costs (7,930) (6,771) (6,341)
Depreciation, depletion and amortization (29,607) (29,738) (25,686)
- --------------------------------------------------------------------------------
25,668 43,614 47,347
Income tax expense (9,831) (16,684) (18,081)
- --------------------------------------------------------------------------------
Results of operations $ 15,837 $ 26,930 $ 29,266
================================================================================
</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 1995, 1994,
and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Property acquisition costs $27,715 $21,972 $ 5,920
Exploration costs 29,843 12,419 11,695
Development costs 24,429 20,943 19,722
- --------------------------------------------------------------------------------
Capitalized costs incurred $81,987 $55,334 $37,337
================================================================================
Amortization per Mcf equivalent $.817 $.759 $.710
================================================================================
</TABLE>
The following table shows the capitalized costs of gas and oil properties
and the related accumulated depreciation, depletion and amortization at December
31, 1995 and 1994:
<TABLE>
<CAPTION>
1995 1994
- ----------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Proved properties $463,868 $405,081
Unproved properties 54,111 30,489
- ----------------------------------------------------------------------------------------------------
Total capitalized costs 517,979 435,570
Less: Accumulated depreciation, depletion and amortization 206,148 176,764
- ----------------------------------------------------------------------------------------------------
Net capitalized costs $311,831 $258,806
====================================================================================================
</TABLE>
The table below sets forth the composition of net unevaluated costs
excluded from amortization as of December 31, 1995. Included in these costs is
$6.6 million representing leasehold and seismic costs related to the remaining
unevaluated portion of acreage located on the Fort Chaffee military reservation.
These costs are expected to be evaluated and subjected to amortization within
the next several years as this acreage is further explored and developed.
Included in exploration costs is $4.7 million of seismic costs related to the
Company's 50% interest in a joint venture seismic program in the Atchafalaya
Basin in Louisiana. These costs and subsequent costs to be incurred will be
evaluated over several years as the seismic data is interpreted and the acreage
is explored. The remaining costs excluded from
24
<PAGE>
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>
1995 1994 1993 Prior Total
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
Property acquisition costs $14,207 $3,667 $1,084 $6,595 $25,553
Exploration costs 17,322 3,202 1,204 347 22,075
Capitalized interest 2,379 535 255 540 3,709
- --------------------------------------------------------------------------------
$33,908 $7,404 $2,543 $7,482 $51,337
================================================================================
</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 1995, 1994, and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
- -----------------------------------------------------------------------------------------------------------
Gas Oil Gas Oil Gas Oil
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf) (MBbls)
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves, beginning of year 316,098 1,231 318,776 479 312,291 359
Revisions of previous estimates (25,970) (199) (16,551) (258) (4,110) (25)
Extensions, discoveries, and other additions 34,801 498 30,932 189 46,069 250
Production (34,515) (229) (37,706) (200) (35,693) (97)
Acquisition of reserves in place 4,462 851 20,647 1,038 222 --
Disposition of reserves in place -- -- -- (17) (3) (8)
- -----------------------------------------------------------------------------------------------------------
Proved reserves, end of year 294,876 2,152 316,098 1,231 318,776 479
===========================================================================================================
Proved, developed reserves:
Beginning of year 261,690 1,116 260,240 469 246,904 337
End of year 248,714 1,975 261,690 1,116 260,240 469
===========================================================================================================
</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, 1995, 1994, and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Future cash inflows $ 751,261 $ 683,438 $ 745,967
Future production and development costs (106,092) (96,813) (85,609)
Future income tax expense (229,064) (207,359) (236,170)
- ---------------------------------------------------------------------------------------------------------
Future net cash flows 416,105 379,266 424,188
10% annual discount for estimated
timing of cash flows (212,583) (189,774) (196,913)
- ---------------------------------------------------------------------------------------------------------
Standardized measure of discounted future net cash flows $ 203,522 $ 189,492 $ 227,275
=========================================================================================================
</TABLE>
Under the standardized measure, future cash inflows were estimated by
applying year-end prices, adjusted for known contractual changes, to the
estimated future production of year-end proved reserves. Future cash inflows
were reduced by estimated future production and development costs based on
year-end costs to determine pretax cash inflows. Future income taxes were
computed by applying the year-end statutory rate, after consideration of
permanent differences 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.
25
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
Following is an analysis of changes in the standardized measure during
1995, 1994, and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
- -----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Standardized measure, beginning of year $189,492 $227,275 $209,970
Sales and transfers of gas and oil produced, net of production costs (55,275) (73,352) (73,017)
Net changes in prices and production costs 39,928 (29,344) 22,392
Extensions, discoveries, and other additions, net of future production and development costs 49,471 43,458 74,511
Revisions of previous quantity estimates (29,851) (19,225) (5,217)
Accretion of discount 28,733 34,968 31,885
Net change in income taxes (9,073) 24,564 (13,524)
Changes in production rates (timing)and other (9,903) (18,852) (19,725)
- -----------------------------------------------------------------------------------------------------------------------------------
Standardized measure, end of year $203,522 $189,492 $227,275
===================================================================================================================================
</TABLE>
(7) INVESTMENT IN UNCONSOLIDATED PARTNERSHIP
The Company holds a general partnership interest in NOARK of 47.93% 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. The Company's investment in NOARK totaled $9.0 million at
December 31, 1995 and $4.8 million at December 31, 1994. The Company's
investment in NOARK includes advances of $5.0 million made during 1995 and $2.3
million during 1994, primarily to provide certain minimum cash balances to
service NOARK's long-term debt. 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, 1995 and 1994 is summarized
below:
<TABLE>
<CAPTION>
1995 1994
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Current assets $ 870 $ 1,078
Noncurrent assets 98,048 100,662
- --------------------------------------------------------------------------------
$98,918 $101,740
================================================================================
Current liabilities $ 6,624 $ 6,009
Long-term debt 76,700 86,250
Loans from general partners 11,505 3,225
Partners' capital 4,089 6,256
- --------------------------------------------------------------------------------
$98,918 $101,740
================================================================================
</TABLE>
The Company's share of NOARK's pretax loss, before the effect of accrued
interest expense on general partner loans, was $.7 million, $2.8 million, and
$1.8 million for 1995, 1994, and 1993, respectively. The Company records its
share of NOARK's pretax loss in other income (expense) on the statements of
income. The 1995 pretax loss included $2.9 million of income for the Company's
share of a $6.0 million settlement of contract issues with one of NOARK's
transporters.
NOARK's results of operations for 1995, 1994, and 1993 are summarized
below:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Operating revenues $11,657 $10,111 $ 8,301
Pretax loss $(2,167) $(5,917) $(3,778)
================================================================================
</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.
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.
26
<PAGE>
The estimated fair values of the Company's financial instruments as of
December 31, 1995 and 1994 were as follows:
<TABLE>
<CAPTION>
1995 1994
-------------------- ---------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C>
Cash $1,498 $1,498 $1,152 $1,152
Customer deposits $4,619 $4,619 $4,232 $4,232
Long-term debt $210,828 $216,364 $142,300 $144,245
================================================================================
</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.
(9) SEGMENT INFORMATION
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, 1995, 1994, and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
- --------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
REVENUES
Exploration and production $ 63,523 $ 80,123 $ 79,374
Gas distribution 119,855 127,060 131,892
Other 336 308 262
Eliminations (30,603) (37,305) (36,684)
- --------------------------------------------------------------------------------
$153,111 $170,186 $174,844
- --------------------------------------------------------------------------------
INTERSEGMENT REVENUES
Exploration and production $ 29,811 $ 36,465 $ 36,091
Gas distribution 536 584 337
Other 256 256 256
- --------------------------------------------------------------------------------
$ 30,603 $ 37,305 $ 36,684
- --------------------------------------------------------------------------------
OPERATING INCOME
Exploration and production $ 20,523 $ 38,888 $ 42,608
Gas distribution 11,133 13,386 15,261
Corporate expenses (468) (192) (305)
- --------------------------------------------------------------------------------
$ 31,188 $ 52,082 $ 57,564
- --------------------------------------------------------------------------------
IDENTIFIABLE ASSETS
Exploration and production $346,514 $288,175 $236,968
Gas distribution 183,410 171,471 186,704
Other 39,169 26,428 21,782
- --------------------------------------------------------------------------------
$569,093 $486,074 $445,454
- --------------------------------------------------------------------------------
DEPRECIATION, DEPLETION AND AMORTIZATION
Exploration and production $ 29,607 $ 29,738 $ 25,686
Gas distribution 5,338 4,981 4,564
Other 1,047 827 694
- --------------------------------------------------------------------------------
$ 35,992 $ 35,546 $ 30,944
- --------------------------------------------------------------------------------
CAPITAL ADDITIONS
Exploration and production $ 82,237 $ 55,449 $ 37,411
Gas distribution 18,523 17,577 19,892
Other 866 3,828 1,916
- --------------------------------------------------------------------------------
$101,626 $ 76,854 $ 59,219
================================================================================
</TABLE>
27
<PAGE>
Notes to Financial Statements continued
Southwestern Energy Company and Subsidiaries
(10) STOCK OPTIONS
The Southwestern Energy Company 1993 Stock Incentive Plan (1993 Plan)
provides for the compensation of officers and key employees of the Company and
its subsidiaries. The 1993 Plan provides for grants of options, shares of
restricted stock, and stock bonuses that in the aggregate do not exceed
1,275,000 shares, the grant of stand-alone stock appreciation rights (SARs),
shares of phantom stock, and cash awards, the shares related to which in the
aggregate do not exceed 1,275,000 shares, and the grant of limited and tandem
SARs (all terms as defined in the 1993 Plan). The types of incentives which may
be awarded are comprehensive and are intended to enable the Board of Directors
to structure the most appropriate incentives and to address changes in income
tax laws which may be enacted over the term of the plan.
At December 31, 1995, there were options for 1,024,108 shares outstanding
under the 1993 Plan at option prices ranging from $13 3/8 to $17 1/8,
representing the fair market value at the dates of grant. Of the total, 780,000
performance accelerated options were granted in 1994 at an option price of $14
5/8. These options vest over a four-year period beginning six years from the
date of grant or earlier if certain corporate performance criteria are achieved.
The remaining options, granted in 1993, 1994, and 1995, vest to employees over a
three-year period from the date of grant. Options for 28,774 shares were
exercisable at December 31, 1995. All options expire ten years from the date of
grant. Additionally, 38,965 shares of restricted stock have been granted to
employees during the period 1993 through 1995. Of this total, 6,855 shares
issued in 1995 vest over a three-year period and the remaining shares vest over
a five-year period. The related compensation expense is being amortized over the
vesting periods.
Under the Company's 1985 Nonqualified Stock Option Plan, there were options
for 427,050 shares and 84,900 SARs outstanding at December 31, 1995 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 Southwestern Energy Company 1993 Stock Incentive Plan for Outside
Directors provides for annual stock option grants of 12,000 shares (with 12,000
limited SARs) to each non-employee director. Options may be awarded under the
plan on no more than 240,000 shares. 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, 1995, there
were options for 99,000 shares outstanding at option prices ranging from $12 7/8
to $17 1/2. Options for 21,000 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. 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 combi-nation, 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, 1995, the Senior Secured Notes had a
remaining balance of $56.7 million and a remaining term of 14 years. At December
31, 1995, NOARK also had an unsecured long-term revolving credit agreement in
the amount of $30.0 million with a group of banks, of which $23.2 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 notes and the line
of credit is 60%. Additionally, the Company's gas distribution subsidiary has a
transportation contract with an original term of ten years with NOARK for firm
capacity of 41 MMcfd. The remaining term of that contract is seven years and is
renewable year-to-year until terminated by 180 days' notice.
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. In December, 1995, the parties
28
<PAGE>
to the lawsuit settled prior to going to trial. In exchange for a $6.0 million
payment to NOARK, the transporter was released from its obligations under its
firm transportation agreement. 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 continue to
investigate 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 has been advised of a potential claim against it involving the
disputed ownership of overriding royalty interests in a number of oil and gas
properties and related matters. The Company has begun discussions with the
claimant and has engaged special counsel to assist it in a preliminary
investigation of the claim's merits. The Company is unable to predict at this
time whether litigation will be commenced in respect of this claim or how the
claim will ultimately be resolved. While the amount of the potential claim is
significant in the aggregate, management believes, based on its preliminary
investigation, that the Company's ultimate liability, if any, will not be
material to its consolidated financial position or results of operations.
The Company is subject to laws and regulations relating to the protection
of the environment. The Company's policy is to accrue environmental and cleanup
related costs of a noncapital nature when it is both probable that a liability
has been incurred and when the amount can be reasonably estimated. Management
believes any future remediation or other compliance related costs will not have
a material effect on the financial condition or reported results of operations
of the Company.
The Company is subject to other litigation and claims that have arisen in
the ordinary course of business. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated. In the
opinion of management, the results of such litigation and claims will not have a
material effect on the results of operations or the financial position of the
Company.
(13) QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the
years ended December 31, 1995 and 1994:
<TABLE>
<CAPTION>
Quarter Ended March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C>
1995
----
Operating revenues $51,751 $30,642 $25,454 $45,264
Operating income $15,090 $ 3,927 $ 1,955 $10,216
Income (loss) before extraordinary item $ 7,102 $ 445 $(1,081) $ 5,069
Net income (loss) $ 7,102 $ 445 $(1,081) $ 4,774
Earnings (loss) per share before extraordinary item $.28 $.02 $(.04) $.20
Earnings (loss) per share $.28 $.02 $(.04) $.19
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
==========================================================================================================================
</TABLE>
29
<PAGE>
Financial and Operating Statistics
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
FINANCIAL REVIEW (in thousands)
Operating revenues:
Exploration and production $ 63,523 $ 80,123 $ 79,374 $ 60,554 $ 49,392 $ 41,489
Gas distribution 119,855 127,060 131,892 117,495 121,302 108,911
Other 336 308 262 256 256 256
Intersegment revenues (30,603) (37,305) (36,684) (34,475) (34,511) (33,586)
- ------------------------------------------------------------------------------------------------------------------------------
153,111 170,186 174,844 143,830 136,439 117,070
- ------------------------------------------------------------------------------------------------------------------------------
Operating costs and expenses:
Purchased gas costs 37,133 36,395 42,962 35,848 40,423 37,678
Operating and general 44,436 42,506 40,093 34,970 32,609 28,134
Depreciation, depletion and amortization 35,992 35,546 30,944 23,880 18,248 14,756
Taxes, other than income taxes 4,362 3,657 3,281 3,144 3,017 2,885
- ------------------------------------------------------------------------------------------------------------------------------
121,923 118,104 117,280 97,842 94,297 83,453
- ------------------------------------------------------------------------------------------------------------------------------
Operating income 31,188 52,082 57,564 45,988 42,142 33,617
Interest expense, net (11,167) (8,867) (9,025) (9,983) (9,813) (10,530)
Other income (expense) (1,227) (2,362) (1,657) (421) (107) (17)
- ------------------------------------------------------------------------------------------------------------------------------
Income before income taxes, extraordinary items and the
cumulative effect of accounting change 18,794 40,853 46,882 35,584 32,222 23,070
- ------------------------------------------------------------------------------------------------------------------------------
Income taxes:
Current (4,908) 9,288 13,704 7,403 7,158 4,994
Deferred 12,167 6,441 6,128 5,916 4,999 3,568
- ------------------------------------------------------------------------------------------------------------------------------
7,259 15,729 19,832 13,319 12,157 8,562
- ------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary item and cumulative effect of
accounting change 11,535 25,124 27,050 22,265 20,065 14,508
Extraordinary loss due to early retirement of debt
(net of $185 tax benefit) (295) -- -- -- -- --
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 $ 11,240 $ 25,124 $ 37,176 $ 22,265 $ 20,065 $ 14,075
==============================================================================================================================
Cash flow from operations (in thousands) $ 55,861 $ 66,613 $ 70,199 $ 49,730 $ 34,986 $ 36,495
Return on equity 5.78% 12.35% 14.66%/(1)/ 14.53% 14.75% 11.66%
Gross profit margin 20.37% 30.60% 32.92% 31.97% 30.89% 28.72%
Net profit margin 7.34% 14.76% 15.47%/(1)/ 15.48% 14.71% 12.02%
==============================================================================================================================
COMMON STOCK STATISTICS/(2)/
Earnings per share before extraordinary item and
cumulative effect of accounting change $.46 $.98 $1.05 $.87 $.78 $.57
Earnings per share $.45 $.98 $1.44 $.87 $.78 $.56
Cash dividends declared and paid per share $.24 $.24 $.22 $.20 $.19 $.19
Book value per share $7.87 $7.92 $7.18 $5.97 $5.30 $4.70
Market price at year-end $12.75 $14.88 $18.00 $12.96 $10.50 $10.42
Number of shareholders of record at year-end 2,759 2,875 3,005 2,930 2,989 3,136
Average shares outstanding 25,130,781 25,684,110 25,684,110 25,683,963 25,678,011 25,270,674
==============================================================================================================================
CAPITALIZATION (in thousands)
Long-term debt, including current portion $210,828 $142,300 $127,000 $143,335 $134,104 $125,535
Common shareholders' equity 194,504 203,456 184,530 153,233 136,041 120,709
- ------------------------------------------------------------------------------------------------------------------------------
Total capitalization $405,332 $345,756 $311,530 $296,568 $270,145 $246,244
- ------------------------------------------------------------------------------------------------------------------------------
Total assets $569,093 $486,074 $445,454 $427,175 $392,208 $366,313
- ------------------------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Debt (excluding current portion) 51.65% 40.10% 40.19% 48.31% 49.08% 50.39%
Equity 48.35% 59.90% 59.81% 51.69% 50.92% 49.61%
==============================================================================================================================
CAPITAL EXPENDITURES (in millions)
Exploration and production $82.2 $55.4 $37.4 $30.8 $30.3 $23.4
Gas distribution 18.5 17.6 19.9 12.2 7.9 9.3
Other .9 3.9 1.9 1.9 .7 .7
- ------------------------------------------------------------------------------------------------------------------------------
$101.6 $76.9 $59.2 $44.9 $38.9 $33.4
==============================================================================================================================
</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.
30
<PAGE>
<TABLE>
<CAPTION>
1995 1994 1993 1992 1991 1990
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas and Oil Wells Completed
Producers:
Gross 70.0 78.0 57.0 69.0 25.0 25.0
Net 43.8 50.2 40.7 54.6 11.8 9.1
Dry holes:
Gross 39.0 30.0 28.0 29.0 12.0 10.0
Net 26.5 16.5 14.5 19.5 4.1 2.1
- --------------------------------------------------------------------------------------------------------------------------------
Total:
Gross 109.0 108.0 85.0 98.0 37.0 35.0
Net 70.3 66.7 55.2 74.1 15.9 11.2
At the end of 1995, the Company was a participant in 17.0 (12.4 net) wells in process.
================================================================================================================================
Natural Gas and Oil Produced
Natural gas:
Production, Bcf 34.5 37.7 35.7 25.8 20.3 16.7
Average price per Mcf $1.72 $2.04 $2.18 $2.26 $2.25 $2.33
Oil:
Production, MBbls 229 200 97 120 176 112
Average price per barrel $17.15 $15.89 $17.20 $19.75 $20.67 $22.89
Average production (lifting) cost per Mcf equivalent $.22 $.17 $.18 $.16 $.19 $.16
Proved reserves at year-end:
Natural gas, Bcf 294.9 316.1 318.8 312.3 307.5 304.5
Oil, MBbls 2,152 1,231 479 359 505 773
================================================================================================================================
Utility Operating Data
Sales volumes, Bcf:
Residential 12.1 11.6 12.9 10.8 10.9 10.1
Commercial 7.6 7.2 7.8 6.6 6.7 6.3
Industrial 7.7 7.5 6.1 6.1 9.5 10.2
Transportation volumes, Bcf:
End-use 5.2 4.8 5.6 5.2 1.3 .1
Off-system 9.8 10.7 11.7 2.5 .2 .3
- --------------------------------------------------------------------------------------------------------------------------------
42.4 41.8 44.1 31.2 28.6 27.0
- --------------------------------------------------------------------------------------------------------------------------------
Average sales customers:
Residential 144,828 140,684 137,087 133,103 129,379 127,142
Commercial 19,502 18,872 18,511 18,141 17,880 17,680
Industrial 342 341 346 348 370 366
- --------------------------------------------------------------------------------------------------------------------------------
164,672 159,897 155,944 151,592 147,629 145,188
- --------------------------------------------------------------------------------------------------------------------------------
Sales and transportation revenues (in thousands):
Residential $ 59,523 $ 62,565 $ 67,502 $ 59,747 $ 58,372 $ 48,407
Commercial 31,018 32,252 35,311 31,425 30,718 27,535
Industrial 22,466 25,191 21,757 20,502 29,187 30,463
Transportation 4,964 4,721 5,177 3,597 857 179
- --------------------------------------------------------------------------------------------------------------------------------
$117,971 $124,729 $129,747 $115,271 $119,134 $106,584
- --------------------------------------------------------------------------------------------------------------------------------
Miles of pipe:
Gathering 434 405 398 383 375 371
Transmission 1,348 1,346 1,335 1,328 1,326 1,326
Distribution 4,451 4,246 4,160 4,090 4,002 3,931
- --------------------------------------------------------------------------------------------------------------------------------
6,233 5,997 5,893 5,801 5,703 5,628
- --------------------------------------------------------------------------------------------------------------------------------
Degree days 4,376 4,161 4,929 4,104 4,095 3,972
Percent of normal 99% 95% 113% 92% 93% 90%
================================================================================================================================
</TABLE>
31
<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 Monday, May
13, 1996, 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 1995 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
----------------------------- -------------------
1995 1994 1995 1994
- -----------------------------------------------------------------------------------------
High Low High Low
<S> <C> <C> <C> <C> <C> <C>
March 31 $15.13 $11.75 $18.88 $15.13 $.06 $.06
June 30 $15.50 $13.63 $17.75 $15.50 $.06 $.06
September 30 $14.25 $12.00 $17.88 $15.50 $.06 $.06
December 31 $14.25 $12.25 $17.75 $14.00 $.06 $.06
=========================================================================================
</TABLE>
Market prices represent transactions on the New York Stock Exchange.
32
<PAGE>
Southwestern Energy Company and Subsidiaries
APPENDIX to 1995 ANNUAL REPORT TO SHAREHOLDERS
Description of Exploration & Production Operating Areas:
Southwestern conducts its exploration and production efforts primarily in four
areas; the Arkoma Basin, the Anadarko Basin, the Gulf Coast, and the Delaware
Basin of New Mexico. 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. The
Delaware Basin is located in the southeast corner of New Mexico and extends to
the south into western Texas.
Description of Gas Distribution Operating Areas:
Arkansas Western Gas Company's (AWG) northwest Arkansas gas utility system
gathers its gas supply from the Arkoma Basin where it also provides distribution
service to communities in that area, including the towns of Ozark and
Clarksville. AWG's transmission and distribution lines extend north and supply
communities in the northwest part of the state, including the towns of
Fayetteville, Springdale, and Rogers. AWG's service area also extends east to
the Harrison and Mountain Home areas. This eastern section of the AWG system
receives a portion of its gas supply from a lateral line off of the NOARK
Pipeline System (NOARK) as discussed below. Through its division, Associated
Natural Gas Company (Associated), AWG provides distribution of natural gas to
communities in northeast Arkansas and parts of Missouri. Major communities
served in northeast Arkansas include Blytheville, Piggott, and Osceola. The
Associated distribution system also serves the "bootheel" area in southeast
Missouri, including the communities of Sikeston, New Madrid, and Caruthersville
and extends north to the Jackson area. In addition, Associated provides service
to Butler, Missouri, near the state's western border and Kirksville, Missouri,
near the state's northern border through connections off of interstate pipelines
in those areas.
Description of NOARK Pipeline System Operating Area:
Southwestern Energy Pipeline Company owns a 47.93% general partnership interest
in NOARK, a 258-mile intrastate pipeline that ties the Claimant's gathering and
transmission pipeline systems in northwest Arkansas to its distribution systems
in northeast Arkansas and southeast Missouri. NOARK starts near Forth Smith, at
the Fort Chaffee military reservation, and extends east through the Arkoma Basin
and across northern Arkansas. A lateral from NOARK extends north and connects to
AWG's distribution line in the Mountain Home area. NOARK crosses three
interstate pipelines in northeast Arkansas and ends at an interconnection with
Arkansas Western Pipeline Company's 8-mile interstate pipeline at the
Arkansas/Missouri border. This pipeline transports gas from NOARK to
Associated's distribution system.
<TABLE>
<CAPTION>
Operating Properties:
ACREAGE AND PRODUCING WELLS
Undeveloped Developed Wells
Gross Net Gross Net Gross Net
<S> <C> <C> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------
Arkansas 175,335 84,566 298,523 138,425 761 395.3
Louisiana 37,485 21,880 12,890 4,060 34 19.6
Oklahoma 21,799 15,601 51,551 27,494 471 245.5
Texas 31,517 15,416 48,687 11,887 39 8.2
New Mexico 17,200 8,967 1,000 161 5 1.6
Other areas 10,154 8,564 4,018 964 11 3.0
- -----------------------------------------------------------------------------------------------------------
293,490 154,994 416,669 182,991 1,321 673.2
===========================================================================================================
</TABLE>
<TABLE>
<CAPTION>
GAS DISTRIBUTION SYSTEMS MILES OF PIPE
AWG Associated Total
<S> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------------
Gathering 434 -- 434
Transmission 745 603 1,348
Distribution 2,867 1,584 4,451
- -----------------------------------------------------------------------------------------------------------
4,046 2,187 6,233
===========================================================================================================
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> DEC-31-1995
<CASH> 1,498
<SECURITIES> 0
<RECEIVABLES> 35,541
<ALLOWANCES> 0
<INVENTORY> 15,448
<CURRENT-ASSETS> 63,896
<PP&E> 763,570
<DEPRECIATION> 277,751
<TOTAL-ASSETS> 569,093
<CURRENT-LIABILITIES> 45,410
<BONDS> 207,757
0
0
<COMMON> 2,774
<OTHER-SE> 191,730
<TOTAL-LIABILITY-AND-EQUITY> 569,093
<SALES> 146,379
<TOTAL-REVENUES> 153,111
<CGS> 0
<TOTAL-COSTS> 121,923
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 11,167
<INCOME-PRETAX> 18,794
<INCOME-TAX> 7,259
<INCOME-CONTINUING> 11,535
<DISCONTINUED> 0
<EXTRAORDINARY> (295)
<CHANGES> 0
<NET-INCOME> 11,240
<EPS-PRIMARY> .45
<EPS-DILUTED> 0
</TABLE>
